10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2024

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

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ☐  No  ☒ 

As of August 2, 2024, the issuer had 226,273,139 shares of Common Stock outstanding.

CHENIERE ENERGY, INC.

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Statements of Operations	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Stockholders’ Equity (Deficit) and Redeemable Non-Controlling Interest	5
	Consolidated Statements of Cash Flows	7
	Notes to Consolidated Financial Statements	8
	Note 1—Nature of Operations and Basis of Presentation	8
	Note 2—Trade and Other Receivables, Net of Current Expected Credit Losses	9
	Note 3—Inventory	9
	Note 4—Property, Plant and Equipment, Net of Accumulated Depreciation	9
	Note 5—Derivative Instruments	10
	Note 6—Non-Controlling Interests and Variable Interest Entities	14
	Note 7—Accrued Liabilities	15
	Note 8—Debt	16
	Note 9—Leases	18
	Note 10—Revenues	19
	Note 11—Related Party Transactions	21
	Note 12—Income Taxes	21
	Note 13—Net Income per Share Attributable to Common Stockholders	22
	Note 14—Share Repurchase Programs	22
	Note 15—Customer Concentration	22
	Note 16—Supplemental Cash Flow Information	23
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	36
Part II. Other Information
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 5.	Other Information	37
Item 6.	Exhibits	38
	Signatures	39

i

DEFINITIONS

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

Common Industry and Other Terms

ASU	Accounting Standards Update
Bcf/d	billion cubic feet per day
Bcfe	billion cubic feet equivalent
CAMT	corporate alternative minimum tax
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
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
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

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of June 30, 2024, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

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

2

PART I.    FINANCIAL INFORMATION 

BES

ITEM 1.    CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Revenues
LNG revenues	$	3,042	$	3,919	$	7,079	$	11,010
Regasification revenues	34		33		68		67
Other revenues	175		150		357		335
Total revenues	3,251		4,102		7,504		11,412
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below)	784		912		3,020		(627)
Operating and maintenance expense	463		487		914		931
Selling, general and administrative expense	99		87		200		194
Depreciation and amortization expense	304		297		606		594
Other operating costs and expenses	13		11		22		21
Total operating costs and expenses	1,663		1,794		4,762		1,113
Income from operations	1,588		2,308		2,742		10,299
Other income (expense)
Interest expense, net of capitalized interest	(257)		(291)		(523)		(588)
Gain (loss) on modification or extinguishment of debt	(9)		(2)		(9)		18
Interest and dividend income	47		55		108		89
Other income, net	3		—		2		3
Total other expense	(216)		(238)		(422)		(478)
Income before income taxes and non-controlling interest	1,372		2,070		2,320		9,821
Less: income tax provision	210		363		319		1,679
Net income	1,162		1,707		2,001		8,142
Less: net income attributable to non-controlling interest	282		338		619		1,339
Net income attributable to Cheniere	$	880	$	1,369	$	1,382	$	6,803
Net income per share attributable to common stockholders—basic (1)	$	3.85	$	5.65	$	5.97	$	27.99
Net income per share attributable to common stockholders—diluted (1)	$	3.84	$	5.61	$	5.96	$	27.79
Weighted average number of common shares outstanding—basic	228.4		242.3		231.3		243.1
Weighted average number of common shares outstanding—diluted	228.9		243.8		231.9		244.8
___________________

(1)Earnings per share may not recalculate 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.

3

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (1)

(in millions, except share data)

	June 30,		December 31,
	2024		2023
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	2,442	$	4,066
Restricted cash and cash equivalents	512		459
Trade and other receivables, net of current expected credit losses	719		1,106
Inventory	387		445
Current derivative assets	38		141
Margin deposits	105		18
Other current assets, net	133		96
Total current assets	4,336		6,331
Property, plant and equipment, net of accumulated depreciation	33,079		32,456
Operating lease assets	2,845		2,641
Derivative assets	1,151		863
Deferred tax assets	26		26
Other non-current assets, net	841		759
Total assets	$	42,278	$	43,076
LIABILITIES, REDEEMABLE NON-CONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	124	$	181
Accrued liabilities	1,706		1,780
Current debt, net of unamortized debt issuance costs	798		300
Deferred revenue	125		179
Current operating lease liabilities	637		655
Current derivative liabilities	803		750
Other current liabilities	43		43
Total current liabilities	4,236		3,888
Long-term debt, net of unamortized discount and debt issuance costs	22,590		23,397
Operating lease liabilities	2,200		1,971
Finance lease liabilities	506		467
Derivative liabilities	2,153		2,378
Deferred tax liabilities	1,576		1,545
Other non-current liabilities	419		410
Total liabilities	33,680		34,056
Redeemable non-controlling interest	6		—
Stockholders’ equity
Preferred stock: $0.0001 par value, 5.0 million shares authorized, none issued	—		—
Common stock: $0.003 par value, 480.0 million shares authorized; 278.5 million shares and 277.9 million shares issued at June 30, 2024 and December 31, 2023, respectively	1		1
Treasury stock: 51.5 million shares and 40.9 million shares at June 30, 2024 and December 31, 2023, respectively, at cost	(5,568)		(3,864)
Additional paid-in-capital	4,406		4,377
Retained earnings	5,625		4,546
Total Cheniere stockholders’ equity	4,464		5,060
Non-controlling interest	4,128		3,960
Total stockholders’ equity	8,592		9,020
Total liabilities, redeemable non-controlling interest and stockholders’ equity	$	42,278	$	43,076

(1)Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP, as further discussed in Note 6—Non-Controlling Interests and Variable Interest Entities. As of June 30, 2024, total assets and liabilities of our VIEs were $17.4 billion and $18.2 billion, respectively, including $351 million of cash and cash equivalents and $79 million of restricted cash and cash equivalents.

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

4

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) AND REDEEMABLE NON-CONTROLLING INTEREST

(in millions)

(unaudited)

Three and Six Months Ended June 30, 2024
	Total Stockholders’ Equity
	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Non-controlling Interest		Total Equity		Redeemable Non-Controlling Interest (1)
	Shares	Par Value Amount		Shares	Amount
Balance at December 31, 2023	237.0	$	1	40.9	$	(3,864)	$	4,377	$	4,546	$	3,960	$	9,020	$	—
Vesting of share-based compensation awards	0.6	—		—	—		—		—		—		—		—
Share-based compensation	—	—		—	—		34		—		—		34		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(40)		—		—		(40)		—
Shares repurchased, at cost	(7.5)	—		7.5	(1,203)		—		—		—		(1,203)		—
Net income	—	—		—	—		—		502		337		839		—
Contributions from redeemable non-controlling interest	—	—		—	—		—		—		—		—		4
Distributions to non-controlling interest	—	—		—	—		—		—		(253)		(253)		—
Dividends declared ($0.435 per common share)	—	—		—	—		—		(103)		—		(103)		—
Balance at March 31, 2024	230.1	1		48.4	(5,067)		4,371		4,945		4,044		8,294		4
Share-based compensation	—	—		—	—		36		—		—		36		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(1)		—		—		(1)		—
Shares repurchased, at cost	(3.1)	—		3.1	(501)		—		—		—		(501)		—
Net income	—	—		—	—		—		880		282		1,162		—
Contributions from redeemable non-controlling interest	—	—		—	—		—		—		—		—		2
Distributions to non-controlling interest	—	—		—	—		—		—		(198)		(198)		—
Dividends declared ($0.435 per common share declared on April 26, 2024 and $0.435 per common share declared on June 17, 2024)	—	—		—	—		—		(200)		—		(200)		—
Balance at June 30, 2024	227.0	$	1	51.5	$	(5,568)	$	4,406	$	5,625	$	4,128	$	8,592	$	6

(1)Redeemable non-controlling interest represents the economic interest held by a third party in one of our consolidated VIEs that is redeemable for cash under certain circumstances, including those that are outside of our control. As such, the economic interest is not a component of permanent equity on our Consolidated Balance Sheets.

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

5

Three and Six Months Ended June 30, 2023
	Total Stockholders’ Equity (Deficit)
	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Non-controlling Interest		Total Equity (Deficit)		Redeemable Non-Controlling Interest
	Shares	Par Value Amount		Shares	Amount
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	1.0	—		—	—		—		—		—		—		—
Share-based compensation	—	—		—	—		43		—		—		43		—
Issued shares withheld from employees related to share-based compensation, at cost	(0.2)	—		0.2	(26)		(29)		—		—		(55)		—
Shares repurchased, at cost	(3.1)	—		3.1	(453)		—		—		—		(453)		—
Net income	—	—		—	—		—		5,434		1,001		6,435		—
Distributions to non-controlling interest	—	—		—	—		—		—		(261)		(261)		—
Dividends declared ($0.395 per common share)	—	—		—	—		—		(98)		—		(98)		—
Balance at March 31, 2023	243.2	1		34.5	(2,821)		4,328		394		3,538		5,440		—
Share-based compensation	—	—		—	—		36		—		—		36		—
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(1)		—		—		(1)		—
Shares repurchased, at cost	(2.3)	—		2.3	(341)		—		—		—		(341)		—
Net income	—	—		—	—		—		1,369		338		1,707		—
Distributions to non-controlling interest	—	—		—	—		—		—		(252)		(252)		—
Dividends declared ($0.395 per common share)	—	—		—	—		—		(97)		—		(97)		—
Balance at June 30, 2023	240.9	$	1	36.8	$	(3,162)	$	4,363	$	1,666	$	3,624	$	6,492	$	—

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

6

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Six Months Ended June 30,
	2024		2023
Cash flows from operating activities
Net income	$	2,001	$	8,142
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized foreign currency exchange loss (gain), net	3		(2)
Depreciation and amortization expense	606		594
Share-based compensation expense	92		85
Amortization of discount and debt issuance costs	19		23
Reduction of right-of-use assets	330		315
Loss (gain) on modification or extinguishment of debt	9		(18)
Total gains on derivative instruments, net	(393)		(5,411)
Net cash provided by (used for) settlement of derivative instruments	36		(102)
Deferred taxes	41		1,581
Other, net	8		6
Changes in operating assets and liabilities:
Trade and other receivables	387		1,249
Inventory	56		418
Margin deposits	(88)		98
Accounts payable and accrued liabilities	(324)		(1,551)
Total deferred revenue	(41)		(78)
Total operating lease liabilities	(324)		(305)
Other, net	(56)		(44)
Net cash provided by operating activities	2,362		5,000
Cash flows from investing activities
Property, plant and equipment, net	(1,153)		(1,044)
Investment in equity method investments	(12)		(18)
Other	(20)		(6)
Net cash used in investing activities	(1,185)		(1,068)
Cash flows from financing activities
Proceeds from issuances of debt	2,725		1,397
Redemptions, repayments and repurchases of debt	(3,021)		(1,098)
Distributions to non-controlling interest	(451)		(513)
Payments related to tax withholdings for share-based compensation	(41)		(56)
Repurchase of common stock	(1,699)		(774)
Dividends to stockholders	(202)		(195)
Other, net	(57)		(14)
Net cash used in financing activities	(2,746)		(1,253)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	(2)		3
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	(1,571)		2,682
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	4,525		2,487
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	2,954	$	5,169

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

7

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 large interstate and intrastate pipelines (the “Creole Trail Pipeline”). As of June 30, 2024, 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”) consisting of 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 large interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the existing assets 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 potential expansion projects. 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.

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 of Regulation S-X and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. Accordingly, these Consolidated Financial Statements do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

Results of operations for the three and six months ended June 30, 2024 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2024.

Recent Accounting Standards

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 a 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.

8

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 2—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):

	June 30,		December 31,
	2024		2023
Trade receivables
SPL and CCL	$	431	$	525
Cheniere Marketing	212		451
Other	4		4
Other receivables	72		126
Total trade and other receivables, net of current expected credit losses	$	719	$	1,106

NOTE 3—INVENTORY

Inventory consisted of the following (in millions):

	June 30,		December 31,
	2024		2023
Materials	$	213	$	207
LNG	75		88
LNG in-transit	73		112
Natural gas	24		35
Other	2		3
Total inventory	$	387	$	445

NOTE 4—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

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

	June 30,		December 31,
	2024		2023
Terminal and related assets
Terminal and interconnecting pipeline facilities	$	34,154	$	34,069
Land	464		463
Construction-in-process	4,555		3,480
Accumulated depreciation	(6,668)		(6,099)
Total terminal and related assets, net of accumulated depreciation	32,505		31,913
Fixed assets and other
Computer and office equipment	39		37
Furniture and fixtures	31		31
Computer software	128		125
Leasehold improvements	44		43
Other	22		21
Accumulated depreciation	(191)		(183)
Total fixed assets and other, net of accumulated depreciation	73		74
Assets under finance leases
Marine assets	583		532
Accumulated depreciation	(82)		(63)
Total assets under finance leases, net of accumulated depreciation	501		469
Property, plant and equipment, net of accumulated depreciation	$	33,079	$	32,456

Depreciation expense was $303 million and $295 million during the three months ended June 30, 2024 and 2023, respectively, and $603 million and $591 million during the six months ended June 30, 2024 and 2023, respectively.

9

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 5—DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments:

•commodity derivatives consisting of the following (collectively, “Commodity Derivatives”):

◦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”); and,

◦LNG derivatives in which we have contractual net settlement and economic hedges on the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”); 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 that are required to be measured at fair value on a recurring basis, distinguished by the fair value hierarchy levels prescribed by GAAP (in millions):

	Fair Value Measurements as of
	June 30, 2024								December 31, 2023
	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)	$	(24)	$	—	$	(1,729)	$	(1,753)	$	25	$	36	$	(2,178)	$	(2,117)
LNG Trading Derivatives asset (liability)	(11)		(6)		—		(17)		30		(20)		—		10
FX Derivatives asset (liability)	—		3		—		3		—		(17)		—		(17)

We value the 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 the 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

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

The Level 3 fair value measurements of our natural gas positions within the 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 the Level 3 Liquefaction Supply Derivatives as of June 30, 2024:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(1,729)	Market approach incorporating present value techniques	Henry Hub basis spread	$(2.063) - $0.445 / $(0.107)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	23% - 394% / 175%

(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 the Liquefaction Supply Derivatives.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Balance, beginning of period	$	(2,457)	$	(5,426)	$	(2,178)	$	(9,924)
Realized and change in fair value gains included in net income (1):
Included in cost of sales, existing deals (2)	617		635		164		4,518
Included in cost of sales, new deals (3)	7		3		5		9
Purchases and settlements:
Purchases (4)	—		—		—		—
Settlements (5)	104		175		280		780
Transfers out of level 3 (6)	—		2		—		6
Balance, end of period	$	(1,729)	$	(4,611)	$	(1,729)	$	(4,611)
Favorable changes in fair value relating to instruments still held at the end of the period	$	624	$	638	$	169	$	4,527

(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the 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.

(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.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

Commodity Derivatives

We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of June 30, 2024, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence or accelerate upon the satisfaction of certain events or development of infrastructure to support natural gas gathering and transport.

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 Commodity Derivatives:

	June 30, 2024		December 31, 2023
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,520	—	14,019	49

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both June 30, 2024 and 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)	Three Months Ended June 30,				Six Months Ended June 30,
		2024		2023		2024		2023
LNG Trading Derivatives	LNG revenues	$	1	$	(46)	$	17	$	15
LNG Trading Derivatives	Recovery (cost) of sales	(1)		(3)		(20)		(87)
Liquefaction Supply Derivatives (2)	LNG revenues	2		(1)		2		(6)
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales	647		826		379		5,497

(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 the 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 $214 million and $789 million as of June 30, 2024 and December 31, 2023, respectively.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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	Three Months Ended June 30,				Six Months Ended June 30,
		2024		2023		2024		2023
FX Derivatives	LNG revenues	$	2	$	(6)	$	15	$	(8)

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

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.

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

	June 30, 2024
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	33	$	2	$	3	$	38
Derivative assets	1,151		—		—		1,151
Total derivative assets	1,184		2		3		1,189
Current derivative liabilities	(784)		(19)		—		(803)
Derivative liabilities	(2,153)		—		—		(2,153)
Total derivative liabilities	(2,937)		(19)		—		(2,956)
Derivative asset (liability), net	$	(1,753)	$	(17)	$	3	$	(1,767)
	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)

(1)Does not include collateral posted with counterparties by us of $49 million and $3 million as of June 30, 2024 and December 31, 2023, respectively, which is included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of zero and $4 million as of June 30, 2024 and December 31, 2023, respectively, which is included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $56 million and $15 million, as of June 30, 2024 and December 31, 2023, respectively, which is included in margin deposits on our Consolidated Balance Sheets, and

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

collateral posted by counterparties to us of zero and $3 million as of June 30, 2024 and December 31, 2023, respectively, which is 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 June 30, 2024
Gross assets	$	1,536	$	20	$	4
Offsetting amounts	(352)		(18)		(1)
Net assets (1)	$	1,184	$	2	$	3
Gross liabilities	$	(3,064)	$	(33)	$	—
Offsetting amounts	127		14		—
Net liabilities (2)	$	(2,937)	$	(19)	$	—
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)

(1)Includes current and non-current derivative assets of $38 million and $1,151 million, respectively, as of June 30, 2024 and $141 million and $863 million, respectively, as of December 31, 2023.

(2)Includes current and non-current derivative liabilities of $803 million and $2,153 million, respectively, as of June 30, 2024 and $750 million and $2,378 million, respectively, as of December 31, 2023.

NOTE 6—NON-CONTROLLING INTERESTS AND VARIABLE INTEREST ENTITIES

When we consolidate our VIEs, we include 100% of the assets, liabilities, revenues and expenses of the VIE in our Consolidated Financial Statements; however, when our ownership is less than 100%, we record a non-controlling interest as a component of equity or redeemable non-controlling interest 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 interests is reported as net income attributable to non-controlling interest on our Consolidated Statements of Operations.

Substantially all of our consolidated VIEs’ assets and liabilities relate to CQP. We own a 48.6% limited partner interest in CQP, and we also own all of the 2% general partner interest and 100% of the incentive distribution rights in CQP. The remaining 49.4% non-controlling limited partner interest in CQP is held by affiliates of Blackstone Inc. and Brookfield Asset Management, Inc. (“Brookfield”) as well as the public.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	June 30,		December 31,
	2024		2023
ASSETS
Current assets
Cash and cash equivalents	$	351	$	575
Restricted cash and cash equivalents	79		56
Trade and other receivables, net of current expected credit losses	291		373
Other current assets, net	260		215
Total current assets	981		1,219
Property, plant and equipment, net of accumulated depreciation	16,108		16,212
Other non-current assets, net	298		309
Total assets	$	17,387	$	17,740
LIABILITIES
Current liabilities
Accrued liabilities	$	684	$	811
Current debt, net of discount and debt issuance costs	798		300
Current derivative liabilities	235		196
Other current liabilities	138		201
Total current liabilities	1,855		1,508
Long-term debt, net of unamortized discount and debt issuance costs	14,803		15,606
Derivative liabilities	1,319		1,531
Other non-current liabilities	249		160
Total liabilities	$	18,226	$	18,805

NOTE 7—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	June 30,		December 31,
	2024		2023
Natural gas purchases	$	552	$	729
Interest costs and related debt fees	362		399
Terminal and related asset costs	271		235
Tax-related liabilities	190		68
Compensation and benefits	152		266
Accrued dividends	101		3
LNG purchases	48		23
Other accrued liabilities	30		57
Total accrued liabilities	$	1,706	$	1,780

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—DEBT

Debt consisted of the following (in millions): 

	June 30,		December 31,
	2024		2023
SPL:
Senior Secured Notes:
5.750% due 2024	$	—	$	300
5.625% due 2025	800		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	8,932		10,432
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	8,932		10,432
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	1,400		1,400
5.750% due 2034	1,200		—
Total CQP Senior Notes	6,800		5,600
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	6,800		5,600
CCH:
Senior Secured Notes:
5.875% due 2025	—		1,491
5.125% due 2027	1,201		1,201
3.700% due 2029	1,125		1,125
3.788% weighted average rate due 2039	2,539		2,539
Total CCH Senior Secured Notes	4,865		6,356
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”)	—		—
Total debt - CCH	4,865		6,356
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
5.650% Senior Notes due 2034	1,500		—
Total Cheniere Senior Notes	3,000		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	3,000		1,500
Total debt	23,597		23,888
Current debt, net of unamortized debt issuance costs	(798)		(300)
Unamortized discount and debt issuance costs	(209)		(191)
Total long-term debt, net of unamortized discount and debt issuance costs	$	22,590	$	23,397

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of June 30, 2024 (in millions):

	SPL Revolving Credit Facility		CQP Revolving Credit Facility		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	238		—		—		110		—
Available commitment	$	762	$	1,000	$	3,260	$	1,390	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (1)	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 (1)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365%
Maturity date	June 23, 2028		June 23, 2028		(2)		June 15, 2027		October 28, 2026

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

(2)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.

In addition, as of June 30, 2024, Cheniere Marketing had trade finance facilities with no outstanding borrowings and $65 million in standby letters of credit and bank guarantees issued.

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.

As of June 30, 2024, 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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Total interest cost	$	309	$	319	$	620	$	640
Capitalized interest	(52)		(28)		(97)		(52)
Total interest expense, net of capitalized interest	$	257	$	291	$	523	$	588

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

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

	June 30, 2024				December 31, 2023
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,597	$	22,569	$	23,888	$	23,062

(1)As of both June 30, 2024 and December 31, 2023, $3.0 billion of the fair value of our senior notes was 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 the fair value 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 9—LEASES

We are the lessee of LNG vessels leased under time charters (“vessel charters”) as well as tug vessels, office space and facilities, land sites and other equipment. All of our leases where we are the lessee are classified as operating leases except for certain of our vessel charters, tug vessels and other equipment, which are classified as finance leases.

Future annual minimum lease payments for operating and finance leases as of June 30, 2024 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2024	$	409	$	35
2025	671		72
2026	538		75
2027	441		77
2028	287		73
Thereafter	932		355
Total lease payments (1)	3,278		687
Less: Interest	(441)		(140)
Present value of lease liabilities	$	2,837	$	547

(1)Does not include approximately $3.3 billion of legally binding minimum payments for leases executed as of June 30, 2024 that will commence in future periods, consisting primarily of vessel charters, 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:

	June 30, 2024		December 31, 2023
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.8	9.3	6.3	9.7
Weighted-average discount rate (1)	5.0%	7.5%	4.7%	7.7%

(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.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Six Months Ended June 30,
	2024		2023
Right-of-use assets obtained in exchange for operating lease liabilities (1)	$	568	$	177
Right-of-use assets obtained in exchange for finance lease liabilities (2)	74		5

(1)Includes $15 million reclassified from finance leases to operating leases during the six months ended June 30, 2024, as a result of modifications of the underlying tug vessel leases.

(2)Includes $33 million reclassified from operating leases to finance leases during the six months ended June 30, 2024, as a result of modifications of the underlying tug vessel leases.

LNG Vessel Subleases

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Fixed income	$	67	$	97	$	165	$	231
Variable income	12		13		18		36
Total sublease income	$	79	$	110	$	183	$	267

Future annual minimum sublease payments to be received from LNG vessel subleases as of June 30, 2024 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2024	$	78
2025	13
Total sublease payments	$	91

NOTE 10—REVENUES

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)	$	3,037	$	3,972	$	7,045	$	11,009
Regasification revenues	34		33		68		67
Other revenues (1)	76		42		151		70
Total revenues from contracts with customers	3,147		4,047		7,264		11,146
Net derivative gain (loss) (see Note 5)	5		(53)		34		1
Sublease income (see Note 9)	79		110		183		267
Other revenues	20		(2)		23		(2)
Total revenues	$	3,251	$	4,102	$	7,504	$	11,412

(1)Includes revenues from LNG vessel subcharters that do not qualify as leases for accounting purposes.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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):

	June 30,		December 31,
	2024		2023
Contract assets, net of current expected credit losses	$	298	$	250

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

	Six Months Ended June 30, 2024
Deferred revenue, beginning of period	$	294
Cash received but not yet recognized in revenue	128
Revenue recognized from prior period deferral	(154)
Deferred revenue, end of period	$	268

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:

	June 30, 2024			December 31, 2023
	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)	$	107.8	9	$	111.0	9
Regasification revenues	0.6		3	0.7		3
Total revenues	$	108.4		$	111.7

(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 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.

The following potential future sources of revenue are omitted from the table above under exemptions we have elected: (1) all performance obligations that are part of a contract that has an original expected duration of one year or less and (2) substantially all variable consideration under our SPAs and TUAs as well as 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 are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.

20

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
LNG revenues	50	%	64	%	56	%	73	%
Regasification revenues	8	%	7	%	8	%	7	%

NOTE 11—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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (1)	$	2	$	2	$	4	$	5
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	3		2		5		4
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (2)	16		14		29		30

(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.

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):

	June 30,		December 31,
	2024		2023
Trade and other receivables, net of current expected credit losses	$	2	$	3
Accrued liabilities	5		6

NOTE 12—INCOME TAXES

We recorded an income tax provision of $210 million and $319 million during the three and six months ended June 30, 2024, respectively, and an income tax provision of $363 million and $1.7 billion for the same periods of 2023, respectively, which was calculated using the annual effective tax rate method.

Our effective tax rate was 15.3% and 13.8% for the three and six months ended June 30, 2024, respectively, as compared to 17.5% and 17.1% for the same periods of 2023, respectively. The effective tax rate for the periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is not taxable to us.

21

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—NET INCOME 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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Net income attributable to Cheniere	$	880	$	1,369	$	1,382	$	6,803
Weighted average common shares outstanding:
Basic	228.4		242.3		231.3		243.1
Dilutive unvested stock	0.5		1.5		0.6		1.7
Diluted	228.9		243.8		231.9		244.8
Net income per share attributable to common stockholders—basic (1)	$	3.85	$	5.65	$	5.97	$	27.99
Net income per share attributable to common stockholders—diluted (1)	$	3.84	$	5.61	$	5.96	$	27.79

(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 June 17, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on August 16, 2024 to stockholders of record as of the close of business on August 9, 2024.

NOTE 14—SHARE REPURCHASE PROGRAMS

The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Total shares repurchased	3.14		2.30		10.66		5.36
Weighted average price paid per share	$	158.00	$	146.56	$	158.31	$	146.90
Total cost of repurchases (1)	$	496	$	337	$	1,688	$	788

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

As of June 30, 2024, we had approximately $4.5 billion remaining under our share repurchase program, subsequent to authorization by our Board of Directors to increase our previous authorization by $4.0 billion on June 14, 2024. Our share repurchase program authorization is effective through December 31, 2027.

NOTE 15—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
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2024	2023	2024	2023	2024	2023
Customer A	*	*	*	*	19%	13%
Customer B	11%	*	11%	*	*	*

* Less than 10%

22

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended June 30,
	2024		2023
Cash paid during the period for interest on debt, net of amounts capitalized	$	499	$	685
Cash paid for income taxes, net	21		54
Non-cash investing activity (1):
Unpaid purchases of property, plant and equipment, net	229		53
Non-cash financing activity (1):
Unpaid excise taxes on repurchase of common stock	15		6
Unpaid repurchase on common stock	—		13
Unpaid dividends on common stock	99		2

(1)Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.

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ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (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 relating to our goals, commitments and strategies in relation to environmental matters;

•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;

•statements regarding our anticipated LNG and natural gas marketing activities; and

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

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that

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the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2023. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction

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

Our discussion and analysis includes the following subjects: 

•Overview

•Overview of Significant Events

•Results of Operations

•Liquidity and Capital Resources

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Overview

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

LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, converted back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking, 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 we are the second largest LNG operator globally, based on the total production capacity of our liquefaction facilities, which totaled approximately 45 mtpa as of June 30, 2024.

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 June 30, 2024, 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

25

up to 200,000 cubic meters. We also own and operate a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”).

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 currently 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”) consisting of seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. We also own and operate a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the existing assets 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 a gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is 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 June 30, 2024, 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, we are developing an expansion adjacent to the SPL Project with a total production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”). In February 2024, certain subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking. 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.

Additionally, we are committed to the management of our most important ESG impacts, risks and opportunities. 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 cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Quarterly Report on Form 10-Q.

Overview of Significant Events

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

Strategic

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

26

Marketing on a free-on-board basis. Deliveries are expected to commence in the early 2030s and are subject to, among other things, a positive Final Investment Decision with respect to the second train of the SPL Expansion Project.

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

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

Operational

•As of August 2, 2024, approximately 3,570 cumulative LNG cargoes totaling over 245 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

Financial

•In June 2024, we announced updates to our ‘20/20 Vision’ comprehensive long-term capital allocation plan, which included an increase to our share repurchase authorization by $4 billion through 2027 and, subject to declaration by our Board of Directors, an increase to our quarterly dividend by approximately 15% to $2.00 per common share annualized, commencing with the third quarter of 2024.

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

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

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

•During the three and six months ended June 30, 2024, we accomplished the following pursuant to our capital allocation priorities:

◦We repurchased over 3.1 million and approximately 10.7 million shares of our common stock, respectively, as part of our share repurchase program for approximately $496 million and $1.7 billion, respectively.

◦SPL repaid $150 million and $300 million, respectively, of outstanding aggregate principal amount of its 5.750% Senior Secured Notes due 2024.

◦We paid dividends of $0.435 and $0.870 per share, respectively, of common stock.

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

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Results of Operations

Consolidated results of operations

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except per share data)	2024		2023		Variance		2024		2023		Variance
Revenues
LNG revenues	$	3,042	$	3,919	$	(877)	$	7,079	$	11,010	$	(3,931)
Regasification revenues	34		33		1		68		67		1
Other revenues	175		150		25		357		335		22
Total revenues	3,251		4,102		(851)		7,504		11,412		(3,908)
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below)	784		912		(128)		3,020		(627)		3,647
Operating and maintenance expense	463		487		(24)		914		931		(17)
Selling, general and administrative expense	99		87		12		200		194		6
Depreciation and amortization expense	304		297		7		606		594		12
Other operating costs and expenses	13		11		2		22		21		1
Total operating costs and expenses	1,663		1,794		(131)		4,762		1,113		3,649
Income from operations	1,588		2,308		(720)		2,742		10,299		(7,557)
Other income (expense)
Interest expense, net of capitalized interest	(257)		(291)		34		(523)		(588)		65
Gain (loss) on modification or extinguishment of debt	(9)		(2)		(7)		(9)		18		(27)
Interest and dividend income	47		55		(8)		108		89		19
Other income, net	3		—		3		2		3		(1)
Total other expense	(216)		(238)		22		(422)		(478)		56
Income before income taxes and non-controlling interest	1,372		2,070		(698)		2,320		9,821		(7,501)
Less: income tax provision	210		363		(153)		319		1,679		(1,360)
Net income	1,162		1,707		(545)		2,001		8,142		(6,141)
Less: net income attributable to non-controlling interest	282		338		(56)		619		1,339		(720)
Net income attributable to Cheniere	$	880	$	1,369	$	(489)	$	1,382	$	6,803	$	(5,421)
Net income per share attributable to common stockholders—basic	$	3.85	$	5.65	$	(1.80)	$	5.97	$	27.99	$	(22.02)
Net income per share attributable to common stockholders—diluted	$	3.84	$	5.61	$	(1.77)	$	5.96	$	27.79	$	(21.83)

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Volumes loaded and recognized from the Liquefaction Projects

	Three Months Ended June 30,			Six Months Ended June 30,
(in TBtu)	2024	2023	Variance	2024	2023	Variance
Volumes loaded during the current period	552	534	18	1,153	1,136	17
Volumes loaded during the prior period but recognized during the current period	30	39	(9)	37	56	(19)
Less: volumes loaded during the current period and in transit at the end of the period	(30)	(26)	(4)	(30)	(26)	(4)
Total volumes recognized in the current period	552	547	5	1,160	1,166	(6)

Components of LNG revenues and corresponding LNG volumes delivered

	Three Months Ended June 30,						Six Months Ended June 30,
	2024		2023		Variance		2024		2023		Variance
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	$	2,755	$	2,752	$	3	$	5,798	$	6,492	$	(694)
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	229		1,037		(808)		1,022		4,281		(3,259)
LNG procured from third parties	—		132		(132)		119		132		(13)
Net derivative gain (loss)	5		(53)		58		35		1		34
Other revenues	53		51		2		105		104		1
Total LNG revenues	$	3,042	$	3,919	$	(877)	$	7,079	$	11,010	$	(3,931)
Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	524		495		29		1,062		1,006		56
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	28		52		(24)		98		160		(62)
LNG procured from third parties	—		14		(14)		11		14		(3)
Total volumes delivered as LNG revenues	552		561		(9)		1,171		1,180		(9)

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

Net income attributable to Cheniere

Net income attributable to Cheniere declined $489 million and $5.4 billion for the three and six months ended June 30, 2024, respectively, as compared to the same periods of 2023. There was a $630 million and $2.6 billion decrease in LNG revenues, net of cost of sales and excluding the effect of derivatives, for the three and six months ended June 30, 2024, respectively, as compared to the same periods of 2023, the majority of which was attributable to declining international LNG and gas prices and a reduction of volumes sold under short-term agreements as a higher proportion of our LNG was sold under long-term contracts, as further described in Revenues below. The decline between the six month periods was primarily attributable to unfavorable changes in fair value and settlements of derivatives of $5.0 billion (before tax and the impact of non-controlling interest), principally attributable to our IPM agreements, where the associated gains decreased from $4.6 billion during the six months ended June 30, 2023 to $582 million during the six months ended June 30, 2024, mainly due to the impact on fair value of moderating changes in volatility in international gas prices in the current period relative to the same period of 2023. These unfavorable variances were partially offset by:

•$153 million and $1.4 billion favorable variances in income tax provision between the three and six months ended June 30, 2024, respectively, as compared to the same periods of 2023, primarily due to lower taxable earnings; and

•$56 million and $720 million reduction in net income attributable to non-controlling interest between the three and six months ended June 30, 2024, respectively, as compared to the same periods of 2023, substantially all of which is due to a decrease in CQP’s consolidated net income between the comparable periods from decreased revenues, net

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of cost of sales, between the three month periods and from declining gains from changes in fair value and settlements of derivatives between the six month 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 decreases of $851 million and $3.9 billion between the three and six months ended June 30, 2024, respectively, as compared to the same periods of 2023 were primarily attributable to:

•$940 million and $3.3 billion decreases in revenues generated by our marketing function under short-term agreements between the three and six month periods, respectively, due to declining international LNG and gas prices and a reduction of volumes sold under short-term agreements as a result of additional long-term agreements commencing after the second quarter of 2023; and

•$694 million decrease in revenues attributable to declining Henry Hub pricing between the six month periods, to which the majority of our long-term LNG sales contracts are indexed. Although there was a decrease in revenue from Henry Hub pricing between the three month periods, it was mostly offset by the increase in volume from the higher proportion of our volumes sold under long-term agreements.

Operating costs and expenses (recoveries)

There was a $131 million favorable variance between the three months ended June 30, 2024 and 2023 primarily as a result of a $307 million decrease in cost of natural gas feedstock largely due to lower U.S. natural gas prices, partially offset by a $176 million unfavorable variance from changes in fair value and settlements of derivatives included in cost of sales.

There was a $3.6 billion unfavorable variance between the six months ended June 30, 2024 and 2023 primarily attributable to a $5.1 billion unfavorable variance from changes in fair value and settlements of derivatives included in cost of sales. $4.0 billion of such unfavorable variance resulted from the moderating volatility in international gas prices during the current period, resulting in decreased non-cash gain in fair value of our IPM agreements indexed to such prices during the six month periods, as described above under the caption Net income attributable to Cheniere, and the remainder of the variance resulted from decreased gains from changes in fair value and settlements of the derivatives associated with other term supply natural gas and power supply contracts. This unfavorable variance was partially offset by a $1.4 billion decrease between the periods in cost of sales excluding the effect of derivative changes described above, primarily as a result of a $1.3 billion decrease in cost of natural gas feedstock largely due to lower U.S. natural gas prices.

Other income (expense)

The $22 million and $56 million favorable variances between the three and six months ended June 30, 2024, respectively, as compared to the same periods of 2023 were primarily attributable to:

•$34 million and $65 million decreases in interest expense, net of capitalized interest, between the three and six month periods, respectively, primarily due to increases in the extent of interest costs qualifying for capitalization, given the higher carrying value of assets under construction, and additionally due to lower overall interest cost due to debt reduction activities associated with our long-term capital allocation plan.

•$7 million and $27 million increases in loss on modification or extinguishment of debt between the three and six month periods, respectively, from debt reduction activities, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

•$8 million decrease in interest and dividend income between the three month periods as a result of lower average cash and cash equivalents balances between the respective periods, partially offset by higher interest rates in 2024, and a $19 million increase in interest and dividend income between the six month periods as a result of higher interest income earned on cash and cash equivalents from higher interest rates in 2024.

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Income tax provision

The $153 million and $1.4 billion favorable variances between the three and six months ended June 30, 2024, respectively, as compared to the same periods of 2023, were primarily attributable to decreases in pre-tax income.

We recorded an income tax provision of $210 million and $319 million during the three and six months ended June 30, 2024, respectively, and an income tax provision of $363 million and $1.7 billion for the same periods of 2023, respectively, which was calculated using the annual effective tax rate method.

Our effective tax rate was 15.3% and 13.8% for the three and six months ended June 30, 2024, respectively, as compared to 17.5% and 17.1% for the same periods of 2023, respectively. The effective tax rate for the periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is not taxable to us. Our effective tax rate decreased between both comparable periods because a larger percentage of pre-tax income was attributable to CQP’s income that is not taxable to us.

Net income attributable to non-controlling interests

The $56 million and $720 million decreases between the three and six months ended June 30, 2024, respectively, as compared to the same periods of 2023 were attributable to a $52 million decrease in CQP’s consolidated net income between the three month periods primarily from decreased revenues, net of cost of sales, and a $1.3 billion decrease in CQP’s consolidated net income between the six month periods primarily from unfavorable changes in fair value and settlements of derivatives, of which $1.0 billion was related to the IPM agreement with Tourmaline Oil Marketing Corp.

Significant factor affecting our results of operations

Below is a significant factor that affects 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 5—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

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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.

	June 30, 2024
Cash and cash equivalents (1)	$	2,442
Restricted cash and cash equivalents (1)	512
Available commitments under our credit facilities (2):
SPL Revolving Credit Facility	762
CQP Revolving Credit Facility	1,000
CCH Credit Facility	3,260
CCH Working Capital Facility	1,390
Cheniere Revolving Credit Facility	1,250
Total available commitments under our credit facilities	7,662
Total available liquidity	$	10,616

(1)Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), as discussed in Note 6—Non-controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements. As of June 30, 2024, assets of our VIEs, which are included in our Consolidated Balance Sheets, included $351 million of cash and cash equivalents and $79 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 June 30, 2024. See Note 8—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to June 30, 2024 will be driven by future sources of liquidity and future cash requirements. For a discussion of our future sources and uses of liquidity, see the liquidity and capital resources disclosures in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

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

•SPL and CCH are required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. In addition, SPL and CCH’s operating costs are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective affiliates, however the cash remains restricted for operation and construction of the Liquefaction Projects;

•CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner. Beginning with the distribution paid in the second quarter of 2022, quarterly distributions by CQP are currently comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business;

•Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and

•SPL and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied.

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

Corpus Christi Stage 3 Project

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of June 30, 2024:

Overall project completion percentage	62.4%
Completion percentage of:
Engineering	93.7%
Procurement	80.3%
Subcontract work	83.9%
Construction	24.4%
Date of expected substantial completion	1H 2025 - 2H 2026

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. 

	Six Months Ended June 30,
	2024		2023
Net cash provided by operating activities	$	2,362	$	5,000
Net cash used in investing activities	(1,185)		(1,068)
Net cash used in financing activities	(2,746)		(1,253)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	(2)		3
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	$	(1,571)	$	2,682

Operating Cash Flows

The $2.6 billion decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes due to a reduction in both pricing per MMBtu and volumes sold under short-term agreements, although this exposed us less to declining international LNG and gas prices in the current year as a higher proportion of our LNG was sold under long-term agreements. The decrease was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.

We became subject to the 15% CAMT beginning in 2024. Accordingly, our U.S. federal income tax obligations are expected to accelerate relative to prior periods, subject to and conditioned on variability in our pre-tax GAAP income, including period-to-period volatility attributable to changes in the fair value of our derivative instruments. As any accelerated CAMT tax liability provides an offsetting credit against our regular U.S. federal income tax liability for future years, we expect that any future impact will be limited to timing differences. Please refer to our annual report on Form 10-K for the fiscal year ended December 31, 2023 for additional discussion of the potential impacts of CAMT on our future liquidity.

Investing Cash Flows

Our investing net cash outflows in both periods primarily were for the construction costs for the Corpus Christi Stage 3 Project, which were $909 million during the six months ended June 30, 2024 compared to $729 million in the comparable period of 2023. We expect to incur a similar level of capital expenditures in the second half of the year as construction work progresses on the Corpus Christi Stage 3 Project.

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Financing Cash Flows

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

	Six Months Ended June 30,
	2024		2023
Proceeds from issuances of debt	$	2,725	$	1,397
Redemptions, repayments and repurchases of debt	(3,021)		(1,098)
Distributions to non-controlling interest	(451)		(513)
Payments related to tax withholdings for share-based compensation	(41)		(56)
Repurchase of common stock	(1,699)		(774)
Dividends to stockholders	(202)		(195)
Other, net	(57)		(14)
Net cash used in financing activities	$	(2,746)	$	(1,253)

Debt Issuances

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

	Six Months Ended June 30,
	2024		2023
Proceeds from issuances of debt
Cheniere:
2034 Cheniere Senior Notes	$	1,497	$	—
CQP:
2034 CQP Senior Notes	1,198		—
5.950% Senior Notes due 2033	—		1,397
SPL:
SPL Revolving Credit Facility	30		—
Total proceeds from issuances of debt	$	2,725	$	1,397

Debt Redemptions, Repayments and Repurchases

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

	Six Months Ended June 30,
	2024		2023
Redemptions, repayments and repurchases of debt
SPL:
5.750% Senior Secured Notes due 2024	$	(300)	$	(200)
5.625% Senior Secured Notes due 2025	(1,200)		—
SPL Revolving Capital Facility	(30)		—
CCH:
7.000% Senior Notes due 2024	—		(498)
5.625% Senior Notes due 2025	(1,491)		—
5.125% Senior Notes due 2027	—		(69)
3.700% Senior Notes due 2029	—		(237)
2.742% Senior Notes due 2039	—		(94)
Total redemptions, repayments and repurchases of debt	$	(3,021)	$	(1,098)

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Repurchase of Common Stock

During the six months ended June 30, 2024 and 2023, we paid $1.7 billion and $774 million to repurchase 10.7 million and 5.4 million shares of our common stock, respectively, under our share repurchase program. As of June 30, 2024, we had approximately $4.5 billion remaining under our share repurchase program.

Cash Dividends to Stockholders

During the six months ended June 30, 2024, we paid aggregate dividends of $0.870 per share of common stock, for a total of $202 million. We paid aggregate dividends of $0.790 per share of common stock for a total of $195 million during the six months ended June 30, 2023.

On June 17, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on August 16, 2024 to stockholders of record as of the close of business on August 9, 2024.

Summary of Critical Accounting Estimates

The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

Recent Accounting Standards

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

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

We have 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):

	June 30, 2024				December 31, 2023
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(1,753)	$	1,466	$	(2,117)	$	1,526
LNG Trading Derivatives	(17)		14		10		12

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

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ITEM 4.    CONTROLS AND PROCEDURES

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

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

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PART II.    OTHER INFORMATION

ITEM 1.    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. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

ITEM 1A.    RISK FACTORS

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes share repurchases for the three months ended June 30, 2024:

Period	Total Number of Shares Purchased	Average Price Paid Per Share (1)	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) (2)
April 1-30, 2024	1,298,558	$158.18	1,298,558	$744
May 1-31, 2024	1,295,875	$157.75	1,295,875	$540
June 1-30, 2024	547,066	$158.15	547,066	$4,453
Total	3,141,499		3,141,499

(1)The price paid per share was based on the average trading price of our common stock on the dates on which we repurchased the shares.

(2)On June 14, 2024, our Board authorized an increase in the existing repurchase program by $4.0 billion, effective through December 31, 2027.

ITEM 5.    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 June 30, 2024, 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).

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ITEM 6.    EXHIBITS

Exhibit No.
	Description
4.1	Ninth Supplemental Indenture, dated as of May 22, 2024, among CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (incorporated by reference to Exhibit 4.1 to the CQP's Current Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2024)
10.1*	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-00086 CCL Tanks “A” and “C” Engineering, Procurement and Construction, dated March 15, 2024, (ii) the Change Order CO-00087 HAZOP Package #6 (“Phase Four Items”), dated January 1, 2024, (iii) the Change Order CO-00088 FERC & PHMSA (DOT) Support Hours (Through to Period 24-Dec-2023), dated February 2, 2024, and (iv) the Change Order CO-00089 30PK-3301A/B/C Firewater Pump Protection - Blast Analysis, Design and Calculation Report, dated May 7, 2024 (Portions of this exhibit have been omitted.)
10.2	Registration Rights Agreement, dated as of May 22, 2024, among CQP, the guarantor party thereto, BofA Securities, Inc., Citigroup Global Markets Inc., ING Financial Markets LLC, MUFG Securities Americas Inc., SMBC Nikko Securities America, Inc. and Standard Chartered Bank (incorporated by reference to Exhibit 10.1 to CQP's Current Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2024)
10.3	Cheniere Energy, Inc. Amended and Restated 2020 Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 24, 2024)
10.4*	First Amendment to Second A&R Term Loan Facility Agreement, dated April 19, 2024
10.5*	First Amendment to Second A&R Common Terms Agreement, dated April 19, 2024
10.6*	First Amendment to Second A&R Common Security and Account Agreement, dated April 19, 2024
10.7*	First Amendment to Second A&R Working Capital Facility Agreement, dated April 19, 2024
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
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
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)

*	Filed herewith.
**	Furnished herewith.

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SIGNATURES

Pursuant to the requirements 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.
Date:	August 7, 2024	By:	/s/ Zach Davis
			Zach Davis
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	August 7, 2024	By:	/s/ David Slack
			David Slack
			Senior Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

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EX-10.1

Exhibit 10.1

[***] 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

CCL TANKS “A” AND “C” ENGINEERING, PROCUREMENT AND CONSTRUCTION

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00086 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 15-Mar-2024

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”), Schedule A-1 (“Scope of Work”) of the Agreement is hereby revised to include the engineering, procurement and construction for the Tank(s) “A” and “C” tie in scope in accordance with the piping and instrumentation diagrams (“P&IDs”) provided as Attachment 1 of this Change Order. For clarity this Change Order includes four (4) skin thermocouples that are wired to the local junction box at locations agreed during the 30% model review (but are not currently shown on the P&IDs). A forecast and indicative Level 2 Schedule is provided as Attachment 2 of this Change Order.

2.    This Change Order, for context, supplements the approvals provided by following earlier-executed Change Order(s). Therefore the detailed cost breakdown for this Change Order (provided as Exhibit A of this Change Order) reconciles against all earlier-approved scope:

1)    Change Order CO-00054: Tie-In Study, preparation of an EPC Contract Price and Level 2 schedule, and, certain long lead items (Package #1);

2)     Change Order CO-00080: Long lead items (Package #2);

3)    Change Order CO-00081: Bridging Engineering (through 29-Mar-2024);

4)    Change Order CO-00084: Long lead items (Package #3)

3.    Parties agree that the definition of Stage 3 Facility includes all Work to perform CCL Liquefaction Facility Tie-in Work. Labor costs to perform CCL Liquefaction Facility Tie-in Work are separately itemized in Exhibit 1 of this Change Order. Capitalized terms used in Clause 3 of this Change Order have meaning ascribed to them in the Stage 3 EPC Agreement.

4.    Schedule 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-00085)...............................	$	315,077,603
3. The Contract Price prior to this Change Order was ........................…..................................................	$	5,799,077,603
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 …………………………………….....	$	5,828,283,837

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: Yes

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/ MV 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/ Mike VanderMate

Name: Mike VanderMate

Title: SVP E&C

BECHTEL ENERGY INC.

By: /s/ Steve Smith

Name: Steve Smith

Title: Senior Project Manager and Senior Vice President

CHANGE ORDER

HAZOP PACKAGE #6 (“PHASE FOUR ITEMS”)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00087 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 22-Jan-2024

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 revised to implement the following HAZOP resolution(s):

Item	HAZOP Reference	HAZOP Scenario see note 1	HAZOP Resolution
1	26290-100-U4R-DK-30099	In Unit 19, in the event of an operator error, there is potential for pressure in blowdown header to be higher than pressure in the low-pressure blowdown system.	Contractor will change four (4) Pressure Indicators (per Train) to four (4) Pressure Transmitters with high alarm (per Train) to alert an operator that the pressure in the Dry Blowdown Header network is too high to allow low pressure systems to be blown-down (typical for seven Trains).
2	Parking Lot items 90 and 91	During a global power failure, fuel gas is unavailable and therefore there is potential for air ingress in flare system.	Additional interlock added on start-up fuel gas line to ensure fuel gas is available in case of a global power failure. Nitrogen shall be supplied to 31PV-22006, 31XV-11039 and 31XV-11042 via pressure regulator such that upon low instrument air (IA) pressure, back up nitrogen is available for valve actuation (only for three Trains).
3	26290-100-U4R-DK-30048	Potential high pressure in 30V-3601 Potable Water Vessel and safety shower users due to failure in level transmitter or failure in instrument air 30PCV-36003.	Add pressure regulators to six (6”) inch outlet line -30PW-360100 of 30V-3601 Potable Water Vessel to make sure potable water pressure is less than 60 psig.
4	26290-100-U4R-DK-10093	Potential for 31C-1301 Regen Gas Compressor depressurization and a relief scenario takes place in the Wet Flare header.	Addition of Car Seal Open (CSO) manual valve (Orbit) on the two (2”) inch 31FL-13161 which is expected to be closed for significant Regen Gas Compressor 31C-1301 shutdown (typical for seven trains).
5	26290-100-U4R-DK-10084	31VA-110028 in bypass around inlet feed gas isolation valves opened too quickly during startup scenario resulting in High Rho V2 Values in Acoustic/Flow Induced Vibration (AIV/FIV) calculations.	Change ball valve to Car Seal Closed (CSC) (no price impact) and increase size of bypass line from two (2”) to four (4”) downstream of globe valve 30VA-110902 to mitigate High Rho V2 (typical for seven trains).

6	26290-100-U4R-DK-23022	At Truck Loading Stations 1 & 2, there is no depressurization line between block valves.	Add hard pipe connection (line two (2”) inch 30FD-20086) between block valves to allow depressurization of hoses to closed flare system. (Typical for both truck stations).
7	26290-100-U4R-DK-10102	Potential for 31PV-13049 to malfunction closed during defrost operation & 31TV-13048 to malfunction wide open during defrost operation, leading to increase in temperature that exceeds design temperature of equipment in defrost circuit.	To close the LOPA gap, add an additional 31XV-13039 and two 31TT-13047B/C added with interlock 31I-13-10 which will close during high-high defrost temperature. This will provide 2.5 years test interval (typical for seven trains).
8	26290-100-U4R-DK-22100	30XV-24300 is opened before pipe pressure is equalized on both side of the XV, creating 2-phase flow downstream.	Addition of Pressure Transmitter across valve 24300 are added with new interlock 30I-24-08 to provide permissive to open the valve on low differential pressure across the valve.

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-00086)….……………..	$	344,283,837
3. The Contract Price prior to this Change Order was ………………………………………………..	$	5,828,283,837
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 ……………………………………..	$	5,831,633,966

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/ MV 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/ Mike VanderMate

Name: Mike VanderMate

Title: SVP, Engineering & Construction

BECHTEL ENERGY INC.

By: /s/ Steve Smith

Name: Steve Smith

Title: Sr. Project Manager and Senior Vice President

CHANGE ORDER

FERC & PHMSA (DOT) SUPPORT HOURS (THROUGH TO PERIOD 24-Dec-2023)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00088 DATE OF CHANGE ORDER: 01-Mar-2022 DATE OF AGREEMENT: 02-Feb-2024

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.    In accordance with Sections 11.1 and 11.2(D) of Schedule A-1 (“Scope of Work”) of the Agreement, this Change Order;

1.1    Increases the Contract Price to reflect the additional [***] hours expended throughout 2023 (to period 24-Dec-2023) to support Owner with the application, coordination and compliance with FERC and PHMSA (DOT) Owner permits; and;

1.2    For context, as of 24-Dec-2023, such support (Contractor’s hours) totals [***] hours, therefore exceeding the [***] hours allocated for such support.

2.    For detailed description of activities by month see Attachment 1.

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 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-00087)……….……......	$	347,633,966
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,831,633,966
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 ……………………….......................	$	5,832,191,832

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/ MV 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/ Mike VanderMate

Name: Mike VanderMate

Title: SVP Engineering & Construction

BECHTEL ENERGY INC.

By: /s/ Steve Smith

Name: Steve Smith

Title: Senior Project Manager and Senior Vice President

CHANGE ORDER

30PK-3301A/B/C FIREWATER PUMP PROTECTION - BLAST ANALYSIS, DESIGN AND CALCULATION REPORT

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00089 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 07-May-2024

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 revised as follows:

1.1    Contractor will provide a third party-developed blast analysis, design and calculation report determining solutions to protect firewater pump packages 30PK-3301A/B/C from blast pressure of 2.00 psi with a duration 63 milliseconds (herein “Study”);

1.2    A draft Study deliverable will be provided no later than seven (7) weeks from execution of this change order; and

1.3    For context, this Study responds to Blue Engineering (Owner’s consultant) updated recommendations.

2.    This is a feasibility study, only, and therefore the cost and schedule impact of implementing any solutions are currently unknown and excluded and will be provided under separate proposal should Owner wish to move forward.

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 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-00088)…..……………….	$	348,191,832
3. The Contract Price prior to this Change Order was ………………………………………………......	$	5,832,191,832
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 …………………………………….....	$	5,832,308,642

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/ MV 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/ Mike VanderMate

Name: Mike VanderMate

Title: SVP, Engineering & Construction

BECHTEL ENERGY INC.

By: /s/ Steve Smith

Name: Steve Smith

Title: Sr. Project Manager and Senior Vice President

EX-10.4

Exhibit 10.4

FIRST AMENDMENT TO
SECOND A&R TERM LOAN FACILITY AGREEMENT

This First Amendment, dated as of April 19, 2024 (the “First Amendment”), amends the Second Amended and Restated Term Loan Facility Agreement, dated as of June 15, 2022 (as amended, amended and restated, modified or supplemented from time to time, the “Term Loan Facility Agreement”), by and among Cheniere Corpus Christi Holdings, LLC (the “Borrower”), Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P. and Corpus Christi Pipeline GP, LLC (the “Guarantors” and, together with the Borrower, the “Loan Parties”), Société Générale as the Term Loan Facility Agent, and the Term Lenders that are party thereto. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Term Loan Facility Agreement.

WHEREAS, the Loan Parties wish to enter into this First Amendment; and

WHEREAS, the Term Loan Facility Agent is executing this amendment as set forth herein pursuant to Section 12.01 (Decisions; Amendments, Etc.) of the Term Loan Facility Agreement and Section 3 (Voting and Decision Making) and Section 4 (Modifications; Instructions; Other Relationships)of the Intercreditor Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained herein, and subject to the terms and conditions herein set forth, the parties hereto agree as follows:

Section 1. Amendments to Term Loan Facility Agreement. The Borrower, the Guarantors and the Term Loan Facility Agent each agree that the Term Loan Facility Agreement is hereby amended by:

(a)amending Section 2.01(d) (Term Loans) of the Term Loan Facility Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“Proceeds of the Term Loans advanced for the purpose of (i) funding the Senior Debt Service Reserve Account shall be paid into the Senior Debt Service Reserve Account, and (ii) reimbursing Equity Funding to an Affiliate of the Borrower in accordance with Section 2.7 (Reimbursements of Equity Funding) of the Common Terms Agreement and Section 2.07 (Use of Proceeds) of this Agreement, and (iii) except in the case of the Initial Advance, paying interest accruing on the Term Loans and Commitment Fees during the Term Loan Availability Period, as designated in the Disbursement Request, shall be transferred by the Term Loan Facility Agent to the Term Lenders in accordance with Section 10.13(a) (General Provisions as to Payments); provided that such transfer shall occur on the same day that the Term Loan Facility Agent receives

such proceeds from the Term Lenders and subject to the Term Loan Facility Agent’s actual receipt of such proceeds in accordance with Section 2.04 (Funding). For the avoidance of doubt, such Advance shall constitute a Term Loan for all purposes under this Agreement and each other Finance Document and shall be treated as received, and accounted for as a Term Loan, by the Borrower.”

(b)amending Section 2.07 (Use of Proceeds) of the Term Loan Facility Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“Proceeds of the Term Loans may be used by the Borrower or the other Loan Parties solely to (i) pay Project Costs, funding(ii) fundthe Senior Debt Service Reserve Account, and to(iii)make Authorized Investments. and (iv) to the extent that, at any time the Stage 3 Senior Debt/Equity Ratio, as certified by the Borrower to the Term Loan Facility Agent, is less than 50:50 based on the actual Project Costs that have been paid as of such date, reimburse Equity Funding to an Affiliate of the Borrower up to an amount that would give rise to a Stage 3 Senior Debt/Equity Ratio of no greater than 50:50; provided that, as of the date on which an Advance is requested, the Borrower shall certify to the Term Loan Facility Agent that (a) Senior Debt Commitments, (b) Equity Funding commitments (if any), (c) funds in the Construction Account and the Equity Proceeds Account and (d) projected contracted Cash Flow from the fixed component under the Qualifying LNG SPAs, in each case under the updated Base Case Forecast, shall be sufficient to achieve the Stage 3 Completion Date by the Stage 3 Date Certain.”

Section 2. Effectiveness. This First Amendment shall be effective upon (a) the receipt by the Term Loan Facility Agent of executed counterparts of this First Amendment by the Borrower and each Guarantor and (b) the execution of this First Amendment by the Term Loan Facility Agent.

Section 3. Finance Document. This First Amendment constitutes a Finance Document as such term is defined in, and for purposes of, the Common Terms Agreement.

Section 4. GOVERNING LAW. THIS FIRST AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, UNITED STATES WITHOUT REGARD TO CONFLICTS OF LAWS PRINCIPLES THEREOF THAT WOULD RESULT IN THE APPLICATION OF THE LAW OF ANY OTHER JURISDICTION.

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Section 5. Headings. All headings in this First Amendment are included only for convenience and ease of reference and shall not be considered in the construction and interpretation of any provision hereof.

Section 6. Binding Nature and Benefit. This First Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted transfers and assigns.

Section 7. Counterparts. This First Amendment may be executed in multiple counterparts, each of which shall be deemed an original and all of which, when taken together, shall constitute one agreement. Delivery of an executed signature page of this First Amendment by facsimile or other electronic transmission (e.g., “pdf” or “tif”) shall be effective as delivery of a manually executed counterpart hereof. Any signature to this First Amendment may be delivered by facsimile, electronic mail (including pdf) or any electronic signature complying with the U.S. federal ESIGN Act of 2000 or the New York Electronic Signature and Records Act or other transmission method and any counterpart so delivered shall be deemed to have been duly and validly delivered and be valid and effective for all purposes to the fullest extent permitted by applicable law.

Section 8. No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Term Loan Facility Agreement shall continue unchanged and shall remain in full force and effect. Each amendment granted herein shall apply solely to the matters set forth herein and such amendment shall not be deemed or construed as an amendment of any other matters, nor shall such amendment apply to any other matters.

[Signature pages follow]

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IN WITNESS WHEREOF, the parties have caused this First Amendment to be duly executed and delivered as of the day and year first above written.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC,as the Company
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CORPUS CHRISTI LIQUEFACTION, LLC, as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CHENIERE CORPUS CHRISTI PIPELINE, L.P., as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CORPUS CHRISTI PIPELINE GP, LLC, as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

Signature Page to First Amendment to

Second A&R Term Loan Facility Agreement

IN WITNESS WHEREOF, the parties have caused this First Amendment to be duly executed and delivered as of the day and year first above written.

SOCIÉTÉ GÉNÉRALE,
as Term Loan Facility Agent on behalf of itself and the Required Term Lenders

By: /s/ Kevin Soucy

Name: Kevin Soucy

Title: Director

Signature Page to First Amendment to

Second A&R Term Loan Facility Agreement

EX-10.5

Exhibit 10.5

FIRST AMENDMENT TO
SECOND A&R COMMON TERMS AGREEMENT

This First Amendment, dated as of April 19, 2024 (the “First Amendment”), amends the Second Amended and Restated Common Terms Agreement, dated as of June 15, 2022 (as amended, amended and restated, modified or supplemented from time to time, the “Common Terms Agreement”), by and among Cheniere Corpus Christi Holdings, LLC (the “Borrower”), Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P. and Corpus Christi Pipeline GP, LLC (the “Guarantors” and, together with the Borrower, the “Loan Parties”), Société Générale as the Term Loan Facility Agent, The Bank of Nova Scotia as the Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Common Terms Agreement.

WHEREAS, the Loan Parties wish to enter into this First Amendment; and

WHEREAS, the Intercreditor Agent is executing this amendment as set forth herein pursuant to Section 23.16 (Amendments) of the Common Terms Agreement and Section 3 (Voting and Decision Making) and Section 4 (Modifications; Instructions; Other Relationships)of the Intercreditor Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained herein, and subject to the terms and conditions herein set forth, the parties hereto agree as follows:

Section 1. Amendments to Common Terms Agreement. The Borrower, the Guarantors and the Intercreditor Agent each agree that the Common Terms Agreement is hereby amended by:

(a)deleting the reference to “[Reserved]” in Section 2.7 ([Reserved]) of the Common Terms Agreement and replacing it in its entirety with the following clause:

“2.7    Reimbursements of Equity Funding

To the extent permitted by a Senior Debt Instrument, disbursements of any Senior Debt may be used to reimburse Equity Funding, in order to achieve any Senior Debt to Equity Funding ratio that is permitted under such Senior Debt Instrument.”

(b)amending Section 6.5(a) (Expansion Senior Debt) of the Common Terms Agreement by deleting the stricken text (example: stricken text) as set forth below:

“The Borrower may incur Expansion Senior Debt to finance a Permitted Development Expenditure or Expansion (“Expansion Senior Debt”), as the

case may be, so long as each of the following conditions is satisfied and the Borrower shall have delivered to the Intercreditor Agent a certificate from an Authorized Officer certifying that such conditions have been satisfied (any such Expansion Senior Debt incurred upon satisfaction of such conditions shall be deemed to have been approved by the Intercreditor Agent for purposes of any Indenture):”

(c)amending Section 8.1 (LNG SPA Maintenance) of the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) as set forth below:

“(d)    The Borrower may, at any time, by notice to the Intercreditor Agent elect for any Qualifying LNG SPA to cease to be a Qualifying LNG SPA (such a LNG SPA, a “Disqualified LNG SPA”) and therefore be deemed to have been “terminated” as a Qualifying LNG SPA for purposes of Section 8.1(a) (LNG SPA Maintenance) and the related quantity contracted to be sold under such LNG SPA shall be removed from the Base Committed Quantity; provided that, after giving effect to such election, the amount of all Senior Debt (excluding Excluded Working Capital Debt and excluding all Indebtedness under Permitted Senior Debt Hedging Instruments) outstanding after such election produces a Fixed Projected DSCR of at least 1.50:1.00 based on a Base Case Forecast updated to take into account the LNG SPAs that then remain as Qualifying LNG SPAs (and the Borrower shall make a LNG SPA Mandatory Prepayment as set forth in Section 8.2(b) (LNG SPA Mandatory Prepayment) in any amount required in order to achieve such minimum Fixed Projected DSCR (or, if no such prepayment is required in order to achieve such Fixed Projected DSCR, shall be deemed to have made a prepayment for purposes of any adjustment to the Base Committed Quantity that is required to reflect the adjusted LNG volumes then contracted to be sold under the then-remaining Qualifying LNG SPAs as a result of such disqualification election)).”

(d)amending Section 8.2(a) and (b) (LNG Mandatory Prepayment) of the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) as set forth below:

“(a)    The Borrower shall be required to make a mandatory prepayment (an “LNG SPA Mandatory Prepayment”) if either of the events set forth below occurs (each, an “LNG SPA Prepayment Event”):

(i)    CCL breaches the covenant in Section 8.1 (LNG SPA Maintenance) (taking into account the period set forth therein to replace the relevant LNG SPA) or elects to disqualify a

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Qualifying LNG SPA pursuant to Section 8.1(d) (LNG SPA Maintenance); or”

“(b)    The amount of the Senior Debt (which shall not extend to any Working Capital Debt) that the Borrower shall repay and the amount of undrawn Facility Debt Commitments (which shall not include any Working Capital Debt) that the Borrower shall cancel upon the occurrence of any LNG SPA Prepayment Event shall be:

(i)    the aggregate principal amount of Senior Debt then-outstanding plus the aggregate principal amount of undrawn Facility Debt Commitments; less

(ii)    the maximum amount of Senior Debt that can be incurred without producing a Fixed Projected DSCR starting from the Quarterly Payment Date following the end of the applicable cure period and for each calendar year thereafter through the Qualifying Term of the Qualifying LNG SPAs then in effect lower than 1.50:1 based on a Base Case Forecast updated to take into account each Qualifying LNG SPA then in full force and effect (excluding, for the avoidance of doubt in the case of an election pursuant to Section 8.1(d) (LNG SPA Maintenance), any Disqualified LNG SPAs) and in respect of which there is in effect its Required Export Authorization which is not Impaired (including any new Qualifying LNG SPAs entered into to replace an LNG SPA whose termination triggered the LNG SPA Prepayment Event).”

(e)amending Section 8.3 (Amendment of LNG SPAs) to the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“Except to the extent an amendment or modification to a Qualifying LNG SPA is required by applicable law or regulation of any Governmental Authority, CCL shall not agree to:

(a)    any amendment or modification of the price or quantity provisions of any Qualifying LNG SPA:(excluding, for the avoidance of doubt, the making of an election pursuant to Section 8.1(d) (LNG SPA Maintenance) for a Qualifying LNG SPA to become a Disqualified LNG SPA, which shall be addressed under Section 8.1(d) (LNG SPA Maintenance)):

(i)    if such amendment or modification results in a breach of Section 8.1 (LNG SPA Maintenance); and

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(ii)    unless after giving effect to such amendment or modification, the Fixed Projected DSCR starting from the Quarterly Payment Date following the date of such amendment or modification for each calendar year thereafter through the Qualifying Term of the Qualifying LNG SPAs then in effect is at least the lower of:

(A)    a Fixed Projected DSCR of 1.40:1; and

(B)    the Fixed Projected DSCR before such change,; or

and CCL has certified the same to the Intercreditor Agent;

(b)    any amendment or modification of any Qualifying LNG SPA that could reasonably be expected to have a Material Adverse Effect; or.

(c)    any material waiver, amendment or modification of (i) the term of a Qualifying LNG SPA (other than an increase) if such waiver, amendment or modification is materially adverse to CCL or any other Loan Party, or (ii) guarantee or credit support provisions (other than an increase or improvement) if such waiver, amendment or modification is inconsistent with the minimum credit support requirements of the Finance Documents for Qualifying LNG SPAs; provided, in each case, that any such amendment shall be permitted if CCL notifies the Intercreditor Agent that it has elected for such amended or modified Qualifying LNG SPA to cease to be a Qualifying LNG SPA for purposes of the Finance Documents and, after giving effect to such amendment, the amount of all Senior Debt (excluding Excluded Working Capital Debt and excluding all Indebtedness under Permitted Senior Debt Hedging Instruments) outstanding is capable of being amortized to a zero balance by the termination date of the last to terminate of the Qualifying LNG SPAs then in effect and produces a Fixed Projected DSCR of at least 1.40:1.00 commencing on the first Quarterly Payment Date following such cessation of such LNG SPA as a Qualifying LNG SPA for each calendar year through the Qualifying Term of the Qualifying LNG SPAs then in effect (with such ratio being calculated on a pro forma basis giving effect to such cessation).

(c)    [reserved].”

(f)deleting each of clauses (e), (f), (h), (k), (r), (s) and (t) of Section 10.3 (Notices) to the Common Terms Agreement in its entirety and replacing each such clause with a reference to “[reserved]”.

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(g)amending clause (g) of Section 10.3 (Notices) to the Common Terms Agreement by deleting the stricken text (example: stricken text) as set forth below:

“(g)    unless previously notified pursuant to another provision in the Finance Documents, event, occurrence or circumstance that could reasonably be expected to cause:

(i)    an increase of more than an aggregate of $500 million in Project Costs in excess of the then-current Stage 3 and Incremental Construction Budget and Schedule (excluding any gas or electricity costs); or

(ii)    Operation and Maintenance Expenses to exceed the amount budgeted therefor by 10% or more in the aggregate per annum;

provided, that such notification shall not be required if the amount of all Senior Debt (excluding Excluded Working Capital Debt and excluding all Indebtedness under Permitted Senior Debt Hedging Instruments) outstanding after giving effect to such event, occurrence or circumstance is capable of being amortized to a zero balance by the termination date of the last to terminate of the Qualifying LNG SPAs then in effect and produces a Fixed Projected DSCR of at least 1.40:1.00 commencing on the first Quarterly Payment Date following such event, occurrence or circumstance for each calendar year through the Qualifying Term of the Qualifying LNG SPAs then in effect (with such ratio being calculated on a pro forma basis giving effect to the incurrence of such event, occurrence or circumstance);”

(h)amending the final paragraph of Section 10.4(b) (Construction Reports) to the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“provided that if the construction report from the EPC ContractorIndependent Engineerdoes not cover construction with respect to the Corpus Christi Pipeline Expansion, the Loan Parties may, if applicable, provide a separate report prepared by the Loan Parties or applicable contractor(s) for the Corpus Christi Pipeline Expansion covering the pipeline-related items required pursuant to this clause (b).”

(i)deleting Section 10.6 (Operating Statements and Reports) to the Common Terms Agreement in its entirety and replacing it with a reference to “[Reserved]”.

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(j)deleting each of clauses (d) and (e) of Section 12.5 (Material Project Agreements) to the Common Terms Agreement in its entirety and replacing each such clause with a reference to “[Reserved]”.

(k)amending Section 12.5 (f), (k) and (l) of Section 12.5 (Material Project Agreements) to the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“(f)    The Loan Parties shall not enter into any Subsequent Material Project Agreements without the prior written consent of the Intercreditor Agent acting on the instructions of the Requisite Intercreditor Parties; provided that the Intercreditor Agent’s consent shall not be required for:

(i)    a Qualifying LNG SPA that meets the requirements set forth in Section 8.1(b) (LNG SPA Maintenance);

(ii)    any Subsequent Material Project Agreement executed in form and substance substantially similar to a form and substance that has previously been approved by the Intercreditor Agent or is attached to an agreement previously approved by the Intercreditor Agent;

(iii)    the ADCC LLC Agreement (if ADCC Investco becomes a Subsidiary of the Borrower in accordance with Section 12.19(l) (Limitations on Investments and Loans)) as long as such agreement is executed in a form that is substantially similar to the form provided to the Intercreditor Agent on or prior to the Stage 3 Closing; provided that the Borrower shall have delivered an updated Base Case Forecast to the Intercreditor Agent that takes into account the commitments of ADCC Investco to make capital contributions to ADCC for the construction of the ADCC Pipeline in accordance with the ADCC LLC Agreement and demonstrates that after giving effect to such commitments of ADCC Investco under the ADCC LLC Agreement:

(A)    the amount of all Senior Debt (excluding Excluded Working Capital Debt and excluding all Indebtedness under Permitted Senior Debt Hedging Instruments) outstanding is capable of being amortized to a zero balance by the termination date of the last to terminate of the Qualifying LNG SPAs then in effect and produces a Fixed Projected DSCR of at least 1.40:1.00

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commencing on the first Quarterly Payment Date following the date on which ADCC Investco becomes a direct or indirect Subsidiary of the Borrower for each calendar year through the Qualifying Term of the Qualifying LNG SPAs then in effect (with such ratio being calculated on a pro forma basis giving effect to the incurrence of ADCC Investco’s obligations under the ADCC LLC Agreement); and

(B)    the Stage 3 Senior Debt/Equity Ratio will be equal or lower than 50:50 (calculated, for this purpose based on the Base Case Forecast delivered as of the Stage 3 Closing Date updated only to reflect any increases in the ADCC Pipeline Costs compared to those set forth in such Base Case Forecast);

(iv)    any:

(A)    Shipping Services Agreements to be entered into in connection with Stage 3 (DES) LNG SPAs; provided that such Shipping Services Agreements satisfy the requirements set forth in clause (h)(i) below;

(B)    Linked LNG SPAs to be entered into in connection with a Linked GSA-SPA that is a Stage 3 LNG SPA; provided that such Linked LNG SPAs satisfy the requirements set forth in clause (h)(ii) below; and

(v)    any other Subsequent Material Project Agreement that a Loan Party enters into, to the extent such Subsequent Material Project Agreement complies with specific requirements related to the terms and requirements therefor under the Finance Documents (to the extent such requirements are expressly set forth in the Finance Documents).; and

(vi)    any other Subsequent Material Project Agreement that a Loan Party enters into, to the extent entry into such Subsequent Material Project Agreement could not reasonably be expected to have a Material Adverse Effect.”

“(k)    No Loan Party shall, without the consent of the Intercreditor Agent (acting on the instruction of Requisite Intercreditor Parties), provide consent to a request for an amendment, modification or waiver to, or assignment or transfer of any interest under, the PetroChina DES LNG SPA that is requested by CMI (UK) unless: that could reasonably be expected to have a Material Adverse Effect.

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(i)    in the case of an amendment, modification or waiver, (A) a corresponding amendment, modification or waiver is made to the DES-Linked LNG SPA to the extent that such amendment, modification or waiver of the DES-Linked LNG SPA is required to maintain the alignment of material terms between the DES-Linked LNG SPA and the PetroChina DES LNG SPA and (B) such corresponding amendment, modification or waiver of the DES-Linked LNG SPA meets the requirement therefor in the Finance Documents; and

(ii)    in the case of an assignment or transfer of any interest under the DES-Linked LNG SPA, such assignment or transfer of any interest could not reasonably be expected to have a Material Adverse Effect.”

“(l)    No Loan Party shall, without the consent of the Intercreditor Agent (acting on the instruction of Requisite Intercreditor Parties):

(i)    amend, waive or modify any of CMI (UK)’s rights or obligations under the CMI Security Agreement in a manner that is materialand adverse to the interests of the Loan Parties could reasonably be expected to have a Material Adverse Effect; or

(ii)    consent to an assignment or transfer of any of CMI (UK)’s material rights or obligations under the CMI Security Agreement that could reasonably be expected to have a Material Adverse Effect.”

(l)amending Section 12.17 (c), (l), (m) and adding clause (n) (Sale of Project Property) to the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“(c)    dispositions of the sale, lease or other disposition of (A) products, services, inventory or accounts receivable in the ordinary course of business or (B)obsolete, superfluous or replaced assets, or assets that are not, or cease to be, necessary for the construction and operation of the Project Facilities substantially in the manner contemplated in this Agreement;”

“(l)    dispositions of other Project Property if a Loan Party replaces such Project Property within 180 days following such disposition or has obtained a commitment to replace such Project Property within 180 days following such disposition and replaces such Project Property within 270 days following such disposition; and”

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“(m)    sale of investments held in pipelines (other than the Corpus Christi Pipeline), electricity generation, carbon capture and sequestration, helium processing or nitrogen rejection facilities, pollution control and associated infrastructure (or in the entity owning such facilities or infrastructure) at a fair market valueand so long as the sale does not materially adversely impact any Material Project Agreement in effect prior to such sale between a Loan Party and the owner of such facilities.; and”

“(n)    any single transaction or series of related transactions that involves assets having a fair market value of less than $50,000,000.”

(m)amending Section 12.22(b) (Hedging Arrangements) to the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“(b)    The As of and following any Hedge Obligation Date, theBorrower shall enter into and thereafter maintain in full force and effect, from time to time, one or more interest rate Permitted Hedging Instruments with respect to no less than 60% (calculated on a weighted average basis) of the projected aggregate outstanding balance of the Senior Debt, no later than 90 days following the Stage 3 Closing Date for the projected aggregate outstanding balance of the Senior Debt; provided that for. The “Hedge Obligation Date” for purposes of this clause shall mean the first Business Day falling 60 days after the date on which the aggregate notional amount of the Permitted Hedging Instruments is less than 60% (calculated on a weighted average basis) of the projected aggregate outstanding balance of Senior Debt as a result of a mandatory or voluntary prepayment of Senior Debt. Forpurposes of calculating such percentage, any such the percentages described in this clause (b), anySenior Debt which bears a fixed interest rate shall be deemed subject to a Permitted Hedging Instrument.”

(n)amending Section 15.1(c) (Loan Facility Events of Default – Breach of Certain Covenants) to the Common Terms Agreement by deleting the reference to Section 12.5(d) (Material Project Agreements) from Section 15.1(c)(ii)(A)(3) (Loan Facility Events of Default – Breach of Certain Covenants) and deleting the reference to Section 12.5(e) (Material Project Agreements) from Section 15.1(c)(ii)(B)(4) (Loan Facility Events of Default – Breach of Certain Covenants).

(o)adding the definition of “Disqualified LNG SPA” to Section 1.3 (Definitions) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Terms Agreement by inserting the text as set forth below:

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““Disqualified LNG SPA” has the meaning set forth in Section 8.1(d) (LNG SPA Maintenance) of the Common Terms Agreement.”

(p)amending the definition of “Permitted Hedging Instrument” in Section 1.3 (Definitions) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Terms Agreement by deleting the stricken text (example: stricken text) as set forth below:

““Permitted Hedging Instrument” means a Hedging Instrument entered into by a Loan Party in the ordinary course of business and that (i) is with a Hedging Bank, a Gas Hedge Provider, a Power Hedge Provider or any other party that is a counterparty to a Hedging Instrument, (ii) if secured, is of the type referred to in clause (a) or (b) of the definition of Hedging Instrument and (iii) is entered for non-speculative purposes and is on arm’s-length terms; provided that (a) if such Hedging Instrument is a Gas Hedging Instrument, Permitted Hedging Instruments are limited to the following: (1) Futures Contracts, Fixed-Floating Futures Swaps, NYMEX Natural Gas Futures Contracts and Swing Swaps for gas hedging purposes for up to a maximum of 207.5 TBtu of gas utilizing intra-month and up to 24 prompt month contracts, (2) Index Swaps for gas hedging purposes for up to a maximum of 98.8 TBtu per month of gas utilizing up to 24 prompt month contracts, and (3) Basis Swaps for gas hedging purposes for up to a maximum of 98.8 TBtu per month with a tenor up to 60 months, where the limitations in each of the categories described in sub-clauses (1), (2) and (3) are not aggregated, and (b) if such Hedging Instrument is a Power Hedging Instrument, the aggregate quantum under such Hedging Instrument does not exceed 3,650,000 megawatt hours and each such Hedging Instrument is for a period not to exceed 60 months where the first month is the month in which the power hedging contract is executed. “Permitted Hedging Instrument” includes any “Permitted Senior Debt Hedging Instrument.””

(q)amending the definition of “Restricted Payment” in Section 1.3 (Definitions) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

““Restricted Payment” means (a) any dividend or other distribution by the Borrower (in cash, property of the Borrower, securities, obligations, or other property) on, or other dividends or distributions on account of, or the setting apart of money for a sinking or other analogous fund for, or the purchase, redemption, retirement or other acquisition by the Borrower of, any portion of any membership interest in the Borrower and (b) all payments (in cash, property of the Borrower, securities, obligations, or other property) of principal of, interest on and other amounts with respect to, or other payments on account of, or the setting apart of money for a sinking or other analogous

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fund for, or the purchase, redemption, retirement or other acquisition by the Borrower of, any Indebtedness owed to Holdco or any other Person party to a pledge agreement or any Affiliate thereof, including any Subordinated Debt. Restricted Payments shall not include payments to the Manager for fees and costs pursuant to Management Services Agreements and fees and costs payable pursuant to the Gas and Power Supply Services Agreement and payments to the Operator pursuant to the O&M Agreements (which shall be paid in accordance with Section 4.7 (Cash Waterfall) of the Common Security and Account Agreement); Permitted Payments (which shall be paid in accordance with Section 4.7 (Cash Waterfall) of the Common Security and Account Agreement); Senior Debt proceeds applied in accordance with amounts paid in accordance with Section 2.7 (Stage 3 Senior Debt/Equity Ratio at Stage 3 Completion Date) (Reimbursements of Equity Funding) of the Common Terms Agreement; and any of the payments in (a) or (b) above (whether in cash, securities, obligations or otherwise) made among any of the Loan Parties.”

(r)Amending paragraph (d) of the definition of “Subsequent Material Project Agreement” in Section 1.3 (Definitions) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

(d)    any contract, agreement, letter agreement or other instrument (other than a Real Property Document) that is not otherwise expressly covered by clauses (a), (b), (c), (e), (f) or (g) of this definition that, (i) contains obligations and liabilities that are in excess of $100 million over its term (including after taking into account all amendments, amendments and restatements, supplements, or waivers to any such contract, agreement, letter agreement or other instrument) and (ii) is for a term that is greater than 10 years under this clause (d); provided that the following shall not constitute Subsequent Material Project Agreements: (A) any construction contracts entered into following the Stage 3 Closing Date, until such time as any Loan Party has entered into construction contracts following the Stage 3 Closing Date that contain obligations and liabilities which in the aggregate are equal to at least $100 million, (B) any LNG SPAs that are not Qualifying LNG SPAs and any guarantee thereof, (C) prior to the incurrence of any Expansion Senior Debt following the Stage 3 Closing Date, any contract, agreement, letter agreement or other instrument containing obligations or liabilities which is not effective by its terms unless and until the Expansion Senior Debt is incurred, (D) any Gas supply contracts (other than any Linked GSA-SPA), and (E) any agreements related solely to the Stage 3 Development except any Qualifying LNG SPAs and any agreements with Affiliates that otherwise meet the

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thresholds set forth in this clause (d), and (F) any guarantees provided by a Loan Party in support of another Loan Party in connection with a Material Project Agreement;

(s)Amending each of Section 2.1 (Operational Property Damage Insurance), Section 2.2 (Business Interruption Insurance), Section 2.3 (Commercial General Liability), Section 2.4 (Marine Cargo Insurance for DES Shipping) and Section 2.5 (Charterer’s Liability Insurance for DES Shipping) of Schedule L (Schedule of Minimum Insurance) to the Common Terms Agreement by replacing the terms specified within these sections as the “Sum Insured”, in each case, with “As is consistent with Prudent Industry Practice”.

(t)Amending Section 6 (Construction All Risk and DSU/Operational Property Damage and Business Interruption Limits) of Schedule L (Schedule of Minimum Insurance) to the Common Terms Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“In lieu of the full construction value or the full replacement value, the Borrower shall be permitted to obtain limits as are consistent with Prudent Industry Practice which meet the full value for probable maximum loss for the perils of windstorm/hurricane, earthquake, flood, vapor cloud explosion, and such other perils as identified and quantified in a probable maximum loss study conducted by a reputable and experienced firm well versed in performing such studies for the then-existing Development. The Borrower shall be permitted to obtain delayed start up (DSU) and business interruption limits as are consistent with Prudent Industry Practice based on the values required for insuring scheduled debt service in respect of the Senior Debt Obligations and fixed expenses for the estimated period of indemnity identified and quantified in a probable maximum loss study conducted by a reputable and experienced firm well versed in performing such studies for the then-existing Development.”

(u)Deleting clauses (A) through (E) (inclusive) of Section 9 (Notices and Reporting) of Schedule L (Schedule of Minimum Insurance) to the Common Terms Agreement in their entirety and replacing each of them with the reference “[Reserved]”.

Section 2. Effectiveness. This First Amendment shall be effective upon (a) the receipt by the Intercreditor Agent of executed counterparts of this First Amendment by the Borrower and each Guarantor and (b) the execution of this First Amendment by the Intercreditor Agent.

Section 3. Finance Document. This First Amendment constitutes a Finance Document as such term is defined in, and for purposes of, the Common Terms Agreement.

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Section 4. GOVERNING LAW. THIS FIRST AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, UNITED STATES WITHOUT REGARD TO CONFLICTS OF LAWS PRINCIPLES THEREOF THAT WOULD RESULT IN THE APPLICATION OF THE LAW OF ANY OTHER JURISDICTION.

Section 5. Headings. All headings in this First Amendment are included only for convenience and ease of reference and shall not be considered in the construction and interpretation of any provision hereof.

Section 6. Binding Nature and Benefit. This First Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted transfers and assigns.

Section 7. Counterparts. This First Amendment may be executed in multiple counterparts, each of which shall be deemed an original and all of which, when taken together, shall constitute one agreement. Delivery of an executed signature page of this First Amendment by facsimile or other electronic transmission (e.g., “pdf” or “tif”) shall be effective as delivery of a manually executed counterpart hereof. Any signature to this First Amendment may be delivered by facsimile, electronic mail (including pdf) or any electronic signature complying with the U.S. federal ESIGN Act of 2000 or the New York Electronic Signature and Records Act or other transmission method and any counterpart so delivered shall be deemed to have been duly and validly delivered and be valid and effective for all purposes to the fullest extent permitted by applicable law.

Section 8. No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Common Terms Agreement shall continue unchanged and shall remain in full force and effect. Each amendment granted herein shall apply solely to the matters set forth herein and such amendment shall not be deemed or construed as an amendment of any other matters, nor shall such amendment apply to any other matters.

[Signature pages follow]

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IN WITNESS WHEREOF, the parties have caused this First Amendment to be duly executed and delivered as of the day and year first above written.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC,as the Company
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CORPUS CHRISTI LIQUEFACTION, LLC, as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CHENIERE CORPUS CHRISTI PIPELINE, L.P., as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CORPUS CHRISTI PIPELINE GP, LLC, as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

Signature Page to First Amendment to

Second A&R Common Terms Agreement

IN WITNESS WHEREOF, the parties have caused this First Amendment to be duly executed and delivered as of the day and year first above written.

SOCIÉTÉ GÉNÉRALE,
as Intercreditor Agent on behalf of itself, each Facility Agent and the Requisite Intercreditor Parties

By: /s/ Kevin Soucy

Name: Kevin Soucy

Title: Director

Signature Page to First Amendment to

Second A&R Common Terms Agreement

EX-10.6

Exhibit 10.6

FIRST AMENDMENT TO
SECOND A&R COMMON SECURITY AND ACCOUNT AGREEMENT

This First Amendment, dated as of April 22, 2024 (the “First Amendment”), amends the Second Amended and Restated Common Security and Account Agreement, dated as of June 15, 2022 (as amended, amended and restated, modified or supplemented from time to time, the “Common Security and Account Agreement”), by and among Cheniere Corpus Christi Holdings, LLC (the “Company”), Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P. and Corpus Christi Pipeline GP, LLC (the “Guarantors” and, together with the Company, the “Securing Parties”), the Senior Creditor Group Representatives party thereto and that accede thereto from time to time, for the benefit of all Senior Creditors, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Common Security and Account Agreement.

WHEREAS, the Loan Parties wish to enter into this First Amendment; and

WHEREAS, the Intercreditor Agent is executing this amendment as set forth herein pursuant to Section 12.14 (Amendments) of the Common Security and Account Agreement and Section 3 (Voting and Decision Making) and Section 4 (Modifications; Instructions; Other Relationships) of the Intercreditor Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained herein, and subject to the terms and conditions herein set forth, the parties hereto agree as follows:

Section 1. Amendments to Common Security and Account Agreement. The Common Security and Account Agreement is hereby amended by:

(a)amending Section 2.3(a)(ii)(D) and (E) and adding Section 2.3(a)(ii)(F) (Pro Rata Payment of Senior Debt Obligations) to the Common Security and Account Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“(D)    each of the payments of Breakage Costs and other similar amounts required to be paid pursuant to an individual Senior Debt Instrument only (as referred to in Section 3.6 (Prepayment Fees and Breakage Costs) of the Common Terms Agreement and any comparable provision of any other Senior Debt Instrument then in effect) and including any cash collateralization of letters of credit required pursuant to the terms of any Working Capital Debt shall not be required to be made as a Pro Rata Payment; and”

“(E)    any other payments or prepayments to a Senior Creditor in respect of which it waives its right to a Pro Rata Payment under its Senior Debt Instrument (including, in respect of Facility Lenders, the proviso to Section 3.7 (Pro Rata Payment) of the Common Terms Agreement (and any comparable provision in any other Senior Debt Instrument then in effect)) which waiver shall be deemed to be a waiver of its right to receive a Pro Rata Payment in accordance with this Section 2.3(a) (Payments and Prepayments – Pro Rata Payment of Senior Debt Obligations) as a result of which such Senior Creditor shall not require a Pro Rata Payment or prepayment to such Senior Creditor.; and”

“(F)    any voluntary or optional prepayment, redemption or market purchase of Senior Debt Obligations (including any series of Senior Notes, in whole or in part) shall not be required to be made as a Pro Rata Payment; provided that such prepayment, redemption or market purchase is made using the proceeds of Replacement Senior Debt in compliance with the requirements set forth in Section 6.3 (Replacement Senior Debt) of the Common Terms Agreement (or any comparable provision of any other Senior Debt Instrument then in effect) or using funds eligible to make Restricted Payments.”

(b)amending Section 3.2(f)(ii) (Real Property) of the Common Security and Account Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“(ii)    The Company shall deliver an executed deed of trust or an amendment to or amendment and restatement of an existing deed of trust, substantially in the applicable form attached as Schedule I-1 (Form of Deed of Trust (CCL)) or Schedule I-2 (Form of Modification and Release Agreement (CCP)) (or in form and substance reasonably acceptable to the Security Trustee), to include all Real Estate of the Securing Parties acquired or otherwise established after the Stage 3 Closing that (x) has a purchase price in excess of $10,000,000 or is otherwise material to the operation ofthe Development50,000,0000 or (y) consists of Real Estate on which anyExpansion that is, or includes, an LNG Train is constructed(A) no later than 60 days following such acquisition or establishment in the case of Real Estate of any Securing Party other than relating to the Corpus Christi Pipeline Expansion and (B) in the case of Real Estate relating to the Corpus Christi Pipeline Expansion, no later than 60 days following the acquisition or establishment of the last Real Estate required for the commissioning of the Corpus Christi Pipeline Expansion or, if earlier, the date of the scheduled commissioning of the Corpus Christi Pipeline Expansion (or, in each case, such later period as reasonably

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agreed in writing by the Security Trustee), together with all documents and instruments required under the law of the State of Texas to perfect the Security Interest of the Security Trustee in such Common Collateral free of any other pledges, security interests or deeds of trust, except Permitted Liens. In connection with any such deed of trust entered into by CCL, CCL (x) shall also deliver a Title Policy meeting the requirements within the definition of such term based on the applicable Real Estate covered by such deed of trust, and (y) prior to the Term Loan Discharge Date, shall use commercially reasonable efforts to obtain and deliver a Flood Certificate consistent with the Flood Certificate described in Section 14(B) of Schedule L (Schedule of Minimum Insurance) of the Common Terms Agreement.”

(c)deleting each of clauses (c) and (e) of Section 3.4 (Direct Agreements) of the Common Security and Account Agreement in its entirety and replacing it with the reference “[Reserved]”

(d)amending clause (h) and adding a new clause (m) to Section 3.4 (Direct Agreements) of the Common Security and Account Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

(h)    For the avoidance of doubt, the Securing Parties shall not be required to (i) obtain Direct Agreements, including from any transporters under any Gas transportation agreements (other than precedent agreements), Gas suppliers under any Gas supply agreements, LNG Buyers or guarantors of LNG SPAs, in each case other than those set forth above. or (ii) maintain a Direct Agreement with respect to an LNG SPA or the Shipping Services Agreement related to such LNG SPA if such LNG SPA becomes a Disqualified LNG SPA in accordance with Section 8.1(d) (LNG SPA Maintenance) of the Common Terms Agreement.”

“(m)    If any Qualifying LNG SPA becomes a Disqualified LNG SPA pursuant to Section 8.1(d) (LNG SPA Maintenance) of the Common Terms Agreement, the Security Trustee is hereby authorized to execute any termination of, or release or expiration of, any Direct Agreement in effect with respect to such Disqualified LNG SPA.”

(e)amending Section 3.5(b) and (e) (Perfection and Maintenance of Security Interests) of the Common Security and Account Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

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“(b)    Collateral in Possession of Bailee; Perfection. If any goods (excluding Gas) in which any Securing Party owns or has an interest are now or at any time in the possession of a bailee and the value of such goods in the possession of such bailee is above $10,000,000 50,000,000:”

“(e)    From and after the Closing Date, with respect to any Letter-of-Credit Rights, the Securing Parties have ensured and shall ensure that, as promptly as reasonably practicable after receipt of a Letter-of-Credit, the Security Trustee has control thereof by ensuring that the Security Trustee takes possession thereof and obtaining a written consent from each issuer of each related letter of credit to the assignment of the proceeds of such letter of credit to the Security Trustee, except for (i) Letter-of-Credit Rights under any letters of credit which, at the time they are granted to a Securing Party, have a face value of less than $10,000,000 individually or $40,000,000 in the aggregate or (ii) from and after the Stage 3 Closing Date, Letter-of-Credit Rights delivered by CMI (UK) to CCL under the CMI Security Agreement or a Shipping Services Agreement which, at the time they are granted to a Securing Party, have a face value of less than $30,000,000 individually or $90,000,000 in the aggregate.

(e)    [Reserved].”

(f)amending Section 4.5(i) (Senior Debt Service Reserve Account) of the Common Security and Account Agreement by inserting the double-underlined text (example: double-underlined text) as set forth below:

“(i)    As of the date hereof, the Senior Debt Service Reserve Account has been funded by the issuance of Acceptable Debt Service Reserve LCs for the benefit of the Security Trustee under the Working Capital Facility Agreement in an amount equivalent to the Reserve Amount as of the Stage 3 Closing Date. Following the date hereof, in accordance with Section 4.7 (Cash Waterfall) or Section 4.8 (Accounts During the Continuance of a Declared Event of Default), the Company shall continue to cause the Senior Debt Service Reserve Account to be funded up to the then-applicable Reserve Amount, from disbursements of Senior Debt as permitted in the applicable Senior Debt Instrument, from Cash Flows in accordance with Section 4.7 (Cash Waterfall) or Section 4.8 (Accounts During the Continuance of a Declared Event of Default), Equity Funding and/or obtaining additional Acceptable Debt Service Reserve LCs.”

(g)amending Section 12.6(c) (Confidentiality) of the Common Security and Account Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

4

“(c)    Additionally, disclosure of any confidential document that contains confidentiality restrictions that require any Securing Party, or the Sponsor or any of their Affiliates, as applicable, to comply with a restricted procedure and LNGSPAs any contracts or documentscontaining commercially sensitive information and identified as such by the Company to the Security Trustee (each such document, a “Restricted Document”) shall only be permitted subject to compliance with the procedures in this clause (c). Restricted Documents may be disclosed to the Intercreditor Agent and the applicable Consultant or legal advisor (to the extent required by such Consultant or legal advisor in order to deliver reports required pursuant to any Finance Document) only (subject to redaction of commercially sensitive information in any such disclosed Restricted Documents provided to the Intercreditor Agent, Consultant or legal advisor and/or subject, if necessary or advisable based on the relevant Restricted Document to any such recipient providing confidentiality undertakings or agreements directly to the applicable counterparty to such Restricted Document).”

(h)amending Section 12.14(b) (Amendments) of the Common Security and Account Agreement by substituting an incorrect reference to Section 3.5(e) for a correct reference to Section 3.5(g).

(i)Adding paragraph (u) to Section 1.2 (Interpretation) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Security and Accounts Agreement by inserting the double-underlined text (example: double-underlined text) as set forth below:

“(u)    with respect to action by the Security Trustee, any action that is “authorized” and/or “authorized and directed” to be taken by the Security Trustee pursuant to the terms hereof shall mean that the Security Trustee is authorized and instructed as of the date hereof by such terms to take the relevant action without any further direction, consent or action of the Secured Parties upon the occurrence of the events in respect of which such action by the Security Trustee is “authorized” and/or “authorized and directed” as applicable.”

(j)adding the definition of “Disqualified LNG SPA” to Section 1.3 (Definitions) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Security and Accounts Agreement by inserting the text as set forth below:

““Disqualified LNG SPA” has the meaning set forth in Section 8.1(d) (LNG SPA Maintenance) of the Common Terms Agreement.”

5

(k)amending the definition of “Permitted Hedging Instrument” in Section 1.3 (Definitions) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Security and Accounts Agreement by deleting the stricken text (example: stricken text) as set forth below:

““Permitted Hedging Instrument” means a Hedging Instrument entered into by a Loan Party in the ordinary course of business and that (i) is with a Hedging Bank, a Gas Hedge Provider, a Power Hedge Provider or any other party that is a counterparty to a Hedging Instrument, (ii) if secured, is of the type referred to in clause (a) or (b) of the definition of Hedging Instrument and (iii) is entered for non-speculative purposes and is on arm’s-length terms; provided that (a) if such Hedging Instrument is a Gas Hedging Instrument, Permitted Hedging Instruments are limited to the following: (1) Futures Contracts, Fixed-Floating Futures Swaps, NYMEX Natural Gas Futures Contracts and Swing Swaps for gas hedging purposes for up to a maximum of 207.5 TBtu of gas utilizing intra-month and up to 24 prompt month contracts, (2) Index Swaps for gas hedging purposes for up to a maximum of 98.8 TBtu per month of gas utilizing up to 24 prompt month contracts, and (3) Basis Swaps for gas hedging purposes for up to a maximum of 98.8 TBtu per month with a tenor up to 60 months, where the limitations in each of the categories described in sub-clauses (1), (2) and (3) are not aggregated, and (b) if such Hedging Instrument is a Power Hedging Instrument, the aggregate quantum under such Hedging Instrument does not exceed 3,650,000 megawatt hours and each such Hedging Instrument is for a period not to exceed 60 months where the first month is the month in which the power hedging contract is executed. “Permitted Hedging Instrument” includes any “Permitted Senior Debt Hedging Instrument.””

(l)amending the definition of “Restricted Payment” in Section 1.3 (Definitions) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Security and Accounts Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

““Restricted Payment” means (a) any dividend or other distribution by the Borrower (in cash, property of the Borrower, securities, obligations, or other property) on, or other dividends or distributions on account of, or the setting apart of money for a sinking or other analogous fund for, or the purchase, redemption, retirement or other acquisition by the Borrower of, any portion of any membership interest in the Borrower and (b) all payments (in cash, property of the Borrower, securities, obligations, or other property) of principal of, interest on and other amounts with respect to, or other payments on account of, or the setting apart of money for a sinking or other analogous fund for, or the purchase, redemption, retirement or other acquisition by the Borrower of, any Indebtedness owed to Holdco or any other Person party to a

6

pledge agreement or any Affiliate thereof, including any Subordinated Debt. Restricted Payments shall not include payments to the Manager for fees and costs pursuant to Management Services Agreements and fees and costs payable pursuant to the Gas and Power Supply Services Agreement and payments to the Operator pursuant to the O&M Agreements (which shall be paid in accordance with Section 4.7 (Cash Waterfall) of the Common Security and Account Agreement); Permitted Payments (which shall be paid in accordance with Section 4.7 (Cash Waterfall) of the Common Security and Account Agreement); Senior Debt proceeds applied in accordance with amounts paid in accordance with Section 2.7 (Stage 3 Senior Debt/Equity Ratio at Stage 3 Completion Date) (Reimbursements of Equity Funding) of the Common Terms Agreement; and any of the payments in (a) or (b) above (whether in cash, securities, obligations or otherwise) made among any of the Loan Parties.”

(m)Amending paragraph (d) of the definition of “Subsequent Material Project Agreement” in Section 1.3 (Definitions) of Schedule A (Common Definitions and Rules of Interpretation) to the Common Security and Accounts Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

(d)    any contract, agreement, letter agreement or other instrument (other than a Real Property Document) that is not otherwise expressly covered by clauses (a), (b), (c), (e), (f) or (g) of this definition that, (i) contains obligations and liabilities that are in excess of $100 million over its term (including after taking into account all amendments, amendments and restatements, supplements, or waivers to any such contract, agreement, letter agreement or other instrument) and (ii) is for a term that is greater than 10 years under this clause (d); provided that the following shall not constitute Subsequent Material Project Agreements: (A) any construction contracts entered into following the Stage 3 Closing Date, until such time as any Loan Party has entered into construction contracts following the Stage 3 Closing Date that contain obligations and liabilities which in the aggregate are equal to at least $100 million, (B) any LNG SPAs that are not Qualifying LNG SPAs and any guarantee thereof, (C) prior to the incurrence of any Expansion Senior Debt following the Stage 3 Closing Date, any contract, agreement, letter agreement or other instrument containing obligations or liabilities which is not effective by its terms unless and until the Expansion Senior Debt is incurred, (D) any Gas supply contracts (other than any Linked GSA-SPA), and (E) any agreements related solely to the Stage 3 Development except any Qualifying LNG SPAs and any agreements with Affiliates that otherwise meet the thresholds set forth in this clause (d), and (F) any guarantees provided

7

by a Loan Party in support of another Loan Party in connection with a Material Project Agreement;

Section 2. Effectiveness. This First Amendment shall be effective upon (x) the receipt by the Intercreditor Agent of executed counterparts of this First Amendment by the Company and each Guarantor and (y) the execution of this First Amendment by the Intercreditor Agent.

Section 3. Finance Document. This First Amendment constitutes a Finance Document as such term is defined in, and for purposes of, the Common Terms Agreement

Section 4. GOVERNING LAW. THIS FIRST AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, UNITED STATES WITHOUT REGARD TO CONFLICTS OF LAWS PRINCIPLES THEREOF THAT WOULD RESULT IN THE APPLICATION OF THE LAW OF ANY OTHER JURISDICTION.

Section 5. Headings. All headings in this First Amendment are included only for convenience and ease of reference and shall not be considered in the construction and interpretation of any provision hereof.

Section 6. Binding Nature and Benefit. This First Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted transfers and assigns.

Section 7. Counterparts. This First Amendment may be executed in multiple counterparts, each of which shall be deemed an original and all of which, when taken together, shall constitute one agreement. Delivery of an executed signature page of this First Amendment by facsimile or other electronic transmission (e.g., “pdf” or “tif”) shall be effective as delivery of a manually executed counterpart hereof. Any signature to this First Amendment may be delivered by facsimile, electronic mail (including pdf) or any electronic signature complying with the U.S. federal ESIGN Act of 2000 or the New York Electronic Signature and Records Act or other transmission method and any counterpart so delivered shall be deemed to have been duly and validly delivered and be valid and effective for all purposes to the fullest extent permitted by applicable law.

Section 8. No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Common Security and Account Agreement shall continue unchanged and shall remain in full force and effect. Each amendment granted herein shall apply solely to the matters set forth herein and such amendment shall not be deemed or construed as an amendment of any other matters, nor shall such amendment apply to any other matters.

[Signature pages follow]

8

IN WITNESS WHEREOF, the parties have caused this First Amendment to the Common Security and Account Agreement to be duly executed and delivered as of the day and year first above written.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC,as the Company
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CORPUS CHRISTI LIQUEFACTION, LLC, as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CHENIERE CORPUS CHRISTI PIPELINE, L.P., as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CORPUS CHRISTI PIPELINE GP, LLC, as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

Signature Page to First Amendment to

Second A&R Common Security and Account Agreement

IN WITNESS WHEREOF, the parties have caused this First Amendment to the Common Security and Account Agreement to be duly executed and delivered as of the day and year first above written.

SOCIÉTÉ GÉNÉRALE,
as Security Trustee

By: /s/ Kevin Soucy

Name: Kevin Soucy

Title: Director

Signature Page to First Amendment to

Second A&R Common Security and Account Agreement

    IN WITNESS WHEREOF, the parties have caused this First Amendment to the Common Security and Account Agreement to be duly executed and delivered as of the day and year first above written.

SOCIÉTÉ GÉNÉRALE,
as Intercreditor Agent, on its own behalf and on behalf of the Intercreditor Parties, solely for purposes of consenting to the Security Trustee’s execution of the amendment pursuant to Section 7.2(a)(i) of the Common Security and Account Agreement

By: /s/ Kevin Soucy

Name: Kevin Soucy

Title: Director

Signature Page to First Amendment to

Second A&R Common Security and Account Agreement

EX-10.7

Exhibit 10.7

FIRST AMENDMENT TO
SECOND A&R WORKING CAPITAL FACILITY AGREEMENT

This First Amendment, dated as of April 19, 2024 (the “First Amendment”), amends the Second Amended and Restated Working Capital Facility Agreement, dated as of June 15, 2022 (as amended, amended and restated, modified or supplemented from time to time, the “Working Capital Facility Agreement”), by and among Cheniere Corpus Christi Holdings, LLC (the “Borrower”), Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P. and Corpus Christi Pipeline GP, LLC (the “Guarantors” and, together with the Borrower, the “Loan Parties”), with The Bank of Nova Scotia, as Working Capital Facility Agent, the Working Capital Lenders party thereto, the Issuing Banks party thereto and the Swing Line Lenders party thereto. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Working Capital Facility Agreement.

WHEREAS, the Loan Parties wish to enter into this First Amendment; and

WHEREAS, the Working Capital Facility Agent is executing this amendment as set forth herein pursuant to Section 11.01 (Decisions; Amendments, Etc.) of the Working Capital Facility Agreement and Section 3 (Voting and Decision Making) and Section 4 (Modifications; Instructions; Other Relationships)of the Intercreditor Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained herein, and subject to the terms and conditions herein set forth, the parties hereto agree as follows:

Section 1. Amendments to Working Capital Facility Agreement. The Borrower, the Guarantors and the Working Capital Facility Agent each agree that the Working Capital Facility Agreement is hereby amended by:

(a)amending Section 8.01 (Use of Proceeds) of the Working Capital Facility Agreement by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“The Loan Parties shall use the proceeds of the Loans and Letters of Credit issued hereunder for (a) the payment of transaction fees and expenses in connection with the entry into this Agreement, (b) payment of gas purchase, transportation and storage expenses (including to meet credit support requirements under gas purchase, transportation or storage agreements), (c) funding of debt service reserves and (d) working capital and other general corporate purposes; provided that, no more than $300,000,000750,000,000may be used for the purposes set forth in clause (d) above (the “General Corporate Purposes Sublimit”).”

Section 2. Effectiveness. This First Amendment shall be effective upon (a) the receipt by the Working Capital Facility Agent of executed counterparts of this First Amendment by the Borrower and each Guarantor and (b) the execution of this First Amendment by the Working Capital Facility Agent.

Section 3. Finance Document. This First Amendment constitutes a Finance Document as such term is defined in, and for purposes of, the Common Terms Agreement.

Section 4. GOVERNING LAW. THIS FIRST AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, UNITED STATES WITHOUT REGARD TO CONFLICTS OF LAWS PRINCIPLES THEREOF THAT WOULD RESULT IN THE APPLICATION OF THE LAW OF ANY OTHER JURISDICTION.

Section 5. Headings. All headings in this First Amendment are included only for convenience and ease of reference and shall not be considered in the construction and interpretation of any provision hereof.

Section 6. Binding Nature and Benefit. This First Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted transfers and assigns.

Section 7. Counterparts. This First Amendment may be executed in multiple counterparts, each of which shall be deemed an original and all of which, when taken together, shall constitute one agreement. Delivery of an executed signature page of this First Amendment by facsimile or other electronic transmission (e.g., “pdf” or “tif”) shall be effective as delivery of a manually executed counterpart hereof. Any signature to this First Amendment may be delivered by facsimile, electronic mail (including pdf) or any electronic signature complying with the U.S. federal ESIGN Act of 2000 or the New York Electronic Signature and Records Act or other transmission method and any counterpart so delivered shall be deemed to have been duly and validly delivered and be valid and effective for all purposes to the fullest extent permitted by applicable law.

Section 8. No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Working Capital Facility Agreement shall continue unchanged and shall remain in full force and effect. Each amendment granted herein shall apply solely to the matters set forth herein and such amendment shall not be deemed or construed as an amendment of any other matters, nor shall such amendment apply to any other matters.

[Signature pages follow]

2

IN WITNESS WHEREOF, the parties have caused this First Amendment to be duly executed and delivered as of the day and year first above written.

CHENIERE CORPUS CHRISTI HOLDINGS, LLC,as the Company
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CORPUS CHRISTI LIQUEFACTION, LLC, as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CHENIERE CORPUS CHRISTI PIPELINE, L.P., as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

CORPUS CHRISTI PIPELINE GP, LLC, as Guarantor
By:	/s/ Matthew Healey
	Name:	Matthew Healey
	Title:	Senior Vice President, Finance and Treasury

Signature Page To First Amendment To

Second A&R Working Capital Facility Agreement

IN WITNESS WHEREOF, the parties have caused this First Amendment to be duly executed and delivered as of the day and year first above written.

THE BANK OF NOVA SCOTIA,
as Working Capital Facility Agent on behalf of itself and the Required Working Capital Lenders

By: /s/ Joe Lattanzi

Name: Joe Lattanzi

Title: Managing Director

Signature Page To First Amendment To Second A&R Working Capital Facility Agreement

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 quarterly report on Form 10-Q 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: August 7, 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 quarterly report on Form 10-Q 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: August 7, 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 quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2024, 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: August 7, 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 quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2024, 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: August 7, 2024 

/s/ Zach Davis

Zach Davis
Chief Financial Officer of

Cheniere Energy, Inc.

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2024	Aug. 02, 2024
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2024
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 Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		226,273,139
Entity Central Index Key	0000003570
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	Q2

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Revenues
Revenues		$ 3,251	$ 4,102	$ 7,504	$ 11,412
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below)		784	912	3,020	(627)
Operating and maintenance expense		463	487	914	931
Selling, general and administrative expense		99	87	200	194
Depreciation and amortization expense		304	297	606	594
Other operating costs and expenses		13	11	22	21
Total operating costs and expenses		1,663	1,794	4,762	1,113
Income from operations		1,588	2,308	2,742	10,299
Other income (expense)
Interest expense, net of capitalized interest		(257)	(291)	(523)	(588)
Gain (loss) on modification or extinguishment of debt		(9)	(2)	(9)	18
Interest and dividend income		47	55	108	89
Other income, net		3	0	2	3
Total other expense		(216)	(238)	(422)	(478)
Income before income taxes and non-controlling interest		1,372	2,070	2,320	9,821
Less: income tax provision		210	363	319	1,679
Net income		1,162	1,707	2,001	8,142
Less: net income attributable to non-controlling interest		282	338	619	1,339
Net income attributable to Cheniere		$ 880	$ 1,369	$ 1,382	$ 6,803
Net income per share attributable to common stockholders—basic (1)	[1],[2]	$ 3.85	$ 5.65	$ 5.97	$ 27.99
Net income per share attributable to common stockholders—diluted (1)	[1],[2]	$ 3.84	$ 5.61	$ 5.96	$ 27.79
Weighted average number of common shares outstanding—basic		228.4	242.3	231.3	243.1
Weighted average number of common shares outstanding—diluted		228.9	243.8	231.9	244.8
LNG [Member]
Revenues
Revenues		$ 3,042	$ 3,919	$ 7,079	$ 11,010
Regasification [Member]
Revenues
Revenues		34	33	68	67
Other [Member]
Revenues
Revenues		$ 175	$ 150	$ 357	$ 335

[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] Earnings per share may not recalculate due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2024		Dec. 31, 2023
Current assets
Cash and cash equivalents	$ 2,442	[1]	$ 4,066
Restricted cash and cash equivalents	512	[1]	459
Trade and other receivables, net of current expected credit losses	719		1,106
Inventory	387		445
Current derivative assets	38		141
Margin deposits	105		18
Other current assets, net	133		96
Total current assets	4,336		6,331
Property, plant and equipment, net of accumulated depreciation	33,079		32,456
Operating lease assets	2,845		2,641
Derivative assets	1,151		863
Deferred tax assets	26		26
Other non-current assets, net	841		759
Total assets	42,278	[1]	43,076
Current liabilities
Accounts payable	124		181
Accrued liabilities	1,706		1,780
Current debt, net of unamortized debt issuance costs	798		300
Deferred revenue	125		179
Current operating lease liabilities	637		655
Current derivative liabilities	803		750
Other current liabilities	43		43
Total current liabilities	4,236		3,888
Long-term debt, net of unamortized discount and debt issuance costs	22,590		23,397
Operating lease liabilities	2,200		1,971
Finance lease liabilities	506		467
Derivative liabilities	2,153		2,378
Deferred tax liabilities	1,576		1,545
Other non-current liabilities	419		410
Total liabilities	33,680		34,056
Redeemable non-controlling interest	6		0
Stockholders’ equity
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; 278.5 million shares and 277.9 million shares issued at June 30, 2024 and December 31, 2023, respectively	1		1
Treasury stock: 51.5 million shares and 40.9 million shares at June 30, 2024 and December 31, 2023, respectively, at cost	(5,568)		(3,864)
Additional paid-in-capital	4,406		4,377
Retained earnings	5,625		4,546
Total Cheniere stockholders’ equity	4,464		5,060
Non-controlling interest	4,128		3,960
Total stockholders’ equity	8,592		9,020
Total liabilities, redeemable non-controlling interest and stockholders’ equity	$ 42,278	[1]	$ 43,076

[1] Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP, as further discussed in Note 6—Non-Controlling Interests and Variable Interest Entities. As of June 30, 2024, total assets and liabilities of our VIEs were $17.4 billion and $18.2 billion, respectively, including $351 million of cash and cash equivalents and $79 million of restricted cash and cash equivalents.

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Consolidated Balance Sheets Parentheticals - USD ($) $ in Millions	Jun. 30, 2024		Dec. 31, 2023
Assets	$ 42,278	[1]	$ 43,076
Liabilities	33,680		34,056
Cash and cash equivalents	2,442	[1]	4,066
Restricted cash and cash equivalents	$ 512	[1]	$ 459
Preferred Stock, Par Value	$ 0.0001		$ 0.0001
Preferred Stock, Shares Authorized	5,000,000.0		5,000,000.0
Preferred Stock, Shares Issued	0		0
Common Stock, Par Value Per Share	$ 0.003		$ 0.003
Common stock, Shares Authorized	480,000,000.0		480,000,000.0
Common Stock, Shares, Issued	278,500,000		277,900,000
Treasury Stock
Treasury Stock, Common	51,500,000		40,900,000
Variable Interest Entities [Member]
Assets	$ 17,387		$ 17,740
Liabilities	18,226		18,805
Cash and cash equivalents	351		575
Restricted cash and cash equivalents	$ 79		$ 56

[1] Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP, as further discussed in Note 6—Non-Controlling Interests and Variable Interest Entities. As of June 30, 2024, total assets and liabilities of our VIEs were $17.4 billion and $18.2 billion, respectively, including $351 million of cash and cash equivalents and $79 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	Common Stock Dividend Paid [Member]	Common Stock Dividend Declared [Member]	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Non-controlling Interest	Redeemable Noncontrolling Interest
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2022			245,500
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2022						31,200
Stockholders' Equity, Beginning of Period at Dec. 31, 2022		$ (171)	$ 1			$ (2,342)	$ 4,314	$ (4,942)	$ 2,798
Redeemable non-controlling interest at Dec. 31, 2022										$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of share-based compensation awards, shares			1,000			0
Vesting of share-based compensation awards		0	$ 0			$ 0	0	0	0
Share-based compensation		43	$ 0			$ 0	43	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		(55)	$ 0			$ (26)	(29)	0	0
Shares repurchased, at cost, shares			(3,100)			3,100
Shares repurchased, at cost		(453)	$ 0			$ (453)	0	0	0
Net income		6,435	0			0	0	5,434	1,001
Distributions to non-controlling interest		(261)	0			0	0	0	(261)
Dividends declared		(98)	$ 0			$ 0	0	(98)	0
Common Stock, Shares, Outstanding, End of Period at Mar. 31, 2023			243,200
Treasury Stock, Shares, End of Period at Mar. 31, 2023						34,500
Stockholders' Equity, End of Period at Mar. 31, 2023		5,440	$ 1			$ (2,821)	4,328	394	3,538
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Mar. 31, 2023										0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared			$ 0.395
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2022			245,500
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2022						31,200
Stockholders' Equity, Beginning of Period at Dec. 31, 2022		$ (171)	$ 1			$ (2,342)	4,314	(4,942)	2,798
Redeemable non-controlling interest at Dec. 31, 2022										0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares repurchased, at cost, shares		5,360
Net income		$ 8,142
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2023			240,900
Treasury Stock, Shares, End of Period at Jun. 30, 2023						36,800
Stockholders' Equity, End of Period at Jun. 30, 2023		6,492	$ 1			$ (3,162)	4,363	1,666	3,624
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Jun. 30, 2023										0
Common Stock, Shares, Outstanding, Beginning of Period at Mar. 31, 2023			243,200
Treasury Stock, Shares, Beginning of Period at Mar. 31, 2023						34,500
Stockholders' Equity, Beginning of Period at Mar. 31, 2023		5,440	$ 1			$ (2,821)	4,328	394	3,538
Redeemable non-controlling interest at Mar. 31, 2023										0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation		36	$ 0			$ 0	36	0	0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock			0
Issued shares withheld from employees related to share-based compensation, at cost, shares, treasury shares						0
Issued shares withheld from employees related to share-based compensation, at cost		$ (1)	$ 0			$ 0	(1)	0	0
Shares repurchased, at cost, shares		2,300	(2,300)			2,300
Shares repurchased, at cost		$ (341)	$ 0			$ (341)	0	0	0
Net income		1,707	0			0	0	1,369	338
Distributions to non-controlling interest		(252)	0			0	0	0	(252)
Dividends declared		(97)	$ 0			$ 0	0	(97)	0
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2023			240,900
Treasury Stock, Shares, End of Period at Jun. 30, 2023						36,800
Stockholders' Equity, End of Period at Jun. 30, 2023		6,492	$ 1			$ (3,162)	4,363	1,666	3,624
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Jun. 30, 2023										0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared			$ 0.395
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2023			237,000
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2023						40,900
Stockholders' Equity, Beginning of Period at Dec. 31, 2023		9,020	$ 1			$ (3,864)	4,377	4,546	3,960
Redeemable non-controlling interest at Dec. 31, 2023		0								0	[1]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of share-based compensation awards, shares			600			0
Vesting of share-based compensation awards		0	$ 0			$ 0	0	0	0
Share-based compensation		34	$ 0			$ 0	34	0	0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock			0
Issued shares withheld from employees related to share-based compensation, at cost, shares, treasury shares						0
Issued shares withheld from employees related to share-based compensation, at cost		(40)	$ 0			$ 0	(40)	0	0
Shares repurchased, at cost, shares			(7,500)			7,500
Shares repurchased, at cost		(1,203)	$ 0			$ (1,203)	0	0	0
Net income		839	0			0	0	502	337
Contributions from redeemable non-controlling interest	[1]									4
Distributions to non-controlling interest		(253)	0			0	0	0	(253)
Dividends declared		(103)	$ 0			$ 0	0	(103)	0
Common Stock, Shares, Outstanding, End of Period at Mar. 31, 2024			230,100
Treasury Stock, Shares, End of Period at Mar. 31, 2024						48,400
Stockholders' Equity, End of Period at Mar. 31, 2024		8,294	$ 1			$ (5,067)	4,371	4,945	4,044
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Mar. 31, 2024	[1]									4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared			$ 0.435
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2023			237,000
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2023						40,900
Stockholders' Equity, Beginning of Period at Dec. 31, 2023		9,020	$ 1			$ (3,864)	4,377	4,546	3,960
Redeemable non-controlling interest at Dec. 31, 2023		$ 0								0	[1]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares repurchased, at cost, shares		10,660
Net income		$ 2,001
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2024			227,000
Treasury Stock, Shares, End of Period at Jun. 30, 2024						51,500
Stockholders' Equity, End of Period at Jun. 30, 2024		8,592	$ 1			$ (5,568)	4,406	5,625	4,128
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Jun. 30, 2024		6								6	[1]
Common Stock, Shares, Outstanding, Beginning of Period at Mar. 31, 2024			230,100
Treasury Stock, Shares, Beginning of Period at Mar. 31, 2024						48,400
Stockholders' Equity, Beginning of Period at Mar. 31, 2024		8,294	$ 1			$ (5,067)	4,371	4,945	4,044
Redeemable non-controlling interest at Mar. 31, 2024	[1]									4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation		36	$ 0			$ 0	36	0	0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock			0
Issued shares withheld from employees related to share-based compensation, at cost, shares, treasury shares						0
Issued shares withheld from employees related to share-based compensation, at cost		$ (1)	$ 0			$ 0	(1)	0	0
Shares repurchased, at cost, shares		3,140	(3,100)			3,100
Shares repurchased, at cost		$ (501)	$ 0			$ (501)	0	0	0
Net income		1,162	0			0	0	880	282
Contributions from redeemable non-controlling interest	[1]									2
Distributions to non-controlling interest		(198)	0			0	0	0	(198)
Dividends declared		(200)	$ 0			$ 0	0	(200)	0
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2024			227,000
Treasury Stock, Shares, End of Period at Jun. 30, 2024						51,500
Stockholders' Equity, End of Period at Jun. 30, 2024		8,592	$ 1			$ (5,568)	$ 4,406	$ 5,625	$ 4,128
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Jun. 30, 2024		$ 6								$ 6	[1]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared				$ 0.435	$ 0.435

[1] Redeemable non-controlling interest represents the economic interest held by a third party in one of our consolidated VIEs that is redeemable for cash under certain circumstances, including those that are outside of our control. As such, the economic interest is not a component of permanent equity on our Consolidated Balance Sheets

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Cash flows from operating activities
Net income	$ 2,001	$ 8,142
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized foreign currency exchange loss (gain), net	3	(2)
Depreciation and amortization expense	606	594
Share-based compensation expense	92	85
Amortization of discount and debt issuance costs	19	23
Reduction of right-of-use assets	330	315
Loss (gain) on modification or extinguishment of debt	9	(18)
Total gains on derivative instruments, net	(393)	(5,411)
Net cash provided by (used for) settlement of derivative instruments	36	(102)
Deferred taxes	41	1,581
Other, net	8	6
Changes in operating assets and liabilities:
Trade and other receivables	387	1,249
Inventory	56	418
Margin deposits	(88)	98
Accounts payable and accrued liabilities	(324)	(1,551)
Total deferred revenue	(41)	(78)
Total operating lease liabilities	(324)	(305)
Other, net	(56)	(44)
Net cash provided by operating activities	2,362	5,000
Cash flows from investing activities
Property, plant and equipment, net	(1,153)	(1,044)
Investment in equity method investments	(12)	(18)
Other	(20)	(6)
Net cash used in investing activities	(1,185)	(1,068)
Cash flows from financing activities
Proceeds from issuances of debt	2,725	1,397
Redemptions, repayments and repurchases of debt	(3,021)	(1,098)
Distributions to non-controlling interest	(451)	(513)
Payments related to tax withholdings for share-based compensation	(41)	(56)
Repurchase of common stock	(1,699)	(774)
Dividends to stockholders	(202)	(195)
Other, net	(57)	(14)
Net cash used in financing activities	(2,746)	(1,253)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	(2)	3
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	(1,571)	2,682
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	4,525	2,487
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$ 2,954	$ 5,169

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Nature of Operations and Basis of Presentation

6 Months Ended

Jun. 30, 2024

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 large interstate and intrastate pipelines (the “Creole Trail Pipeline”). As of June 30, 2024, 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”) consisting of 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 large interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the existing assets 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 potential expansion projects. 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.

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 of Regulation S-X and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. Accordingly, these Consolidated Financial Statements do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

Results of operations for the three and six months ended June 30, 2024 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2024.

Recent Accounting Standards

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 a 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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Trade and Other Receivables, Net of Current Expected Credit Losses

6 Months Ended

Jun. 30, 2024

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):

	June 30,		December 31,
	2024		2023
Trade receivables
SPL and CCL	$	431	$	525
Cheniere Marketing	212		451
Other	4		4
Other receivables	72		126
Total trade and other receivables, net of current expected credit losses	$	719	$	1,106

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Inventory

6 Months Ended

Jun. 30, 2024

Inventory Disclosure [Abstract]

Inventory

INVENTORY

Inventory consisted of the following (in millions):

	June 30,		December 31,
	2024		2023
Materials	$	213	$	207
LNG	75		88
LNG in-transit	73		112
Natural gas	24		35
Other	2		3
Total inventory	$	387	$	445

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Property, Plant and Equipment, Net of Accumulated Depreciation

6 Months Ended

Jun. 30, 2024

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):

	June 30,		December 31,
	2024		2023
Terminal and related assets
Terminal and interconnecting pipeline facilities	$	34,154	$	34,069
Land	464		463
Construction-in-process	4,555		3,480
Accumulated depreciation	(6,668)		(6,099)
Total terminal and related assets, net of accumulated depreciation	32,505		31,913
Fixed assets and other
Computer and office equipment	39		37
Furniture and fixtures	31		31
Computer software	128		125
Leasehold improvements	44		43
Other	22		21
Accumulated depreciation	(191)		(183)
Total fixed assets and other, net of accumulated depreciation	73		74
Assets under finance leases
Marine assets	583		532
Accumulated depreciation	(82)		(63)
Total assets under finance leases, net of accumulated depreciation	501		469
Property, plant and equipment, net of accumulated depreciation	$	33,079	$	32,456

Depreciation expense was $303 million and $295 million during the three months ended June 30, 2024 and 2023, respectively, and $603 million and $591 million during the six months ended June 30, 2024 and 2023, respectively.

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Derivative Instruments

6 Months Ended

Jun. 30, 2024

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments:

•commodity derivatives consisting of the following (collectively, “Commodity Derivatives”):

◦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”); and,

◦LNG derivatives in which we have contractual net settlement and economic hedges on the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”); 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 that are required to be measured at fair value on a recurring basis, distinguished by the fair value hierarchy levels prescribed by GAAP (in millions):

	Fair Value Measurements as of
	June 30, 2024								December 31, 2023
	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)	$	(24)	$	—	$	(1,729)	$	(1,753)	$	25	$	36	$	(2,178)	$	(2,117)
LNG Trading Derivatives asset (liability)	(11)		(6)		—		(17)		30		(20)		—		10
FX Derivatives asset (liability)	—		3		—		3		—		(17)		—		(17)

We value the 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 the 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 satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

The Level 3 fair value measurements of our natural gas positions within the 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 the Level 3 Liquefaction Supply Derivatives as of June 30, 2024:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(1,729)	Market approach incorporating present value techniques	Henry Hub basis spread	$(2.063) - $0.445 / $(0.107)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	23% - 394% / 175%

(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 the Liquefaction Supply Derivatives.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Balance, beginning of period	$	(2,457)	$	(5,426)	$	(2,178)	$	(9,924)
Realized and change in fair value gains included in net income (1):
Included in cost of sales, existing deals (2)	617		635		164		4,518
Included in cost of sales, new deals (3)	7		3		5		9
Purchases and settlements:
Purchases (4)	—		—		—		—
Settlements (5)	104		175		280		780
Transfers out of level 3 (6)	—		2		—		6
Balance, end of period	$	(1,729)	$	(4,611)	$	(1,729)	$	(4,611)
Favorable changes in fair value relating to instruments still held at the end of the period	$	624	$	638	$	169	$	4,527

(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the 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.

(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.

Commodity Derivatives

We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of June 30, 2024, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence or accelerate upon the satisfaction of certain events or development of infrastructure to support natural gas gathering and transport.

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 Commodity Derivatives:

	June 30, 2024		December 31, 2023
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,520	—	14,019	49

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both June 30, 2024 and 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)	Three Months Ended June 30,				Six Months Ended June 30,
		2024		2023		2024		2023
LNG Trading Derivatives	LNG revenues	$	1	$	(46)	$	17	$	15
LNG Trading Derivatives	Recovery (cost) of sales	(1)		(3)		(20)		(87)
Liquefaction Supply Derivatives (2)	LNG revenues	2		(1)		2		(6)
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales	647		826		379		5,497

(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 the 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 $214 million and $789 million as of June 30, 2024 and December 31, 2023, 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	Three Months Ended June 30,				Six Months Ended June 30,
		2024		2023		2024		2023
FX Derivatives	LNG revenues	$	2	$	(6)	$	15	$	(8)

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

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.

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

	June 30, 2024
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	33	$	2	$	3	$	38
Derivative assets	1,151		—		—		1,151
Total derivative assets	1,184		2		3		1,189
Current derivative liabilities	(784)		(19)		—		(803)
Derivative liabilities	(2,153)		—		—		(2,153)
Total derivative liabilities	(2,937)		(19)		—		(2,956)
Derivative asset (liability), net	$	(1,753)	$	(17)	$	3	$	(1,767)
	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)

(1)Does not include collateral posted with counterparties by us of $49 million and $3 million as of June 30, 2024 and December 31, 2023, respectively, which is included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of zero and $4 million as of June 30, 2024 and December 31, 2023, respectively, which is included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $56 million and $15 million, as of June 30, 2024 and December 31, 2023, respectively, which is included in margin deposits on our Consolidated Balance Sheets, and

collateral posted by counterparties to us of zero and $3 million as of June 30, 2024 and December 31, 2023, respectively, which is 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 June 30, 2024
Gross assets	$	1,536	$	20	$	4
Offsetting amounts	(352)		(18)		(1)
Net assets (1)	$	1,184	$	2	$	3
Gross liabilities	$	(3,064)	$	(33)	$	—
Offsetting amounts	127		14		—
Net liabilities (2)	$	(2,937)	$	(19)	$	—
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)

(1)Includes current and non-current derivative assets of $38 million and $1,151 million, respectively, as of June 30, 2024 and $141 million and $863 million, respectively, as of December 31, 2023.

(2)Includes current and non-current derivative liabilities of $803 million and $2,153 million, respectively, as of June 30, 2024 and $750 million and $2,378 million, respectively, as of December 31, 2023.

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Non-Controlling Interest and Variable Interest Entity

6 Months Ended

Jun. 30, 2024

Noncontrolling Interest and Variable Interest Entity [Abstract]

Non-Controlling Interest and Variable Interest Entity

NON-CONTROLLING INTERESTS AND VARIABLE INTEREST ENTITIES

When we consolidate our VIEs, we include 100% of the assets, liabilities, revenues and expenses of the VIE in our Consolidated Financial Statements; however, when our ownership is less than 100%, we record a non-controlling interest as a component of equity or redeemable non-controlling interest 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 interests is reported as net income attributable to non-controlling interest on our Consolidated Statements of Operations.

Substantially all of our consolidated VIEs’ assets and liabilities relate to CQP. We own a 48.6% limited partner interest in CQP, and we also own all of the 2% general partner interest and 100% of the incentive distribution rights in CQP. The remaining 49.4% non-controlling limited partner interest in CQP is held by affiliates of Blackstone Inc. and Brookfield Asset Management, Inc. (“Brookfield”) as well as the public.

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

	June 30,		December 31,
	2024		2023
ASSETS
Current assets
Cash and cash equivalents	$	351	$	575
Restricted cash and cash equivalents	79		56
Trade and other receivables, net of current expected credit losses	291		373
Other current assets, net	260		215
Total current assets	981		1,219
Property, plant and equipment, net of accumulated depreciation	16,108		16,212
Other non-current assets, net	298		309
Total assets	$	17,387	$	17,740
LIABILITIES
Current liabilities
Accrued liabilities	$	684	$	811
Current debt, net of discount and debt issuance costs	798		300
Current derivative liabilities	235		196
Other current liabilities	138		201
Total current liabilities	1,855		1,508
Long-term debt, net of unamortized discount and debt issuance costs	14,803		15,606
Derivative liabilities	1,319		1,531
Other non-current liabilities	249		160
Total liabilities	$	18,226	$	18,805

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Accrued Liabilities

6 Months Ended

Jun. 30, 2024

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	June 30,		December 31,
	2024		2023
Natural gas purchases	$	552	$	729
Interest costs and related debt fees	362		399
Terminal and related asset costs	271		235
Tax-related liabilities	190		68
Compensation and benefits	152		266
Accrued dividends	101		3
LNG purchases	48		23
Other accrued liabilities	30		57
Total accrued liabilities	$	1,706	$	1,780

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Debt

6 Months Ended

Jun. 30, 2024

Debt Disclosure [Abstract]

Debt

DEBT

Debt consisted of the following (in millions): 

	June 30,		December 31,
	2024		2023
SPL:
Senior Secured Notes:
5.750% due 2024	$	—	$	300
5.625% due 2025	800		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	8,932		10,432
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	8,932		10,432
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	1,400		1,400
5.750% due 2034	1,200		—
Total CQP Senior Notes	6,800		5,600
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	6,800		5,600
CCH:
Senior Secured Notes:
5.875% due 2025	—		1,491
5.125% due 2027	1,201		1,201
3.700% due 2029	1,125		1,125
3.788% weighted average rate due 2039	2,539		2,539
Total CCH Senior Secured Notes	4,865		6,356
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”)	—		—
Total debt - CCH	4,865		6,356
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
5.650% Senior Notes due 2034	1,500		—
Total Cheniere Senior Notes	3,000		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	3,000		1,500
Total debt	23,597		23,888
Current debt, net of unamortized debt issuance costs	(798)		(300)
Unamortized discount and debt issuance costs	(209)		(191)
Total long-term debt, net of unamortized discount and debt issuance costs	$	22,590	$	23,397

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of June 30, 2024 (in millions):

	SPL Revolving Credit Facility		CQP Revolving Credit Facility		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	238		—		—		110		—
Available commitment	$	762	$	1,000	$	3,260	$	1,390	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (1)	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 (1)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365%
Maturity date	June 23, 2028		June 23, 2028		(2)		June 15, 2027		October 28, 2026

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

(2)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.

In addition, as of June 30, 2024, Cheniere Marketing had trade finance facilities with no outstanding borrowings and $65 million in standby letters of credit and bank guarantees issued.

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.

As of June 30, 2024, 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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Total interest cost	$	309	$	319	$	620	$	640
Capitalized interest	(52)		(28)		(97)		(52)
Total interest expense, net of capitalized interest	$	257	$	291	$	523	$	588

Fair Value Disclosures

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

	June 30, 2024				December 31, 2023
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,597	$	22,569	$	23,888	$	23,062

(1)As of both June 30, 2024 and December 31, 2023, $3.0 billion of the fair value of our senior notes was 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 the fair value 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

6 Months Ended

Jun. 30, 2024

Leases [Abstract]

Leases

LEASES

We are the lessee of LNG vessels leased under time charters (“vessel charters”) as well as tug vessels, office space and facilities, land sites and other equipment. All of our leases where we are the lessee are classified as operating leases except for certain of our vessel charters, tug vessels and other equipment, which are classified as finance leases.

Future annual minimum lease payments for operating and finance leases as of June 30, 2024 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2024	$	409	$	35
2025	671		72
2026	538		75
2027	441		77
2028	287		73
Thereafter	932		355
Total lease payments (1)	3,278		687
Less: Interest	(441)		(140)
Present value of lease liabilities	$	2,837	$	547

(1)Does not include approximately $3.3 billion of legally binding minimum payments for leases executed as of June 30, 2024 that will commence in future periods, consisting primarily of vessel charters, 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:

	June 30, 2024		December 31, 2023
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.8	9.3	6.3	9.7
Weighted-average discount rate (1)	5.0%	7.5%	4.7%	7.7%

(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):

	Six Months Ended June 30,
	2024		2023
Right-of-use assets obtained in exchange for operating lease liabilities (1)	$	568	$	177
Right-of-use assets obtained in exchange for finance lease liabilities (2)	74		5

(1)Includes $15 million reclassified from finance leases to operating leases during the six months ended June 30, 2024, as a result of modifications of the underlying tug vessel leases.

(2)Includes $33 million reclassified from operating leases to finance leases during the six months ended June 30, 2024, as a result of modifications of the underlying tug vessel leases.

LNG Vessel Subleases

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Fixed income	$	67	$	97	$	165	$	231
Variable income	12		13		18		36
Total sublease income	$	79	$	110	$	183	$	267

Future annual minimum sublease payments to be received from LNG vessel subleases as of June 30, 2024 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2024	$	78
2025	13
Total sublease payments	$	91

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Revenues

6 Months Ended

Jun. 30, 2024

Revenue from Contract with Customer [Abstract]

Revenues

REVENUES

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)	$	3,037	$	3,972	$	7,045	$	11,009
Regasification revenues	34		33		68		67
Other revenues (1)	76		42		151		70
Total revenues from contracts with customers	3,147		4,047		7,264		11,146
Net derivative gain (loss) (see Note 5)	5		(53)		34		1
Sublease income (see Note 9)	79		110		183		267
Other revenues	20		(2)		23		(2)
Total revenues	$	3,251	$	4,102	$	7,504	$	11,412

(1)Includes revenues from LNG vessel subcharters that do not qualify as leases for accounting purposes.

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):

	June 30,		December 31,
	2024		2023
Contract assets, net of current expected credit losses	$	298	$	250

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

	Six Months Ended June 30, 2024
Deferred revenue, beginning of period	$	294
Cash received but not yet recognized in revenue	128
Revenue recognized from prior period deferral	(154)
Deferred revenue, end of period	$	268

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:

	June 30, 2024			December 31, 2023
	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)	$	107.8	9	$	111.0	9
Regasification revenues	0.6		3	0.7		3
Total revenues	$	108.4		$	111.7

(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 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.

The following potential future sources of revenue are omitted from the table above under exemptions we have elected: (1) all performance obligations that are part of a contract that has an original expected duration of one year or less and (2) substantially all variable consideration under our SPAs and TUAs as well as 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 are contractually 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:

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
LNG revenues	50	%	64	%	56	%	73	%
Regasification revenues	8	%	7	%	8	%	7	%

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Related Party Transactions

6 Months Ended

Jun. 30, 2024

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (1)	$	2	$	2	$	4	$	5
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	3		2		5		4
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (2)	16		14		29		30

(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.

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):

	June 30,		December 31,
	2024		2023
Trade and other receivables, net of current expected credit losses	$	2	$	3
Accrued liabilities	5		6

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Income Taxes

6 Months Ended

Jun. 30, 2024

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

We recorded an income tax provision of $210 million and $319 million during the three and six months ended June 30, 2024, respectively, and an income tax provision of $363 million and $1.7 billion for the same periods of 2023, respectively, which was calculated using the annual effective tax rate method.

Our effective tax rate was 15.3% and 13.8% for the three and six months ended June 30, 2024, respectively, as compared to 17.5% and 17.1% for the same periods of 2023, respectively. The effective tax rate for the periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is not taxable to us.

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Net Income Per Share Attributable to Common Stockholders

6 Months Ended

Jun. 30, 2024

Earnings Per Share [Abstract]

Net Income Per Share Attributable to Common Stockholders

NET INCOME 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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Net income attributable to Cheniere	$	880	$	1,369	$	1,382	$	6,803
Weighted average common shares outstanding:
Basic	228.4		242.3		231.3		243.1
Dilutive unvested stock	0.5		1.5		0.6		1.7
Diluted	228.9		243.8		231.9		244.8
Net income per share attributable to common stockholders—basic (1)	$	3.85	$	5.65	$	5.97	$	27.99
Net income per share attributable to common stockholders—diluted (1)	$	3.84	$	5.61	$	5.96	$	27.79

(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 June 17, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on August 16, 2024 to stockholders of record as of the close of business on August 9, 2024.

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Share Repurchase Programs

6 Months Ended

Jun. 30, 2024

Equity [Abstract]

Share Repurchase Programs

SHARE REPURCHASE PROGRAMS

The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Total shares repurchased	3.14		2.30		10.66		5.36
Weighted average price paid per share	$	158.00	$	146.56	$	158.31	$	146.90
Total cost of repurchases (1)	$	496	$	337	$	1,688	$	788

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

As of June 30, 2024, we had approximately $4.5 billion remaining under our share repurchase program, subsequent to authorization by our Board of Directors to increase our previous authorization by $4.0 billion on June 14, 2024. Our share repurchase program authorization is effective through December 31, 2027.

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Customer Concentration

6 Months Ended

Jun. 30, 2024

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
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2024	2023	2024	2023	2024	2023
Customer A	*	*	*	*	19%	13%
Customer B	11%	*	11%	*	*	*

* Less than 10%

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2024

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended June 30,
	2024		2023
Cash paid during the period for interest on debt, net of amounts capitalized	$	499	$	685
Cash paid for income taxes, net	21		54
Non-cash investing activity (1):
Unpaid purchases of property, plant and equipment, net	229		53
Non-cash financing activity (1):
Unpaid excise taxes on repurchase of common stock	15		6
Unpaid repurchase on common stock	—		13
Unpaid dividends on common stock	99		2

(1)Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.

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Pay vs Performance Disclosure - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Pay vs Performance Disclosure
Net income (loss) attributable to common stockholders	$ 880	$ 1,369	$ 1,382	$ 6,803

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Insider Trading Arrangements	3 Months Ended
	Jun. 30, 2024
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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Nature of Operations and Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2024

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 of Regulation S-X and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. Accordingly, these Consolidated Financial Statements do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

Results of operations for the three and six months ended June 30, 2024 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2024.

Recent Accounting Standards

Recent Accounting Standards

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 a 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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Trade and Other Receivables, Net of Current Expected Credit Losses (Tables)

6 Months Ended

Jun. 30, 2024

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):

	June 30,		December 31,
	2024		2023
Trade receivables
SPL and CCL	$	431	$	525
Cheniere Marketing	212		451
Other	4		4
Other receivables	72		126
Total trade and other receivables, net of current expected credit losses	$	719	$	1,106

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Inventory (Tables)

6 Months Ended

Jun. 30, 2024

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of the following (in millions):

	June 30,		December 31,
	2024		2023
Materials	$	213	$	207
LNG	75		88
LNG in-transit	73		112
Natural gas	24		35
Other	2		3
Total inventory	$	387	$	445

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Property, Plant and Equipment, Net of Accumulated Depreciation (Tables)

6 Months Ended

Jun. 30, 2024

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):

	June 30,		December 31,
	2024		2023
Terminal and related assets
Terminal and interconnecting pipeline facilities	$	34,154	$	34,069
Land	464		463
Construction-in-process	4,555		3,480
Accumulated depreciation	(6,668)		(6,099)
Total terminal and related assets, net of accumulated depreciation	32,505		31,913
Fixed assets and other
Computer and office equipment	39		37
Furniture and fixtures	31		31
Computer software	128		125
Leasehold improvements	44		43
Other	22		21
Accumulated depreciation	(191)		(183)
Total fixed assets and other, net of accumulated depreciation	73		74
Assets under finance leases
Marine assets	583		532
Accumulated depreciation	(82)		(63)
Total assets under finance leases, net of accumulated depreciation	501		469
Property, plant and equipment, net of accumulated depreciation	$	33,079	$	32,456

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2024

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 that are required to be measured at fair value on a recurring basis, distinguished by the fair value hierarchy levels prescribed by GAAP (in millions):

	Fair Value Measurements as of
	June 30, 2024								December 31, 2023
	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)	$	(24)	$	—	$	(1,729)	$	(1,753)	$	25	$	36	$	(2,178)	$	(2,117)
LNG Trading Derivatives asset (liability)	(11)		(6)		—		(17)		30		(20)		—		10
FX Derivatives asset (liability)	—		3		—		3		—		(17)		—		(17)

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of June 30, 2024:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(1,729)	Market approach incorporating present value techniques	Henry Hub basis spread	$(2.063) - $0.445 / $(0.107)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	23% - 394% / 175%

(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 the Level 3 Liquefaction Supply Derivatives (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Balance, beginning of period	$	(2,457)	$	(5,426)	$	(2,178)	$	(9,924)
Realized and change in fair value gains included in net income (1):
Included in cost of sales, existing deals (2)	617		635		164		4,518
Included in cost of sales, new deals (3)	7		3		5		9
Purchases and settlements:
Purchases (4)	—		—		—		—
Settlements (5)	104		175		280		780
Transfers out of level 3 (6)	—		2		—		6
Balance, end of period	$	(1,729)	$	(4,611)	$	(1,729)	$	(4,611)
Favorable changes in fair value relating to instruments still held at the end of the period	$	624	$	638	$	169	$	4,527

(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the 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.

(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):

	June 30, 2024
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	33	$	2	$	3	$	38
Derivative assets	1,151		—		—		1,151
Total derivative assets	1,184		2		3		1,189
Current derivative liabilities	(784)		(19)		—		(803)
Derivative liabilities	(2,153)		—		—		(2,153)
Total derivative liabilities	(2,937)		(19)		—		(2,956)
Derivative asset (liability), net	$	(1,753)	$	(17)	$	3	$	(1,767)
	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)

(1)Does not include collateral posted with counterparties by us of $49 million and $3 million as of June 30, 2024 and December 31, 2023, respectively, which is included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of zero and $4 million as of June 30, 2024 and December 31, 2023, respectively, which is included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $56 million and $15 million, as of June 30, 2024 and December 31, 2023, respectively, which is included in margin deposits on our Consolidated Balance Sheets, and

collateral posted by counterparties to us of zero and $3 million as of June 30, 2024 and December 31, 2023, respectively, which is 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 June 30, 2024
Gross assets	$	1,536	$	20	$	4
Offsetting amounts	(352)		(18)		(1)
Net assets (1)	$	1,184	$	2	$	3
Gross liabilities	$	(3,064)	$	(33)	$	—
Offsetting amounts	127		14		—
Net liabilities (2)	$	(2,937)	$	(19)	$	—
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)

(1)Includes current and non-current derivative assets of $38 million and $1,151 million, respectively, as of June 30, 2024 and $141 million and $863 million, respectively, as of December 31, 2023.

(2)Includes current and non-current derivative liabilities of $803 million and $2,153 million, respectively, as of June 30, 2024 and $750 million and $2,378 million, respectively, as of December 31, 2023.

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 Commodity Derivatives:

	June 30, 2024		December 31, 2023
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,520	—	14,019	49

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both June 30, 2024 and 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)	Three Months Ended June 30,				Six Months Ended June 30,
		2024		2023		2024		2023
LNG Trading Derivatives	LNG revenues	$	1	$	(46)	$	17	$	15
LNG Trading Derivatives	Recovery (cost) of sales	(1)		(3)		(20)		(87)
Liquefaction Supply Derivatives (2)	LNG revenues	2		(1)		2		(6)
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales	647		826		379		5,497

(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 the 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	Three Months Ended June 30,				Six Months Ended June 30,
		2024		2023		2024		2023
FX Derivatives	LNG revenues	$	2	$	(6)	$	15	$	(8)

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Non-Controlling Interest and Variable Interest Entity (Tables)

6 Months Ended

Jun. 30, 2024

Variable Interest Entities [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 our consolidated VIEs, which are included in our Consolidated Balance Sheets. The assets in the table below may only be used to settle obligations of the respective VIEs. In addition, there is no recourse to us for the consolidated VIEs’ liabilities. The assets and liabilities in the table below include third party assets and liabilities of the VIEs only and exclude intercompany balances between the respective VIEs and Cheniere that eliminate in our Consolidated Financial Statements.

	June 30,		December 31,
	2024		2023
ASSETS
Current assets
Cash and cash equivalents	$	351	$	575
Restricted cash and cash equivalents	79		56
Trade and other receivables, net of current expected credit losses	291		373
Other current assets, net	260		215
Total current assets	981		1,219
Property, plant and equipment, net of accumulated depreciation	16,108		16,212
Other non-current assets, net	298		309
Total assets	$	17,387	$	17,740
LIABILITIES
Current liabilities
Accrued liabilities	$	684	$	811
Current debt, net of discount and debt issuance costs	798		300
Current derivative liabilities	235		196
Other current liabilities	138		201
Total current liabilities	1,855		1,508
Long-term debt, net of unamortized discount and debt issuance costs	14,803		15,606
Derivative liabilities	1,319		1,531
Other non-current liabilities	249		160
Total liabilities	$	18,226	$	18,805

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Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2024

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following (in millions): 

	June 30,		December 31,
	2024		2023
Natural gas purchases	$	552	$	729
Interest costs and related debt fees	362		399
Terminal and related asset costs	271		235
Tax-related liabilities	190		68
Compensation and benefits	152		266
Accrued dividends	101		3
LNG purchases	48		23
Other accrued liabilities	30		57
Total accrued liabilities	$	1,706	$	1,780

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Debt (Tables)

6 Months Ended

Jun. 30, 2024

Debt Disclosure [Abstract]

Schedule of Debt Instruments

Debt consisted of the following (in millions): 

	June 30,		December 31,
	2024		2023
SPL:
Senior Secured Notes:
5.750% due 2024	$	—	$	300
5.625% due 2025	800		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	8,932		10,432
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	8,932		10,432
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	1,400		1,400
5.750% due 2034	1,200		—
Total CQP Senior Notes	6,800		5,600
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	6,800		5,600
CCH:
Senior Secured Notes:
5.875% due 2025	—		1,491
5.125% due 2027	1,201		1,201
3.700% due 2029	1,125		1,125
3.788% weighted average rate due 2039	2,539		2,539
Total CCH Senior Secured Notes	4,865		6,356
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”)	—		—
Total debt - CCH	4,865		6,356
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
5.650% Senior Notes due 2034	1,500		—
Total Cheniere Senior Notes	3,000		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	3,000		1,500
Total debt	23,597		23,888
Current debt, net of unamortized debt issuance costs	(798)		(300)
Unamortized discount and debt issuance costs	(209)		(191)
Total long-term debt, net of unamortized discount and debt issuance costs	$	22,590	$	23,397

Schedule of Line of Credit Facilities and Delayed Draw Term Loan

Below is a summary of our committed credit facilities outstanding as of June 30, 2024 (in millions):

	SPL Revolving Credit Facility		CQP Revolving Credit Facility		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	238		—		—		110		—
Available commitment	$	762	$	1,000	$	3,260	$	1,390	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (1)	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 (1)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365%
Maturity date	June 23, 2028		June 23, 2028		(2)		June 15, 2027		October 28, 2026

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

(2)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.

In addition, as of June 30, 2024, Cheniere Marketing had trade finance facilities with no outstanding borrowings and $65 million in standby letters of credit and bank guarantees issued.

Schedule of Interest Expense

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Total interest cost	$	309	$	319	$	620	$	640
Capitalized interest	(52)		(28)		(97)		(52)
Total interest expense, net of capitalized interest	$	257	$	291	$	523	$	588

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):

	June 30, 2024				December 31, 2023
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,597	$	22,569	$	23,888	$	23,062

(1)As of both June 30, 2024 and December 31, 2023, $3.0 billion of the fair value of our senior notes was 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 the fair value 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)

6 Months Ended

Jun. 30, 2024

Leases [Abstract]

Schedule of Maturity of Lease Liabilities

Future annual minimum lease payments for operating and finance leases as of June 30, 2024 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2024	$	409	$	35
2025	671		72
2026	538		75
2027	441		77
2028	287		73
Thereafter	932		355
Total lease payments (1)	3,278		687
Less: Interest	(441)		(140)
Present value of lease liabilities	$	2,837	$	547

(1)Does not include approximately $3.3 billion of legally binding minimum payments for leases executed as of June 30, 2024 that will commence in future periods, consisting primarily of vessel charters, 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:

	June 30, 2024		December 31, 2023
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.8	9.3	6.3	9.7
Weighted-average discount rate (1)	5.0%	7.5%	4.7%	7.7%

(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):

	Six Months Ended June 30,
	2024		2023
Right-of-use assets obtained in exchange for operating lease liabilities (1)	$	568	$	177
Right-of-use assets obtained in exchange for finance lease liabilities (2)	74		5

(1)Includes $15 million reclassified from finance leases to operating leases during the six months ended June 30, 2024, as a result of modifications of the underlying tug vessel leases.

(2)Includes $33 million reclassified from operating leases to finance leases during the six months ended June 30, 2024, as a result of modifications of the underlying tug vessel leases.

Schedule of Sublease Income

The following table shows the sublease income recognized in other revenues on our Consolidated Statements of Operations (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Fixed income	$	67	$	97	$	165	$	231
Variable income	12		13		18		36
Total sublease income	$	79	$	110	$	183	$	267

Sublease Payment to be Received, Fiscal Year Maturity

Future annual minimum sublease payments to be received from LNG vessel subleases as of June 30, 2024 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2024	$	78
2025	13
Total sublease payments	$	91

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Revenues (Tables)

6 Months Ended

Jun. 30, 2024

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)	$	3,037	$	3,972	$	7,045	$	11,009
Regasification revenues	34		33		68		67
Other revenues (1)	76		42		151		70
Total revenues from contracts with customers	3,147		4,047		7,264		11,146
Net derivative gain (loss) (see Note 5)	5		(53)		34		1
Sublease income (see Note 9)	79		110		183		267
Other revenues	20		(2)		23		(2)
Total revenues	$	3,251	$	4,102	$	7,504	$	11,412

(1)Includes revenues from LNG vessel subcharters that do not qualify as leases for accounting purposes.

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):

	June 30,		December 31,
	2024		2023
Contract assets, net of current expected credit losses	$	298	$	250

Contract Liabilities

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

	Six Months Ended June 30, 2024
Deferred revenue, beginning of period	$	294
Cash received but not yet recognized in revenue	128
Revenue recognized from prior period deferral	(154)
Deferred revenue, end of period	$	268

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:

	June 30, 2024			December 31, 2023
	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)	$	107.8	9	$	111.0	9
Regasification revenues	0.6		3	0.7		3
Total revenues	$	108.4		$	111.7

(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 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:

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
LNG revenues	50	%	64	%	56	%	73	%
Regasification revenues	8	%	7	%	8	%	7	%

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2024

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (1)	$	2	$	2	$	4	$	5
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	3		2		5		4
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (2)	16		14		29		30

(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.

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):

	June 30,		December 31,
	2024		2023
Trade and other receivables, net of current expected credit losses	$	2	$	3
Accrued liabilities	5		6

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Net Income Per Share Attributable to Common Stockholders (Tables)

6 Months Ended

Jun. 30, 2024

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Net income attributable to Cheniere	$	880	$	1,369	$	1,382	$	6,803
Weighted average common shares outstanding:
Basic	228.4		242.3		231.3		243.1
Dilutive unvested stock	0.5		1.5		0.6		1.7
Diluted	228.9		243.8		231.9		244.8
Net income per share attributable to common stockholders—basic (1)	$	3.85	$	5.65	$	5.97	$	27.99
Net income per share attributable to common stockholders—diluted (1)	$	3.84	$	5.61	$	5.96	$	27.79

(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.

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Share Repurchase Programs (Tables)

6 Months Ended

Jun. 30, 2024

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):

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Total shares repurchased	3.14		2.30		10.66		5.36
Weighted average price paid per share	$	158.00	$	146.56	$	158.31	$	146.90
Total cost of repurchases (1)	$	496	$	337	$	1,688	$	788

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

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Customer Concentration (Tables)

6 Months Ended

Jun. 30, 2024

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
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2024	2023	2024	2023	2024	2023
Customer A	*	*	*	*	19%	13%
Customer B	11%	*	11%	*	*	*

* Less than 10%

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2024

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Six Months Ended June 30,
	2024		2023
Cash paid during the period for interest on debt, net of amounts capitalized	$	499	$	685
Cash paid for income taxes, net	21		54
Non-cash investing activity (1):
Unpaid purchases of property, plant and equipment, net	229		53
Non-cash financing activity (1):
Unpaid excise taxes on repurchase of common stock	15		6
Unpaid repurchase on common stock	—		13
Unpaid dividends on common stock	99		2

(1)Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.

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Nature of Operations and Basis of Presentation (Details)	6 Months Ended
	Jun. 30, 2024 milliontonnes / yr item unit mi 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	2.00%
Limited Partner ownership percentage	48.60%
Incentive Distribution Right Ownership Percentage	100.00%
CQP [Member] | Cheniere [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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Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Accounts and Other Receivables [Line Items]
Other receivables	$ 72	$ 126
Total trade and other receivables, net of current expected credit losses	719	1,106
SPL and CCL
Accounts and Other Receivables [Line Items]
Trade receivables	431	525
Cheniere Marketing
Accounts and Other Receivables [Line Items]
Trade receivables	212	451
Other
Accounts and Other Receivables [Line Items]
Trade receivables	$ 4	$ 4

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Inventory (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Inventory [Line Items]
Inventory	$ 387	$ 445
Materials [Member]
Inventory [Line Items]
Inventory	213	207
LNG [Member]
Inventory [Line Items]
Inventory	75	88
LNG in-transit [Member]
Inventory [Line Items]
Inventory	73	112
Natural gas [Member]
Inventory [Line Items]
Inventory	24	35
Other [Member]
Inventory [Line Items]
Inventory	$ 2	$ 3

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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	Jun. 30, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 33,079	$ 32,456
Terminal and related assets [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(6,668)	(6,099)
Property, plant and equipment, net of accumulated depreciation	32,505	31,913
Terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	34,154	34,069
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	464	463
Construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	4,555	3,480
Fixed assets and other [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(191)	(183)
Property, plant and equipment, net of accumulated depreciation	73	74
Computer and office equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	39	37
Furniture and fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	31	31
Computer software [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	128	125
Leasehold improvements [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	44	43
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	22	21
Assets under finance leases [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	583	532
Accumulated depreciation	(82)	(63)
Property, plant and equipment, net of accumulated depreciation	$ 501	$ 469

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Property, Plant and Equipment, Net of Accumulated Depreciation - Depreciation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 303	$ 295	$ 603	$ 591

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Derivative Instruments - Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Instruments in Hedges, at Fair Value, Net	$ 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	$ 214	$ 789
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	Jun. 30, 2024	Dec. 31, 2023
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (1,753)	$ (2,117)
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	(24)	25
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	0	36
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	(1,729)	(2,178)
LNG Trading Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(17)	10
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	(11)	30
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	(6)	(20)
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	3	(17)
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	3	(17)
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] - USD ($)		6 Months Ended
		Jun. 30, 2024	Dec. 31, 2023
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Net Fair Value Liabilities		$ (1,753,000,000)	$ (2,117,000,000)
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Net Fair Value Liabilities		(1,729,000,000)	$ (2,178,000,000)
Valuation, Market Approach [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	[1]	(2.063)
Valuation, Market Approach [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	[1]	0.445
Valuation, Market Approach [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	[1]	$ (0.107)
Valuation Technique, Option Pricing Model [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	23.00%
Valuation Technique, Option Pricing Model [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	394.00%
Valuation Technique, Option Pricing Model [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	175.00%

[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		3 Months Ended		6 Months Ended
		Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Fair Value, Assets (Liabilities) Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (2,457)	$ (5,426)	$ (2,178)	$ (9,924)
Realized and change in fair value gains (losses) included in net income:
Included in cost of sales, existing deals	[1],[2]	617	635	164	4,518
Included in cost of sales, new deals	[1],[3]	7	3	5	9
Purchases and settlements:
Purchases	[4]	0	0	0	0
Settlements	[5]	104	175	280	780
Transfers out of level 3	[6]	0	2	0	6
Balance, end of period		(1,729)	(4,611)	(1,729)	(4,611)
Favorable changes in fair value relating to instruments still held at the end of the period		$ 624	$ 638	$ 169	$ 4,527

[1] Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the 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.

[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		Jun. 30, 2024	Dec. 31, 2023
Liquefaction Supply Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	[1]	13,520	14,019
LNG Trading Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		0	49

[1] Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both June 30, 2024 and December 31, 2023.

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 5	$ (53)	$ 34	$ 1
LNG Trading Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	1	(46)	17	15
LNG Trading Derivatives [Member] | Recovery (cost) of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	(1)	(3)	(20)	(87)
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	2	(1)	2	(6)
Liquefaction Supply Derivatives [Member] | Recovery (cost) of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	647	826	379	5,497
FX Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 2	$ (6)	$ 15	$ (8)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Revenues	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 the 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		Jun. 30, 2024	Dec. 31, 2023
Derivatives, Fair Value [Line Items]
Current derivative assets		$ 38	$ 141
Derivative assets		1,151	863
Total derivative assets		1,189	1,004
Current derivative liabilities		(803)	(750)
Derivative liabilities		(2,153)	(2,378)
Total derivative liabilities		(2,956)	(3,128)
Derivative asset (liability), net		$ (1,767)	$ (2,124)
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]	$ 33	$ 49
Derivative assets	[1]	1,151	863
Total derivative assets	[1]	1,184	912
Current derivative liabilities	[1]	(784)	(651)
Derivative liabilities	[1]	(2,153)	(2,378)
Total derivative liabilities	[1]	(2,937)	(3,029)
Derivative asset (liability), net	[1]	(1,753)	(2,117)
Derivative, collateral posted by us		49	3
Derivative, collateral posted by counterparties		0	4
LNG Trading Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[2]	2	92
Derivative assets	[2]	0	0
Total derivative assets	[2]	2	92
Current derivative liabilities	[2]	(19)	(82)
Derivative liabilities	[2]	0	0
Total derivative liabilities	[2]	(19)	(82)
Derivative asset (liability), net	[2]	(17)	10
Derivative, collateral posted by us		56	15
Derivative, collateral posted by counterparties		0	3
FX Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets		3	0
Derivative assets		0	0
Total derivative assets		3	0
Current derivative liabilities		0	(17)
Derivative liabilities		0	0
Total derivative liabilities		0	(17)
Derivative asset (liability), net		$ 3	$ (17)

[1] Does not include collateral posted with counterparties by us of $49 million and $3 million as of June 30, 2024 and December 31, 2023, respectively, which is included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of zero and $4 million as of June 30, 2024 and December 31, 2023, respectively, which is included in other current liabilities on our Consolidated Balance Sheets.

[2] Does not include collateral posted with counterparties by us of $56 million and $15 million, as of June 30, 2024 and December 31, 2023, respectively, which is included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of zero and $3 million as of June 30, 2024 and December 31, 2023, respectively, which is 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		Jun. 30, 2024	Dec. 31, 2023
Derivative [Line Items]
Current derivative assets		$ 38	$ 141
Derivative assets		1,151	863
Current derivative liabilities		803	750
Derivative liabilities		2,153	2,378
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		1,536	1,272
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(352)	(360)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	1,184	912
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(3,064)	(3,095)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		127	66
Derivative Assets (Liabilities), at Fair Value, Net	[2]	(2,937)	(3,029)
LNG Trading Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		20	94
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(18)	(2)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	2	92
LNG Trading Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(33)	(110)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		14	28
Derivative Assets (Liabilities), at Fair Value, Net	[2]	(19)	(82)
FX Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		4	0
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(1)	0
Derivative Assets (Liabilities), at Fair Value, Net	[1]	3	0
FX Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		0	(17)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		0	0
Derivative Assets (Liabilities), at Fair Value, Net	[2]	$ 0	$ (17)

[1] Includes current and non-current derivative assets of $38 million and $1,151 million, respectively, as of June 30, 2024 and $141 million and $863 million, respectively, as of December 31, 2023.

[2] Includes current and non-current derivative liabilities of $803 million and $2,153 million, respectively, as of June 30, 2024 and $750 million and $2,378 million, respectively, as of December 31, 2023.

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Non-Controlling Interest and Variable Interest Entity (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024		Dec. 31, 2023
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 2,442	[1]	$ 4,066
Restricted cash and cash equivalents	512	[1]	459
Trade and other receivables, net of current expected credit losses	719		1,106
Other current assets, net	133		96
Total current assets	4,336		6,331
Property, plant and equipment, net of accumulated depreciation	33,079		32,456
Other non-current assets, net	841		759
Assets	42,278	[1]	43,076
Accrued liabilities	1,706		1,780
Current debt, net of unamortized debt issuance costs	798		300
Current derivative liabilities	803		750
Other current liabilities	43		43
Total current liabilities	4,236		3,888
Long-term debt, net of unamortized discount and debt issuance costs	22,590		23,397
Derivative liabilities	2,153		2,378
Other non-current liabilities	419		410
Liabilities	$ 33,680		34,056
CQP [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Limited Partner ownership percentage	48.60%
General Partner ownership percentage	2.00%
Incentive Distribution Right Ownership Percentage	100.00%
Blackstone Inc. and Brookfield Asset Management, Inc. and the public
Noncontrolling Interest and Variable Interest Entity [Line Items]
Limited Partner ownership percentage	49.40%
Variable Interest Entities [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 351		575
Restricted cash and cash equivalents	79		56
Trade and other receivables, net of current expected credit losses	291		373
Other current assets, net	260		215
Total current assets	981		1,219
Property, plant and equipment, net of accumulated depreciation	16,108		16,212
Other non-current assets, net	298		309
Assets	17,387		17,740
Accrued liabilities	684		811
Current debt, net of unamortized debt issuance costs	798		300
Current derivative liabilities	235		196
Other current liabilities	138		201
Total current liabilities	1,855		1,508
Long-term debt, net of unamortized discount and debt issuance costs	14,803		15,606
Derivative liabilities	1,319		1,531
Other non-current liabilities	249		160
Liabilities	$ 18,226		$ 18,805

[1] Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP, as further discussed in Note 6—Non-Controlling Interests and Variable Interest Entities. As of June 30, 2024, total assets and liabilities of our VIEs were $17.4 billion and $18.2 billion, respectively, including $351 million of cash and cash equivalents and $79 million of restricted cash and cash equivalents.

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Accrued Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Accrued Liabilities, Current [Abstract]
Natural gas purchases	$ 552	$ 729
Interest costs and related debt fees	362	399
Terminal and related asset costs	271	235
Tax-related liabilities	190	68
Compensation and benefits	152	266
Accrued dividends	101	3
LNG purchases	48	23
Other accrued liabilities	30	57
Total accrued liabilities	$ 1,706	$ 1,780

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 23,597	$ 23,888
Current portion of long-term debt	(798)	(300)
Unamortized discount and debt issuance costs	(209)	(191)
Total long-term debt, net of unamortized discount and debt issuance costs	22,590	23,397
SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	8,932	10,432
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 0	300
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	$ 800	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 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	6,800	5,600
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	1,400
Debt Instrument, Interest Rate, Stated Percentage	5.95%
2034 Cheniere Energy Partners Senior Notes
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,200	0
Debt Instrument, Interest Rate, Stated Percentage	5.75%
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	4,865	6,356
2025 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 0	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	1,201
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	1,125
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	2,539
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	0	0
Cheniere Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	3,000	1,500
2028 Cheniere 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	4.625%
2034 Cheniere Senior Notes
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,500	0
Debt Instrument, Interest Rate, Stated Percentage	5.65%
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	3,000	1,500
SPL [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	8,932	10,432
CQP [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	6,800	5,600
CCH [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 4,865	$ 6,356

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Debt - Credit Facilities Table (Details) $ in Millions	6 Months Ended
	Jun. 30, 2024 USD ($) units
Line of Credit Facility [Line Items]
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio | units	1.25
Cheniere Marketing
Line of Credit Facility [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding	$ 0
Standby Letters Of Credit And Bank Guarantees [Member] | Cheniere Marketing
Line of Credit Facility [Line Items]
Letters of credit issued	65
SPL Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	1,000
Outstanding balance	0
Letters of credit issued	238
Available commitment	$ 762
Maturity date	Jun. 23, 2028
SPL Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.075%	[1]
SPL Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[1]
SPL Revolving Credit Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1]
SPL Revolving Credit Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[1]
SPL Revolving Credit Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%	[1]
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]
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]
CQP Revolving Credit Facility
Line of Credit Facility [Line Items]
Total facility size	$ 1,000
Outstanding balance	0
Letters of credit issued	0
Available commitment	$ 1,000
Maturity date	Jun. 23, 2028
CQP Revolving Credit Facility | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%	[1]
CQP Revolving Credit Facility | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[1]
CQP Revolving Credit Facility | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1]
CQP Revolving Credit Facility | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.125%	[1]
CQP Revolving Credit Facility | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%	[1]
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]
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]
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 3,260
Outstanding balance	0
Letters of credit issued	0
Available commitment	$ 3,260
Line of Credit Facility, Commitment Fee Percentage	0.525%	[1]
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%	[1]
Debt Instrument, Basis Spread on Variable Rate	1.50%	[1]
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%	[1]
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,500
Outstanding balance	0
Letters of credit issued	110
Available commitment	$ 1,390
Maturity date	Jun. 15, 2027
CCH Working Capital Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%	[1]
CCH Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.20%	[1]
CCH Working Capital Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1]
CCH Working Capital Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[1]
CCH Working Capital Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%	[1]
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%	[1]
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%	[1]
Cheniere Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,250
Outstanding balance	0
Letters of credit issued	0
Available commitment	$ 1,250
Maturity date	Oct. 28, 2026
Cheniere Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.115%	[1]
Cheniere Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.365%	[1]
Cheniere Revolving Credit Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1]
Cheniere Revolving Credit Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.075%	[1]
Cheniere Revolving Credit Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.20%	[1]
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%	[1]
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%	[1]

[1] The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Debt Disclosure [Abstract]
Total interest cost	$ 309	$ 319	$ 620	$ 640
Capitalized interest	(52)	(28)	(97)	(52)
Total interest expense, net of capitalized interest	$ 257	$ 291	$ 523	$ 588

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Jun. 30, 2024	Dec. 31, 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 23,597	$ 23,888
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		23,597	23,888
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]	22,569	23,062
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 June 30, 2024 and December 31, 2023, $3.0 billion of the fair value of our senior notes was 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 the fair value 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 - Future Minimum Payments Table (Details) $ in Millions	Jun. 30, 2024 USD ($)
Operating Leases, Future Minimum Payments
2024	$ 409
2025	671
2026	538
2027	441
2028	287
Thereafter	932
Total lease payments	3,278	[1]
Less: Interest	(441)
Present value of lease liabilities	2,837
Finance Leases, Future Minimum Payments
2024	35
2025	72
2026	75
2027	77
2028	73
Thereafter	355
Total lease payments	687	[1]
Less: Interest	(140)
Present value of lease liabilities	547
Operating Lease, Lease Not yet Commenced, Payments Due	$ 3,300
Maximum [Member]
Finance Leases, Future Minimum Payments
Operating Leases, Lease Not yet Commenced, Term of Contract	15 years

[1] Does not include approximately $3.3 billion of legally binding minimum payments for leases executed as of June 30, 2024 that will commence in future periods, consisting primarily of vessel charters, with fixed minimum lease terms of up to 15 years.

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Leases - Other Quantitative Information (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2024		Jun. 30, 2023	Dec. 31, 2023
Operating Leases
Weighted-average remaining lease term		6 years 9 months 18 days			6 years 3 months 18 days
Weighted-average discount rate	[1]	5.00%			4.70%
Finance Leases
Weighted-average remaining lease term		9 years 3 months 18 days			9 years 8 months 12 days
Weighted-average discount rate	[1]	7.50%			7.70%
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability		$ 568	[2]	$ 177
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability		74	[3]	$ 5
Right-Of-Use Asset Obtained In Exchange For Operating Lease Liability, Reclassification From Finance Lease		15
Right-Of-Use Asset Obtained In Exchange For Finance Lease Liability, Reclassification From Operating Lease		$ 33

[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 $15 million reclassified from finance leases to operating leases during the six months ended June 30, 2024, as a result of modifications of the underlying tug vessel leases.

[3] Includes $33 million reclassified from operating leases to finance leases during the six months ended June 30, 2024, as a result of modifications of the underlying tug vessel leases.

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Leases - Subleases (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Lessor, Operating Lease, Description
Sublease Income, Fixed	$ 67	$ 97	$ 165	$ 231
Sublease Income, Variable	12	13	18	36
Sublease Income, Total	79	$ 110	183	$ 267
Operating Leases, Future Minimum Payments Receivable
2024	78		78
2025	13		13
Total sublease payments	$ 91		$ 91

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Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 3,147	$ 4,047	$ 7,264	$ 11,146
Net derivative gain (loss)		5	(53)	34	1
Sublease Income		79	110	183	267
Other revenues		20	(2)	23	(2)
Total revenues		3,251	4,102	7,504	11,412
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		3,037	3,972	7,045	11,009
Total revenues		3,042	3,919	7,079	11,010
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		34	33	68	67
Total revenues		34	33	68	67
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	[1]	76	42	151	70
Total revenues		$ 175	$ 150	$ 357	$ 335

[1] Includes revenues from LNG vessel subcharters that do not qualify as leases for accounting purposes.

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Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 298	$ 250
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	294
Cash received but not yet recognized in revenue	128
Revenue recognized from prior period deferral	(154)
Deferred revenue, end of period	$ 268

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Revenues - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Jun. 30, 2024	Dec. 31, 2023
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
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 108.4
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
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	[1]	$ 107.8
Weighted Average Recognition Timing	[1],[2]	9 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
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 0.6
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 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)	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
LNG [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	50.00%	64.00%	56.00%	73.00%
Regasification [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	8.00%	7.00%	8.00%	7.00%

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Related Party Transaction [Line Items]
Revenues		$ 3,251	$ 4,102	$ 7,504	$ 11,412
Operating and maintenance expense		463	487	914	931
Trade and other receivables, net of current expected credit losses		719		719		$ 1,106
Accrued liabilities		1,706		1,706		1,780
Related Party [Member]
Related Party Transaction [Line Items]
Trade and other receivables, net of current expected credit losses		2		2		3
Accrued liabilities		5		5		$ 6
Other [Member]
Related Party Transaction [Line Items]
Revenues		175	150	357	335
Operation and Maintenance Agreement [Member] | Other [Member] | Midship Pipeline [Member]
Related Party Transaction [Line Items]
Revenues	[1]	2	2	4	5
Natural Gas Transportation and Storage Agreements [Member] | Midship Pipeline [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense	[2]	3	2	5	4
Natural Gas Transportation and Storage Agreements [Member] | Related Party through Brookfield Ownership [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense	[2]	$ 16	$ 14	$ 29	$ 30

[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.

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Income Tax Disclosure [Abstract]
Income tax provision (benefit)	$ 210	$ 363	$ 319	$ 1,679
Effective Income Tax Rate	15.30%	17.50%	13.80%	17.10%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			21.00%

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Net Income Per Share Attributable to Common Stockholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended		6 Months Ended
		Jun. 17, 2024	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Earnings Per Share [Abstract]
Net income attributable to common stockholders			$ 880	$ 1,369	$ 1,382	$ 6,803
Weighted average number of common shares outstanding, basic			228.4	242.3	231.3	243.1
Dilutive Unvested Stock			0.5	1.5	0.6	1.7
Weighted Average Number of Shares Outstanding, Diluted			228.9	243.8	231.9	244.8
Net income per share attributable to common stockholders—basic (1)	[1],[2]		$ 3.85	$ 5.65	$ 5.97	$ 27.99
Net income per share attributable to common stockholders—diluted (1)	[1],[2]		$ 3.84	$ 5.61	$ 5.96	$ 27.79
Common Stock, Dividends, Per Share, Declared		$ 0.435

[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] Earnings per share may not recalculate due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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Share Repurchase Programs - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2024	Jun. 14, 2024
Equity [Abstract]
Stock Repurchase Program, Remaining Authorized Repurchase Amount	$ 4,500
Share Repurchase, Additional Shares Authorized		$ 4,000

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Share Repurchase Programs - Schedule of Share Repurchases (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Equity [Abstract]
Total shares repurchased		3,140	2,300	10,660	5,360
Weighted average price paid per share		$ 158.00	$ 146.56	$ 158.31	$ 146.90
Total cost of repurchases	[1]	$ 496	$ 337	$ 1,688	$ 788

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

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Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2024	Jun. 30, 2024	Dec. 31, 2023
Customer A [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		19.00%	13.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%	11.00%

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2024	Jun. 30, 2023
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized		$ 499	$ 685
Cash paid for income taxes, net		21	54
Unpaid purchases of property, plant and equipment, net	[1]	229	53
Unpaid excise taxes on repurchase of common stock	[1]	15	6
Unpaid repurchase on common stock	[1]	0	13
Unpaid dividends on common stock	[1]	$ 99	$ 2

[1] Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.