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 September 30, 2023

or

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

For the transition period from            to            

Commission file number 001-16383

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

700 Milam Street, Suite 1900

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	NYSE American

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 October 26, 2023, the issuer had 238,254,866 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)	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—Restricted Cash and Cash Equivalents	9
	Note 3—Trade and Other Receivables, Net of Current Expected Credit Losses	9
	Note 4—Inventory	9
	Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation	10
	Note 6—Derivative Instruments	10
	Note 7—Non-Controlling Interest and Variable Interest Entity	15
	Note 8—Accrued Liabilities	16
	Note 9—Debt	17
	Note 10—Leases	19
	Note 11—Revenues	21
	Note 12—Related Party Transactions	23
	Note 13—Income Taxes	23
	Note 14—Net Income (Loss) per Share Attributable to Common Stockholders	24
	Note 15—Share Repurchase Programs	25
	Note 16—Customer Concentration	25
	Note 17—Supplemental Cash Flow Information	25
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	39
Part II. Other Information
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
	Signatures	42

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	billion cubic feet
Bcf/d	billion cubic feet per day
Bcf/yr	billion cubic feet per year
Bcfe	billion cubic feet equivalent
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 USD 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 index price, less a fixed liquefaction fee, shipping and other costs
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu	million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpa	million tonnes per annum
non-FTA countries	countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC	U.S. Securities and Exchange Commission
SOFR	Secured Overnight Financing Rate
SPA	LNG sale and purchase agreement
TBtu	trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA	terminal use agreement

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of September 30, 2023, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

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

2

PART I.    FINANCIAL INFORMATION 

ITEM 1.    CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues
LNG revenues	$	3,974	$	8,236	$	14,984	$	23,449
Regasification revenues	34		455		101		591
Other revenues	151		161		486		303
Total revenues	4,159		8,852		15,571		24,343
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below)	556		11,073		(71)		24,161
Operating and maintenance expense	445		419		1,376		1,227
Selling, general and administrative expense	102		92		296		265
Depreciation and amortization expense	298		280		892		827
Other	3		4		24		15
Total operating costs and expenses	1,404		11,868		2,517		26,495
Income (loss) from operations	2,755		(3,016)		13,054		(2,152)
Other income (expense)
Interest expense, net of capitalized interest	(283)		(354)		(871)		(1,060)
Gain (loss) on modification or extinguishment of debt	(3)		3		15		(43)
Interest and dividend income	58		20		147		28
Other income (expense), net	4		(49)		7		(47)
Total other expense	(224)		(380)		(702)		(1,122)
Income (loss) before income taxes and non-controlling interest	2,531		(3,396)		12,352		(3,274)
Less: income tax provision (benefit)	440		(752)		2,119		(762)
Net income (loss)	2,091		(2,644)		10,233		(2,512)
Less: net income (loss) attributable to non-controlling interest	390		(259)		1,729		(3)
Net income (loss) attributable to common stockholders	$	1,701	$	(2,385)	$	8,504	$	(2,509)
Net income (loss) per share attributable to common stockholders—basic (1)	$	7.08	$	(9.54)	$	35.12	$	(9.94)
Net income (loss) per share attributable to common stockholders—diluted (1)	$	7.03	$	(9.54)	$	34.87	$	(9.94)
Weighted average number of common shares outstanding—basic	240.2		249.9		242.1		252.5
Weighted average number of common shares outstanding—diluted	242.0		249.9		243.9		252.5
___________________
(1)Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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

3

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (1)

(in millions, except share data)

	September 30,		December 31,
	2023		2022
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	3,861	$	1,353
Restricted cash and cash equivalents	422		1,134
Trade and other receivables, net of current expected credit losses	811		1,944
Inventory	400		826
Current derivative assets	95		120
Margin deposits	73		134
Other current assets, net	107		97
Total current assets	5,769		5,608
Property, plant and equipment, net of accumulated depreciation	32,053		31,528
Operating lease assets	2,549		2,625
Derivative assets	620		35
Goodwill	77		77
Deferred tax assets	40		864
Other non-current assets, net	611		529
Total assets	$	41,719	$	41,266
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	126	$	124
Accrued liabilities	1,433		2,679
Current debt, net of discount and debt issuance costs	349		813
Deferred revenue	209		234
Current operating lease liabilities	612		616
Current derivative liabilities	991		2,301
Other current liabilities	38		28
Total current liabilities	3,758		6,795
Long-term debt, net of discount and debt issuance costs	23,389		24,055
Operating lease liabilities	1,907		1,971
Finance lease liabilities	476		494
Derivative liabilities	2,882		7,947
Deferred tax liabilities	1,178		—
Other non-current liabilities	222		175
Stockholders’ equity (deficit)
Preferred stock: $0.0001 par value, 5.0 million shares authorized, none issued	—		—
Common stock: $0.003 par value, 480.0 million shares authorized; 277.8 million shares and 276.7 million shares issued at September 30, 2023 and December 31, 2022, respectively	1		1
Treasury stock: 39.0 million shares and 31.2 million shares at September 30, 2023 and December 31, 2022, respectively, at cost	(3,522)		(2,342)
Additional paid-in-capital	4,394		4,314
Accumulated income (deficit)	3,271		(4,942)
Total Cheniere stockholders’ equity (deficit)	4,144		(2,969)
Non-controlling interest	3,763		2,798
Total stockholders’ equity (deficit)	7,907		(171)
Total liabilities and stockholders’ equity (deficit)	$	41,719	$	41,266

(1)Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 7—Non-controlling Interest and Variable Interest Entity. As of September 30, 2023, total assets and liabilities of CQP were $17.8 billion and $19.0 billion, respectively, including $499 million of cash and cash equivalents and $35 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)

(in millions)

(unaudited)

Three and Nine Months Ended September 30, 2023
	Total Stockholders’ Equity (Deficit)
	Common Stock			Treasury Stock			Additional Paid-in Capital		Accumulated Income (Deficit)		Non-controlling Interest		Total Equity (Deficit)
	Shares	Par Value Amount		Shares	Amount
Balance at December 31, 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 attributable to non-controlling interest	—	—		—	—		—		—		1,001		1,001
Distributions to non-controlling interest	—	—		—	—		—		—		(261)		(261)
Dividends declared ($0.395 per common share)	—	—		—	—		—		(98)		—		(98)
Net income attributable to common stockholders	—	—		—	—		—		5,434		—		5,434
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 attributable to non-controlling interest	—	—		—	—		—		—		338		338
Distributions to non-controlling interest	—	—		—	—		—		—		(252)		(252)
Dividends declared ($0.395 per common share)	—	—		—	—		—		(97)		—		(97)
Net income attributable to common stockholders	—	—		—	—		—		1,369		—		1,369
Balance at June 30, 2023	240.9	1		36.8	(3,162)		4,363		1,666		3,624		6,492
Vesting of share-based compensation awards	0.1	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		37		—		—		37
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	—		(6)		—		—		(6)
Shares repurchased, at cost	(2.2)	—		2.2	(360)		—		—		—		(360)
Net income attributable to non-controlling interest	—	—		—	—		—		—		390		390
Distributions to non-controlling interest	—	—		—	—		—		—		(251)		(251)
Dividends declared ($0.395 per common share)	—	—		—	—		—		(96)		—		(96)
Net income attributable to common stockholders	—	—		—	—		—		1,701		—		1,701
Balance at September 30, 2023	238.8	$	1	39.0	$	(3,522)	$	4,394	$	3,271	$	3,763	$	7,907

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

5

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)—CONTINUED

(in millions)

(unaudited)

Three and Nine Months Ended September 30, 2022
	Total Stockholders’ Deficit
	Common Stock			Treasury Stock			Additional Paid-in Capital		Accumulated Deficit		Non-controlling Interest		Total Deficit
	Shares	Par Value Amount		Shares	Amount
Balance at December 31, 2021	253.6	$	1	21.6	$	(928)	$	4,377	$	(6,021)	$	2,538	$	(33)
Vesting of share-based compensation awards	1.3	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		38		—		—		38
Issued shares withheld from employees related to share-based compensation, at cost	(0.3)	—		0.3	(35)		(18)		—		—		(53)
Shares repurchased, at cost	(0.2)	—		0.2	(25)		—		—		—		(25)
Adoption of ASU 2020-06, net of tax	—	—		—	—		(153)		4		—		(149)
Net income attributable to non-controlling interest	—	—		—	—		—		—		84		84
Distributions to non-controlling interest	—	—		—	—		—		—		(171)		(171)
Dividends declared ($0.33 per common share)	—	—		—	—		—		(85)		—		(85)
Net loss attributable to common stockholders	—	—		—	—		—		(865)		—		(865)
Balance at March 31, 2022	254.4	1		22.1	(988)		4,244		(6,967)		2,451		(1,259)
Vesting of share-based compensation awards	0.1	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		34		—		—		34
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	(1)		(1)		—		—		(2)
Shares repurchased, at cost	(4.1)	—		4.1	(540)		—		—		—		(540)
Net income attributable to non-controlling interest	—	—		—	—		—		—		172		172
Distributions to non-controlling interest	—	—		—	—		—		—		(256)		(256)
Dividends declared ($0.33 per common share)	—	—		—	—		—		(85)		—		(85)
Net income attributable to common stockholders	—	—		—	—		—		741		—		741
Balance at June 30, 2022	250.4	1		26.2	(1,529)		4,277		(6,311)		2,367		(1,195)
Vesting of share-based compensation awards	0.1	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		34		—		—		34
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	(5)		(2)		—		—		(7)
Shares repurchased, at cost	(0.6)	—		0.6	(75)		—		—		—		(75)
Net loss attributable to non-controlling interest	—	—		—	—		—		—		(259)		(259)
Distributions to non-controlling interest	—	—		—	—		—		—		(259)		(259)
Dividends declared ($0.33 per common share)	—	—		—	—		—		(84)		—		(84)
Dividends declared ($0.395 per common share)	—	—		—	—		—		(100)		—		(100)
Net loss attributable to common stockholders	—	—		—	—		—		(2,385)		—		(2,385)
Balance at September 30, 2022	249.9	$	1	26.8	$	(1,609)	$	4,309	$	(8,880)	$	1,849	$	(4,330)

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)

	Nine Months Ended September 30,
	2023		2022
Cash flows from operating activities
Net income (loss)	$	10,233	$	(2,512)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized foreign currency exchange gain, net	(2)		(10)
Depreciation and amortization expense	892		827
Share-based compensation expense	128		115
Amortization of debt issuance costs, premium and discount	34		43
Reduction of right-of-use assets	464		444
Loss (gain) on modification or extinguishment of debt	(15)		43
Total losses (gains) on derivative instruments, net	(6,839)		10,228
Net cash used for settlement of derivative instruments	(96)		(702)
Equity in losses (earnings) of unconsolidated entities	(4)		55
Deferred taxes	2,015		(856)
Other, net	7		11
Changes in operating assets and liabilities:
Trade and other receivables	1,134		(389)
Inventory	422		(426)
Margin deposits	61		498
Contract assets	11		(387)
Other current assets	(24)		57
Accounts payable and accrued liabilities	(1,261)		938
Total deferred revenue	27		91
Total operating lease liabilities	(456)		(460)
Other, net	(33)		(37)
Net cash provided by operating activities	6,698		7,571
Cash flows from investing activities
Property, plant and equipment, net	(1,430)		(1,339)
Investment in equity method investments	(36)		(10)
Other, net	(12)		1
Net cash used in investing activities	(1,478)		(1,348)
Cash flows from financing activities
Proceeds from issuances of debt	1,397		1,015
Redemptions, repayments and repurchases of debt	(2,548)		(4,005)
Debt issuance and other financing costs	(32)		(44)
Debt modification or extinguishment gains (costs)	26		(33)
Distributions to non-controlling interest	(764)		(686)
Payments related to tax withholdings for share-based compensation	(62)		(62)
Repurchase of common stock	(1,132)		(640)
Dividends to stockholders	(291)		(251)
Payments of finance lease liabilities	(20)		(1)
Net cash used in financing activities	(3,426)		(4,707)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	2		5
Net increase in cash, cash equivalents and restricted cash and cash equivalents	1,796		1,521
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	2,487		1,817
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	4,283	$	3,338

Balances per Consolidated Balance Sheet:

	September 30, 2023
Cash and cash equivalents	$	3,861
Restricted cash and cash equivalents	422
Total cash, cash equivalents and restricted cash and cash equivalents	$	4,283

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. Additionally, the Sabine Pass LNG Terminal includes a 94-mile pipeline owned by CTPL, a subsidiary of CQP, that interconnects our facilities with a number of large interstate and intrastate pipelines. As of September 30, 2023, we owned 100% of the general partner interest and a 48.6% limited partner interest in CQP.

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

We have increased available liquefaction capacity at the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) as a result of debottlenecking and other optimization projects. 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 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. In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the National Environmental Policy Act for an expansion adjacent to the SPL Project with a potential production capacity of up to 20 mtpa of LNG. 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, they 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, 2022.

Results of operations for the three and nine months ended September 30, 2023 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2023.

Recent Accounting Standards

ASU 2020-04

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 9—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities subsequent to the effective date of ASU

8

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

2020-04. We elected to apply the optional expedients as applicable to certain modified or replaced facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

NOTE 2—RESTRICTED CASH AND CASH EQUIVALENTS

As of September 30, 2023 and December 31, 2022, we had $422 million and $1.1 billion of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is restricted, primarily to the payment of liabilities related to the Liquefaction Projects, as required under certain debt arrangements.

NOTE 3—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):

	September 30,		December 31,
	2023		2022
Trade receivables
SPL and CCL	$	418	$	922
Cheniere Marketing	323		917
Other receivables	70		105
Total trade and other receivables, net of current expected credit losses	$	811	$	1,944

NOTE 4—INVENTORY

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
LNG in-transit	$	82	$	356
LNG	90		212
Materials	199		194
Natural gas	27		60
Other	2		4
Total inventory	$	400	$	826

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 5—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

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

	September 30,		December 31,
	2023		2022
LNG terminal
Terminal and interconnecting pipeline facilities	$	33,881	$	33,815
Site and related costs	461		451
Construction-in-process	2,981		1,685
Accumulated depreciation	(5,821)		(4,985)
Total LNG terminal, net of accumulated depreciation	31,502		30,966
Fixed assets and other
Computer and office equipment	36		33
Furniture and fixtures	20		20
Computer software	125		121
Leasehold improvements	69		48
Other	21		20
Accumulated depreciation	(202)		(191)
Total fixed assets and other, net of accumulated depreciation	69		51
Assets under finance leases
Marine assets	532		533
Accumulated depreciation	(50)		(22)
Total assets under finance leases, net of accumulated depreciation	482		511
Property, plant and equipment, net of accumulated depreciation	$	32,053	$	31,528

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Depreciation expense	$	296	$	278	$	887	$	822
Offsets to LNG terminal costs (1)	—		—		—		204

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

NOTE 6—DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments:

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

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

•foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with cash flows denominated in currencies other than United States 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 or fair value 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.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Fair Value Measurements as of
	September 30, 2023								December 31, 2022
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset (liability)	$	19	$	54	$	(3,216)	$	(3,143)	$	(66)	$	(29)	$	(9,924)	$	(10,019)
LNG Trading Derivatives asset (liability)	(29)		7		—		(22)		1		(47)		—		(46)
FX Derivatives asset (liability)	—		7		—		7		—		(28)		—		(28)

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

The fair value of our Liquefaction Supply Derivatives and LNG Trading Derivatives are predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

We include a significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.

The Level 3 fair value measurements of our natural gas positions within our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of September 30, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(3,216)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.245) - $0.638 / $(0.031)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	83% - 422% / 188%

(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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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Balance, beginning of period	$	(4,611)	$	(8,462)	$	(9,924)	$	(4,036)
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	1,197		(5,668)		5,350		(8,825)
Included in cost of sales, new deals (3)	8		—		26		—
Purchases and settlements:
Purchases (4)	—		4		—		(1,390)
Settlements (5)	187		322		1,323		446
Transfers out of level 3 (6)	3		(1)		9		—
Balance, end of period	$	(3,216)	$	(13,805)	$	(3,216)	$	(13,805)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	1,205	$	(5,668)	$	5,376	$	(8,825)

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

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

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

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

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

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

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

Commodity Derivatives

SPL and CCL hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The firm terms of the Liquefaction Supply Derivatives range up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.

Cheniere Marketing has historically entered into, and may from time to time enter into, LNG transactions that provide for contractual net settlement. Such transactions are accounted for as LNG Trading Derivatives along with financial

12

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

commodity contracts in the form of swaps or futures. The terms of LNG Trading Derivatives range up to approximately one year.

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

	September 30, 2023		December 31, 2022
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,542	6	14,504	50

(1)Excludes notional amounts associated with extension options that were uncertain to be taken as of September 30, 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 September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
LNG Trading Derivatives	LNG revenues	$	19	$	(237)	$	34	$	(454)
LNG Trading Derivatives	Recovery (cost) of sales	(8)		(4)		(95)		103
Liquefaction Supply Derivatives (2)	LNG revenues	1		(3)		(5)		8
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales	1,403		(5,508)		6,900		(10,008)

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

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

FX Derivatives

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

The total notional amount of our FX Derivatives was $266 million and $619 million as of September 30, 2023 and December 31, 2022, respectively.

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

		Gain Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
FX Derivatives	LNG revenues	$	13	$	54	$	5	$	121

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

	September 30, 2023
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	62	$	23	$	10	$	95
Derivative assets	620		—		—		620
Total derivative assets	682		23		10		715
Current derivative liabilities	(943)		(45)		(3)		(991)
Derivative liabilities	(2,882)		—		—		(2,882)
Total derivative liabilities	(3,825)		(45)		(3)		(3,873)
Derivative asset (liability), net	$	(3,143)	$	(22)	$	7	$	(3,158)
	December 31, 2022
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	36	$	84	$	—	$	120
Derivative assets	35		—		—		35
Total derivative assets	71		84		—		155
Current derivative liabilities	(2,143)		(130)		(28)		(2,301)
Derivative liabilities	(7,947)		—		—		(7,947)
Total derivative liabilities	(10,090)		(130)		(28)		(10,248)
Derivative liability, net	$	(10,019)	$	(46)	$	(28)	$	(10,093)

(1)Does not include collateral posted with counterparties by us of $1 million and $111 million as of September 30, 2023 and December 31, 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $1 million and zero as of September 30, 2023 and December 31, 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $72 million and $23 million, as of September 30, 2023 and December 31, 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 September 30, 2023
Gross assets	$	1,161	$	23	$	10
Offsetting amounts	(479)		—		—
Net assets (1)	$	682	$	23	$	10
Gross liabilities	$	(3,911)	$	(51)	$	(3)
Offsetting amounts	86		6		—
Net liabilities (2)	$	(3,825)	$	(45)	$	(3)
As of December 31, 2022
Gross assets	$	76	$	87	$	—
Offsetting amounts	(5)		(3)		—
Net assets (1)	$	71	$	84	$	—
Gross liabilities	$	(10,436)	$	(132)	$	(29)
Offsetting amounts	346		2		1
Net liabilities (2)	$	(10,090)	$	(130)	$	(28)

(1)Includes current and non-current derivative assets of $95 million and $620 million, respectively, as of September 30, 2023 and $120 million and $35 million, respectively, as of December 31, 2022.

(2)Includes current and non-current derivative liabilities of $991 million and $2,882 million, respectively, as of September 30, 2023 and $2,301 million and $7,947 million, respectively, as of December 31, 2022.

NOTE 7—NON-CONTROLLING INTEREST AND VARIABLE INTEREST ENTITY

CQP is accounted for as a consolidated VIE. We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. We also own 100% of the general partner interest and the incentive distribution rights in CQP.

15

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

	September 30,		December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	499	$	904
Restricted cash and cash equivalents	35		92
Trade and other receivables, net of current expected credit losses	287		627
Other current assets	225		269
Total current assets	1,046		1,892
Property, plant and equipment, net of accumulated depreciation	16,341		16,725
Other non-current assets, net	377		288
Total assets	$	17,764	$	18,905
LIABILITIES
Current liabilities
Accrued liabilities	$	646	$	1,384
Current debt, net of discount and debt issuance costs	349		—
Current derivative liabilities	294		769
Other current liabilities	217		191
Total current liabilities	1,506		2,344
Long-term debt, net of premium, discount and debt issuance costs	15,600		16,198
Derivative liabilities	1,731		3,024
Other non-current liabilities	141		98
Total liabilities	$	18,978	$	21,664

NOTE 8—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2023		2022
Natural gas purchases	$	607	$	1,621
Interest costs and related debt fees	260		383
LNG terminals and related pipeline costs	244		240
Compensation and benefits	118		245
LNG purchases	22		88
Other accrued liabilities	182		102
Total accrued liabilities	$	1,433	$	2,679

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—DEBT

Debt consisted of the following (in millions): 

	September 30,		December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.75% due 2024 (the “2024 SPL Senior Notes”)	$	350	$	2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,482		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,482		12,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
5.95% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
CCH:
Senior Secured Notes:
7.000% due 2024 (the “2024 CCH Senior Notes”)	—		498
5.875% due 2025	1,491		1,491
5.125% due 2027	1,201		1,271
3.700% due 2029	1,125		1,361
3.788% weighted average rate due 2039	2,539		2,633
Total CCH Senior Secured Notes	6,356		7,254
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”) (1)	—		—
Total debt - CCH	6,356		7,254
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		1,500
Total debt	23,938		25,086
Current debt, net of discount and debt issuance costs	(349)		(813)
Long-term portion of unamortized discount and debt issuance costs, net	(200)		(218)
Total long-term debt, net of discount and debt issuance costs	$	23,389	$	24,055

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

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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 September 30, 2023 (in millions):

	SPL Revolving Credit Facility (1)		CQP Revolving Credit Facility (1)		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility (2)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	284		—		—		155		—
Available commitment	$	716	$	1,000	$	3,260	$	1,345	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (3)	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 0.115% - 0.365%
Commitment fees on undrawn balance (3)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365% (4)
Maturity date	June 23, 2028		June 23, 2028		(5)		June 15, 2027		October 28, 2026

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

(2)In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR.

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

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

(5)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.

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 September 30, 2023, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total interest cost	$	316	$	376	$	956	$	1,118
Capitalized interest	(33)		(22)		(85)		(58)
Total interest expense, net of capitalized interest	$	283	$	354	$	871	$	1,060

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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):

	September 30, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,938	$	22,052	$	25,086	$	23,500

(1)As of September 30, 2023 and December 31, 2022, $2.8 billion and $3.0 billion, respectively, of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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

NOTE 10—LEASES

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

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

		September 30,		December 31,
	Consolidated Balance Sheets Location	2023		2022
Right-of-use assets—Operating	Operating lease assets	$	2,549	$	2,625
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	482		511
Total right-of-use assets		$	3,031	$	3,136
Current operating lease liabilities	Current operating lease liabilities	$	612	$	616
Current finance lease liabilities	Other current liabilities	35		28
Non-current operating lease liabilities	Operating lease liabilities	1,907		1,971
Non-current finance lease liabilities	Finance lease liabilities	476		494
Total lease liabilities		$	3,030	$	3,109

19

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
Operating lease cost (a)	Operating costs and expenses (1)	$	185	$	213	$	583	$	604
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	13		1		37		3
Interest on lease liabilities	Interest expense, net of capitalized interest	11		2		27		7
Total lease cost		$	209	$	216	$	647	$	614
(a) Included in operating lease cost:
Short-term lease costs		$	6	$	16	$	31	$	80
Variable lease costs		1		7		15		16

(1)Presented in cost (recovery) of sales, operating and maintenance expense or selling, general and administrative expense consistent with the use of the asset under lease.

Future annual minimum lease payments for operating and finance leases as of September 30, 2023 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2023	$	167	$	17
2024	702		67
2025	583		72
2026	450		75
2027	353		77
Thereafter	687		427
Total lease payments (1)	2,942		735
Less: Interest	(423)		(224)
Present value of lease liabilities	$	2,519	$	511

(1)Does not include approximately $4.1 billion of legally binding minimum payments primarily for vessel charters executed as of September 30, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years.

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

	September 30, 2023		December 31, 2022
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.0	9.9	5.9	10.6
Weighted-average discount rate (1)	4.5%	7.7%	4.2%	7.8%

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

20

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):

	Nine Months Ended September 30,
	2023		2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	538	$	524
Operating cash flows from finance leases	26		6
Financing cash flows from finance leases	20		1
Right-of-use assets obtained in exchange for operating lease liabilities	388		1,139
Right-of-use assets obtained in exchange for finance lease liabilities	8		23

LNG Vessel Subcharters

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Fixed income	$	96	$	122	$	327	$	188
Variable income	5		12		41		37
Total sublease income	$	101	$	134	$	368	$	225

Future annual minimum sublease payments to be received from LNG vessel subcharters as of September 30, 2023 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2023	$	76
2024	120
Thereafter	—
Total sublease payments	$	196

NOTE 11—REVENUES

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues from contracts with customers
LNG revenues	$	3,941	$	8,422	$	14,950	$	23,774
Regasification revenues	34		455		101		591
Other revenues	50		27		120		78
Total revenues from contracts with customers	4,025		8,904		15,171		24,443
Net derivative gain (loss) (1)	33		(186)		34		(325)
Other (2)	101		134		366		225
Total revenues	$	4,159	$	8,852	$	15,571	$	24,343

(1)See Note 6—Derivative Instruments for additional information about our derivatives.

(2)Includes revenues from LNG vessel subcharters. See Note 10—Leases for additional information about our subleases.

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. (“Chevron”) entered into an agreement with SPLNG providing for the early termination of the TUA and an associated terminal marine services agreement between the parties and their affiliates (the “Termination Agreement”), effective July 2022, for a lump sum fee of $765 million (the “Termination Fee”). Obligations pursuant to the TUA and associated agreement, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million

21

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

annually (adjusted for inflation) from 2023 through 2029, terminated on December 31, 2022, upon SPLNG’s receipt of the Termination Fee in December 2022. We allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which was recognized ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations.

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):

	September 30,		December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	218	$	186

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

	Nine Months Ended September 30, 2023
Deferred revenue, beginning of period	$	320
Cash received but not yet recognized in revenue	345
Revenue recognized from prior period deferral	(320)
Deferred revenue, end of period	$	345

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:

	September 30, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	112.5	9	$	112.0	9
Regasification revenues	0.7		3	0.8		4
Total revenues	$	113.2		$	112.8

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

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

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

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

22

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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	63	%	76	%	71	%	72	%
Regasification revenues	7	%	1	%	7	%	2	%

NOTE 12—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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG Revenues
Natural Gas Transportation and Storage Agreements with a related party through Brookfield Asset Management, Inc. (“Brookfield”) (1)	$	—	$	—	$	—	$	4
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (2)	2		3		7		5
Cost of sales
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	—		—		—		1
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	5		—		9		—
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	14		18		44		45

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

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

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):

	September 30,		December 31,
	2023		2022
Trade and other receivables, net of current expected credit losses	$	2	$	1
Accrued liabilities	6		1

NOTE 13—INCOME TAXES

We recorded an income tax provision of $440 million and $2.1 billion during the three and nine months ended September 30, 2023, respectively, which was calculated using the annual effective tax rate method. We recorded an income tax benefit of $752 million and $762 million during the three and nine months ended September 30, 2022, which was calculated using the year-to-date effective tax rate method.

Our effective tax rate was 17.4% and 17.2% for the three and nine months ended September 30, 2023, respectively, and 22.1% and 23.3% for the three and nine months ended September 30, 2022, respectively. The effective tax rate for the three and nine months ended September 30, 2023 represents a tax provision and was lower than the statutory rate of 21% primarily

23

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

due to CQP’s income that is not taxable to us. The effective tax rate for the three and nine months ended September 30, 2022 represents a tax benefit and was higher than the statutory rate of 21% primarily due to the foreign derived intangible income (“FDII”) deduction, which results in income from our sales to foreign customers being taxed at a lower effective tax rate. The year-to-date effective tax rate method was used for the three and nine months ended September 30, 2022 because a relatively small change in estimated ordinary income or loss caused significant changes to the estimated annual effective tax rate such that the annual effective tax rate did not provide a reliable estimate.

In August 2022, President Biden signed into U.S. federal law the Inflation Reduction Act which, among other things, introduced a new 15% corporate alternative minimum tax (“CAMT”), effective in 2023, that is based on 15% of an applicable corporation’s adjusted financial statement income (“AFSI”). A corporation is subject to the CAMT if its average AFSI over three prior years is greater than $1 billion (“Applicable Corporation”). We expect to become an Applicable Corporation beginning in 2024, but such timing is dependent on future earnings and the resultant impact of any future regulatory guidance issued by the U.S. Department of the Treasury and the Internal Revenue Service. The CAMT may accelerate and cause volatility in our cash tax payment obligations, particularly in periods of significant commodity, currency or financial market variability resulting in potential changes in the fair value of our derivative instruments.

NOTE 14—NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net income (loss) attributable to common stockholders	$	1,701	$	(2,385)	$	8,504	$	(2,509)
Weighted average common shares outstanding:
Basic	240.2		249.9		242.1		252.5
Dilutive unvested stock	1.8		—		1.8		—
Diluted	242.0		249.9		243.9		252.5
Net income (loss) per share attributable to common stockholders—basic (1)	$	7.08	$	(9.54)	$	35.12	$	(9.94)
Net income (loss) per share attributable to common stockholders—diluted (1)	$	7.03	$	(9.54)	$	34.87	$	(9.94)
Dividends paid per common share	$	0.395	$	0.33	$	1.185	$	0.99

(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 October 30, 2023, we declared a quarterly dividend of $0.435 per share of common stock that is payable on November 17, 2023 to stockholders of record as of the close of business on November 9, 2023.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Unvested stock (1)	—	2.5	—	2.3
4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) (2)	—	—	—	0.2
Total potentially dilutive common shares	—	2.5	—	2.5

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

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

24

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 15—SHARE REPURCHASE PROGRAMS

On September 7, 2021, our board of directors (our “Board”) authorized a reset in the previously existing share repurchase program to $1.0 billion, inclusive of any amounts remaining under the previous authorization as of September 30, 2021, for an additional three years beginning on October 1, 2021. On September 12, 2022, our Board authorized an increase in the existing share repurchase program by $4.0 billion for an additional three years, beginning on October 1, 2022. The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total shares repurchased	2.21		0.60		7.57		4.97
Weighted average price paid per share	$	161.98	$	125.34	$	151.29	$	128.73
Total cost of repurchases (1)	$	357	$	75	$	1,145	$	640

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

As of September 30, 2023, we had approximately $2.5 billion remaining under our share repurchase program.

NOTE 16—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 September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2023	2022	2023	2022	2023	2022
Customer A	*	*	*	*	16%	*
Customer B	*	—%	*	*	12%	—%

* Less than 10%

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2023		2022
Cash paid during the period for interest on debt, net of amounts capitalized	$	906	$	891
Cash paid for income taxes, net	85		28
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net	204		217
Share-based compensation capitalized to property, plant and equipment	3		3
Non-cash conveyance of property, plant and equipment	—		17
Commitments due to equity method investments	14		—
Contribution of other non-current assets in exchange for equity method investment	30		—
Non-cash financing activity:
Unpaid dividends declared on unvested common stock	3		5
Unpaid repurchases of treasury stock inclusive of excise taxes	22		—

See Note 10—Leases for supplemental cash flow information related to our leases.

25

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

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

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

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such

26

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, 2022. 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, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking, other industrial uses and back up for intermittent energy sources. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.

We are the largest producer of LNG in the United States and the second largest LNG operator globally, based on the total production capacity of our liquefaction facilities, which totals approximately 45 mtpa as of September 30, 2023.

We own and operate a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with CQP, which is a publicly traded limited partnership that we formed in 2007. As of September 30, 2023, we owned 100% of the general partner interest and a 48.6% limited partner interest in 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 three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth which can accommodate vessels with nominal capacity of up to 200,000 cubic meters, 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. The Sabine Pass LNG Terminal also includes a 94-mile pipeline owned by CTPL, a subsidiary of CQP, that interconnects our facilities to several interstate and intrastate pipelines (the “Creole Trail Pipeline”).

27

We also own and operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through CCL, which has natural gas liquefaction facilities consisting of three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. We also own and operate through CCP a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “CCL Project”).

Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted substantially all of our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. 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, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. Excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation, our SPAs and IPM agreements had approximately 16 years of weighted average remaining life as of September 30, 2023. We also market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases and transportation and liquefaction fuel to produce LNG, thus limiting our exposure to fluctuations in U.S. natural gas prices. We continue to grow our portfolio of SPA and IPM agreements, and we believe that continued global demand for natural gas and LNG will provide a foundation for additional growth in our portfolio of customer contracts in the future.

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 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 (“NGA”) for an expansion adjacent to the CCL Project consisting of two midscale Trains with an expected total production capacity of approximately 3 mtpa of LNG (the “CCL Midscale Trains 8 & 9 Project”). Additionally, in May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the National Environmental Policy Act (“NEPA”) for an expansion adjacent to the SPL Project with a potential production capacity of up to 20 mtpa of LNG (the “SPL Expansion Project”). The development of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

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

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Overview of Significant Events

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

Strategic

•Cheniere Marketing entered into long-term SPAs with BASF, ENN LNG (Singapore) Pte. Ltd., Equinor ASA and Korea Southern Power Co. Ltd. with estimated volumes totaling approximately 89 million tonnes of LNG and expected deliveries between 2026 and 2049. Approximately 48 million tonnes is subject to Cheniere making a positive FID on the first train of the SPL Expansion Project. Each of these SPAs permit Cheniere Marketing to assign or novate the agreement to certain affiliates at a later date.

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

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

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

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

Operational

•As of October 26, 2023, over 3,070 cumulative LNG cargoes totaling over 210 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

Financial

•We completed the following debt transactions:

◦In June 2023, CQP issued $1.4 billion aggregate principal amount of 5.95% Senior Notes due 2033 (the “2033 CQP Senior Notes”). Using contributed proceeds from the 2033 CQP Senior Notes together with cash on hand, SPL redeemed $1.4 billion of its 5.75% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) in July 2023.

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

•We received the following upgrades from credit rating agencies, each with a stable outlook:

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

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•During the three and nine months ended September 30, 2023, we accomplished the following pursuant to our capital allocation priorities:

◦We prepaid $50 million and $1.1 billion, respectively, of consolidated long-term indebtedness, which excludes prepayments associated with debt refinancing and includes zero and $600 million, respectively, of debt repurchases in the open market.

◦We repurchased approximately 2.2 million shares and 7.6 million shares, respectively, of our common stock as part of our share repurchase program for $357 million and $1.1 billion, respectively.

◦We paid dividends of $0.395 and $1.185 per share of common stock during the three and nine months ended September 30, 2023, respectively.

◦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 September 30,						Nine Months Ended September 30,
(in millions, except per share data)	2023		2022		Variance		2023		2022		Variance
Revenues
LNG revenues	$	3,974	$	8,236	$	(4,262)	$	14,984	$	23,449	$	(8,465)
Regasification revenues	34		455		(421)		101		591		(490)
Other revenues	151		161		(10)		486		303		183
Total revenues	4,159		8,852		(4,693)		15,571		24,343		(8,772)
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below)	556		11,073		(10,517)		(71)		24,161		(24,232)
Operating and maintenance expense	445		419		26		1,376		1,227		149
Selling, general and administrative expense	102		92		10		296		265		31
Depreciation and amortization expense	298		280		18		892		827		65
Other	3		4		(1)		24		15		9
Total operating costs and expenses	1,404		11,868		(10,464)		2,517		26,495		(23,978)
Income (loss) from operations	2,755		(3,016)		5,771		13,054		(2,152)		15,206
Other income (expense)
Interest expense, net of capitalized interest	(283)		(354)		71		(871)		(1,060)		189
Gain (loss) on modification or extinguishment of debt	(3)		3		(6)		15		(43)		58
Interest and dividend income	58		20		38		147		28		119
Other income (expense), net	4		(49)		53		7		(47)		54
Total other expense	(224)		(380)		156		(702)		(1,122)		420
Income (loss) before income taxes and non-controlling interest	2,531		(3,396)		5,927		12,352		(3,274)		15,626
Less: income tax provision (benefit)	440		(752)		1,192		2,119		(762)		2,881
Net income (loss)	2,091		(2,644)		4,735		10,233		(2,512)		12,745
Less: net income (loss) attributable to non-controlling interest	390		(259)		649		1,729		(3)		1,732
Net income (loss) attributable to common stockholders	$	1,701	$	(2,385)	$	4,086	$	8,504	$	(2,509)	$	11,013
Net income (loss) per share attributable to common stockholders—basic	$	7.08	$	(9.54)	$	16.62	$	35.12	$	(9.94)	$	45.06
Net income (loss) per share attributable to common stockholders—diluted	$	7.03	$	(9.54)	$	16.57	$	34.87	$	(9.94)	$	44.81

Operational volumes loaded and recognized from the Liquefaction Projects

	Three Months Ended September 30,			Nine Months Ended September 30, 2023
(in TBtu)	2023	2022	Variance	2023	2022	Variance
Volumes loaded during the current period	548	559	(11)	1,684	1,695	(11)
Volumes loaded during the prior period but recognized during the current period	26	34	(8)	56	49	7
Less: volumes loaded during the current period and in transit at the end of the period	(29)	(37)	8	(29)	(37)	8
Total volumes recognized in the current period	545	556	(11)	1,711	1,707	4

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Components of LNG revenues and corresponding LNG volumes delivered

	Three Months Ended September 30,						Nine Months Ended September 30,
	2023		2022		Variance		2023		2022		Variance
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	$	2,928	$	6,084	$	(3,156)	$	9,420	$	15,652	$	(6,232)
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	835		2,139		(1,304)		5,116		7,408		(2,292)
LNG procured from third parties	93		173		(80)		225		566		(341)
Net derivative gains (losses)	33		(186)		219		34		(325)		359
Other revenues	85		26		59		189		148		41
Total LNG revenues	$	3,974	$	8,236	$	(4,262)	$	14,984	$	23,449	$	(8,465)
Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	487		484		3		1,493		1,441		52
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	58		72		(14)		218		266		(48)
LNG procured from third parties	10		4		6		24		19		5
Total volumes delivered as LNG revenues	555		560		(5)		1,735		1,726		9

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

Net income (loss) attributable to common stockholders

The favorable variances of $4.1 billion and $11.0 billion for the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to favorable variances of $7.1 billion and $17.1 billion (before tax and the impact of non-controlling interest) between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, from changes in fair value and settlement of derivatives between the periods. The majority of the variances were due to non-cash favorable changes in fair value of our IPM agreements as a result of lower volatility in international gas prices compared to the same periods of 2022 and declines in international forward commodity curves, which changed from losses of $4.9 billion and $9.3 billion in the three and nine months ended September 30, 2022, respectively, to gains of $1.2 billion and $5.8 billion in the three and nine months ended September 30, 2023, respectively.

The favorable variances were offset by:

•unfavorable variances of $1.2 billion and $2.9 billion in income tax provision (benefit) between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022;

•favorable variances in net income or loss attributable to non-controlling interest of $649 million and $1.7 billion between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022; and

•decreases in LNG revenues, net of cost (recovery) of sales and excluding the effect of derivatives (as further described above), of $874 million and $1.3 billion between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, the majority of which was attributable to lower margins on LNG delivered.

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

Revenues

The decreases of $4.7 billion and $8.8 billion between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to:

•decreases in Henry Hub pricing, contributing $3.2 billion and $6.8 billion between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, for which the majority of our long-term contracts are indexed;

•decreases in revenues generated by our marketing function of $1.3 billion and $2.6 billion between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, due to declining international prices and a reduction of volumes sold under short-term agreements; and

•decreases in regasification revenues of $421 million and $490 million between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, due to the early termination of one of our TUA agreements in December 2022. See Note 11—Revenues of our Notes to Consolidated Financial Statements for additional information on the termination agreement.

Operating costs and expenses (recoveries)

The $10.5 billion and $24.0 billion favorable variances between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to:

•$6.9 billion and $16.7 billion favorable variances between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, from changes in fair value and settlements of derivatives included in cost of sales, from $5.5 billion and $9.9 billion of losses in the three and nine months ended September 30, 2022, respectively, to $1.4 billion and $6.8 billion of gains in the three and nine months ended September 30, 2023, respectively, primarily related to non-cash favorable changes in fair value of our IPM agreements as described above under the caption Net income (loss) attributable to common stockholders; and

•$3.6 billion and $7.5 billion decreases between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, in cost of sales excluding the effect of derivative changes described above, primarily as a result of $3.5 billion and $7.5 billion, respectively, in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.

The favorable variances were partially offset by increases in operating and maintenance expense of $26 million and $149 million for the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022. The increase in operating and maintenance expense for the nine months ended September 30, 2023 as compared to the the nine months ended September 30, 2022 was primarily due to the completion of planned large-scale maintenance activities on two trains at the SPL Project during June 2023. The increases between the three and nine months ended September 30, 2023 as compared to the same periods of 2022 were also due to other third party service and maintenance contract costs and natural gas transportation and storage capacity demand charges.

Other income (expense)

The $156 million and $420 million favorable variances between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to:

•$71 million and $189 million decreases in interest expense, net of capitalized interest, between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, primarily as a result of lower debt balances due to repayment of debt in accordance with our capital allocation plan;

•$38 million and $119 million increases in interest and dividend income between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022 attributable to higher interest income earned on cash and cash equivalents from higher interest rates in 2023; and

•$58 million favorable variance in gain (loss) on modification or extinguishment of debt between the nine months ended September 30, 2023 as compared to the same period of 2022, primarily due to higher losses recognized from the

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amendment and restatement of CCH’s term loan facility agreement (the “CCH Credit Facility”) and CCH’s working capital facility agreement (the “CCH Working Capital Facility”) during the second quarter of 2022 and the redemption of our 4.25% Convertible Senior Notes due in 2045 (the “2045 Cheniere Convertible Senior Notes”) during the first quarter of 2022. Further contributing to the favorable variance during the nine months ended September 30, 2023 was a reduction in premiums paid for the early redemption or repayment of debt principal, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

Income tax provision (benefit)

The $1.2 billion and $2.9 billion unfavorable variances between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to an increase in pre-tax income.

Our effective tax rate was 17.4% and 17.2% for the three and nine months ended September 30, 2023, respectively, and 22.1% and 23.3% for the three and nine months ended September 30, 2022, respectively. The effective tax rate for the three and nine months ended September 30, 2023 represents a tax provision and was lower than the statutory rate of 21% primarily due to CQP’s income that is not taxable to us. The effective tax rate for the three and nine months ended September 30, 2022 represents a tax benefit and was higher than the statutory rate of 21% primarily due to the foreign derived intangible income (“FDII”) deduction, which results in income from our sales to foreign customers being taxed at a lower effective tax rate. The year-to-date effective tax rate method was used for the three and nine months ended September 30, 2022 because a relatively small change in estimated ordinary income or loss caused significant changes to the estimated annual effective tax rate such that the annual effective tax rate did not provide a reliable estimate.

Net income (loss) attributable to non-controlling interest

The $649 million and $1.7 billion increase between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, was primarily attributable to $1.3 billion and $3.4 billion favorable variances in CQP’s consolidated net income or loss between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments, which in addition to managing exposure to commodity-related marketing and price risks are utilized to manage exposure to changing interest rates and foreign exchange volatility, are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Because 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, 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, notwithstanding the operational intent to mitigate risk exposure over time.

Commissioning cargoes

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the nine months ended September 30, 2022, we realized offsets to LNG terminal costs of $204 million corresponding to 15 TBtu attributable to the sale of commissioning cargoes from Train 6 of the SPL Project. We did not have any commissioning cargoes during the three months ended September 30, 2022 or the three and nine months ended September 30, 2023.

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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.

	September 30, 2023
Cash and cash equivalents (1)	$	3,861
Restricted cash and cash equivalents (1)	422
Available commitments under our credit facilities (2):
SPL Revolving Credit Facility	716
CQP Revolving Credit Facility	1,000
CCH Credit Facility	3,260
CCH Working Capital Facility	1,345
Cheniere’s revolving credit agreement (the “Cheniere Revolving Credit Facility”)	1,250
Total available commitments under our credit facilities	7,571
Total available liquidity	$	11,854

(1)Amounts presented include balances held by our consolidated variable interest entity, CQP, and its subsidiaries, as discussed in Note 7—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of September 30, 2023, assets of CQP and its subsidiaries, which are included in our Consolidated Balance Sheets, included $499 million of cash and cash equivalents and $35 million of restricted cash and cash equivalents.

(2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of September 30, 2023. See Note 9—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to September 30, 2023 will be driven by future sources of liquidity and future cash requirements. Future sources of liquidity are expected to be composed of (1) cash receipts from executed contracts, under which we are contractually entitled to future consideration, and (2) additional sources of liquidity, from which we expect to receive cash although the cash is not underpinned by executed contracts. Future cash requirements are expected to be composed of (1) cash payments under executed contracts, under which we are contractually obligated to make payments, and (2) additional cash requirements, under which we expect to make payments although we are not contractually obligated to make the payments under executed contracts. For further 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, 2022.

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

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

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

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

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

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

Corpus Christi Stage 3 Project

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of September 30, 2023:

Overall project completion percentage	44.1%
Completion percentage of:
Engineering	74.1%
Procurement	63.3%
Subcontract work	55.9%
Construction	7.5%
Date of expected substantial completion	2Q/3Q 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. 

	Nine Months Ended September 30,
	2023		2022
Net cash provided by operating activities	$	6,698	$	7,571
Net cash used in investing activities	(1,478)		(1,348)
Net cash used in financing activities	(3,426)		(4,707)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	2		5
Net increase in cash, cash equivalents and restricted cash and cash equivalents	$	1,796	$	1,521

Operating Cash Flows

The $873 million decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes from lower pricing per MMBtu as a result of decreased pricing and a reduction of volumes sold under short-term agreements, and regasification fees. The decrease was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.

In August 2022, President Biden signed into U.S. federal law the Inflation Reduction Act which, among other things, introduced a new 15% corporate alternative minimum tax (“CAMT”), effective in 2023, that is based on 15% of an applicable corporation’s adjusted financial statement income (“AFSI”). A corporation is subject to the CAMT if its average AFSI over three prior years is greater than $1 billion (“Applicable Corporation”). We expect to become an Applicable Corporation beginning in 2024, but such timing is dependent on future earnings and the resultant impact of any future regulatory guidance issued by the U.S. Department of the Treasury and the Internal Revenue Service. The CAMT may accelerate and cause volatility in our cash tax payment obligations, particularly in periods of significant commodity, currency or financial market variability resulting in potential changes in the fair value of our derivative instruments.

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Investing Cash Flows

Our investing net cash outflows in both years primarily were for the construction costs for the Liquefaction Projects. The $130 million increase in 2023 compared to 2022 was primarily due to $1.0 billion of cash outflows during the nine months ended September 30, 2023 related to construction of the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 2022 compared to $545 million in the comparable period of 2022, partially offset by a decrease in spend due to the completion of Train 6 of the SPL Project in February 2022. We expect our capital expenditures to increase in future periods as construction work progresses on the Corpus Christi Stage 3 Project.

Financing Cash Flows

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

	Nine Months Ended September 30,
	2023		2022
Proceeds from issuances of debt	$	1,397	$	1,015
Redemptions, repayments and repurchases of debt	(2,548)		(4,005)
Debt issuance and other financing costs	(32)		(44)
Debt modification or extinguishment gains (costs)	26		(33)
Distributions to non-controlling interest	(764)		(686)
Repurchase of common stock	(1,132)		(640)
Dividends to stockholders	(291)		(251)
Other, net	(82)		(63)
Net cash used in financing activities	$	(3,426)	$	(4,707)

Debt Issuances

During the nine months ended September 30, 2023, CQP issued an aggregate principal amount of $1.4 billion of 2033 CQP Senior Notes, the proceeds of which were used with cash on hand to redeem $1.4 billion of the 2024 SPL Senior Notes. Additionally, during the nine months ended September 30, 2023, SPL purchased $200 million of the 2024 SPL Senior Notes in the open market and redeemed an additional $50 million of the 2024 SPL Senior Notes, which leaves only $350 million to be repaid for debt maturing in 2024. During the nine months ended September 30, 2022, we had total borrowings of $575 million on the Cheniere Revolving Credit Facility and $440 million on the CCH Credit Facility. The proceeds from the borrowings during the nine months ended September 30, 2022, together with cash on hand, were used to redeem or repurchase $4.0 billion of outstanding indebtedness, entirely associated with redemptions of our outstanding notes or repayment of amounts outstanding under our credit facilities.

37

Debt Redemptions, Repayments and Repurchases

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

	Nine Months Ended September 30,
	2023		2022
Redemptions, repayments and repurchases of debt
SPL:
2024 SPL Senior Notes	$	(1,650)	$	—
CCH:
CCH Credit Facility	—		(2,169)
CCH Working Capital Facility	—		(250)
7.000% Senior Notes due 2024	(498)		—
5.125% Senior Notes due 2027	(69)		—
3.700% Senior Notes due 2029	(237)		(8)
2.742% Senior Notes due 2039	(94)		—
3.788% weighted average Senior Notes rate due 2039	—		(17)
Cheniere:
2045 Cheniere Convertible Senior Notes	—		(500)
Cheniere Revolving Credit Facility	—		(575)
4.625% Senior Secured Notes due 2028	—		(486)
Total redemptions, repayments and repurchases of debt	$	(2,548)	$	(4,005)

Non-Controlling Interest Distributions

We own a 48.6% limited partner interest in CQP with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. CQP paid distributions of $764 million and $686 million during the nine months ended September 30, 2023 and 2022, respectively, to non-controlling interests.

Repurchase of Common Stock

During the nine months ended September 30, 2023 and 2022, we paid $1.1 billion and $640 million to repurchase 7.6 million and 5.0 million shares of our common stock, respectively, as part of our share repurchase program. As of September 30, 2023, we had approximately $2.5 billion remaining under our share repurchase program.

Cash Dividends to Stockholders

During the nine months ended September 30, 2023, we paid aggregate dividends of $1.185 per share of common stock, for a total of $291 million paid to common stockholders. We paid aggregate dividends of $0.99 per share of common stock, for a total of $251 million during the nine months ended September 30, 2022.

On October 30, 2023, we declared a quarterly dividend of $0.435 per share of common stock that is payable on November 17, 2023 to stockholders of record as of the close of business on November 9, 2023.

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, 2022.

38

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 commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project, and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). We have also entered into physical and financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):

	September 30, 2023				December 31, 2022
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(3,143)	$	1,638	$	(10,019)	$	2,249
LNG Trading Derivatives	(22)		5		(46)		15

See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.

Foreign Currency Exchange Risk

We have entered into foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with operations in countries outside of the United States (“FX Derivatives”). In order to test the sensitivity of the fair value of the FX Derivatives to changes in FX rates, management modeled a 10% change in FX rate between the U.S. dollar and the applicable foreign currencies as follows (in millions):

	September 30, 2023				December 31, 2022
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
FX Derivatives	$	7	$	1	$	(28)	$	3

See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our foreign currency derivative instruments.

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. 

39

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, 2022, except for the update presented in our quarterly report on Form 10-Q for the quarterly period ended March 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, 2022.

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 stock repurchases for the three months ended September 30, 2023:

Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share (2)	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)
July 1 - 31, 2023	371,828	$154.49	371,828	$2,780
August 1 - 31, 2023	628,646	$163.99	628,646	$2,677
September 1 - 30, 2023	1,204,747	$163.23	1,204,747	$2,480
Total	2,205,221		2,205,221

(1)Includes issued shares surrendered to us by participants in our share-based compensation plans for payment of applicable tax withholdings on the vesting of share-based compensation awards. Associated shares surrendered by participants are repurchased pursuant to terms of the plan and award agreements and not as part of the publicly announced share repurchase plan.

(2)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.

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 September 30, 2023, none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

40

ITEM 6.    EXHIBITS

Exhibit No.
	Description
10.1*	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 8, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00076 Supplemental FERC Condition 80 Requirements, dated May 5, 2023, (ii) the Change Order CO-00077 Louisiana Sales and Use Tax Provisional Sum Closure, dated June 16, 2023, (iii) the Change Order CO-00078 Natural Gas Pipeline (NGPL) Security Coordination Provisional Sum Closure, dated June 22, 2023, (iv) the Change Order CO-00079 Insurance Provisional Sum Closure, dated July 27, 2023 and (v) the Change Order Co-00080 Borrowed Items, dated September 6, 2023
10.2*	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00036 Payment Milestone Updates (Schedule C-1), dated June 19, 2023, (ii) the Change Order CO-00037 Geotechnical Soils Investigation Period & Security Division of Responsibility Change, dated June 20, 2023, (iii) the Change Order CO-00038 Power Monitoring System (ETAP HMI), dated June 29, 2023 and (iv) the Change Order CO-00039 EFG Firewater Connection, dated June 30, 2023 (Portions of this exhibit have been omitted.)
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.

41

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:	November 1, 2023	By:	/s/ Zach Davis
			Zach Davis
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	November 1, 2023	By:	/s/ David Slack
			David Slack
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

42

EX-10.1

Exhibit 10.1

CHANGE ORDER

SUPPLEMENTAL FERC CONDITION 80 REQUIREMENTS

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. CHANGE ORDER NUMBER: CO-00076 DATE OF CHANGE ORDER: 05-May-2023 DATE OF AGREEMENT: November 7, 2018

The Agreement between the Parties listed above is changed as follows:

1.    In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), and per Owner correspondence SPL4-BE-C23-036 dated 20-Feb-2023, the Parties agree Contractor shall augment the scope as stated under Clause 1(d) of previous Change Order CO-00072 dated 31-Oct-2022, as follows:

a.    Add a sixth (6th) elevated-oscillating firewater monitor with remote manual operation capability, the implementation of which requires the relocation of three (3) of five (5) firewater monitors added in accordance with Clause 1(d) of previous Change Order CO-00072; and

b.    For context: Per Clause 1(d) of previous CO-00072, the Agreement was amended for Contractor to install five (5) firewater hydrants or monitors for the entire length of the marine transfer piping (under FERC Condition 80 and associated conditions).

2.    The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.    Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was ……………………..…......................	$	2,016,892,573
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49, 51, 53-58, 61, 68, 75)….................................................................................................................................................	$	8,116,678
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was.........................….	$	2,025,009,251
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ...............................................................................................................................................	$	0
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ...............................................................................................................................................	$	0
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be ......................	$	2,025,009,251

Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was …..….......................	$	457,696,000
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50, 52, 59-60, 62-74) ................	$	11,039,604
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ............................	$	468,735,604
10. The Contract Price Applicable to Subproject 6(b) will be changed by this change order ..................	$	165,221
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order .......	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be ...................	$	468,900,825
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) ...........	$	2,474,588,573
14. The Contract Price prior to this Change Order was (add lines 3 and 9) …………….........................	$	2,493,744,855
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) ………………………………………….......................................................................................	$	165,221
16. The new Contract Price including this Change Order will be (add lines 14 and 15) ….....................	$	2,493,910,076

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a): N/A

Adjustment to Payment Schedule for Subproject 6(a): N/A

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A – This Work is performed post-Substantial Completion

Adjustment to other Changed Criteria for Subproject 6(b): N/A – This Work is performed post-Substantial Completion

Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B

Adjustment to Design Basis for Subproject 6(b): N/A – This Work is performed post-Substantial Completion

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A – This Work is performed post-Substantial Completion

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/ LL__ Contractor _/s/ DC_ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. 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.

/s/ David Craft	/s/ Laura Link
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP, Engineering & Construction	Senior Project Manager & Principal Vice President
Title	Title
July 18, 2023	June 27, 2023
Date of Signing	Date of Signing

CHANGE ORDER

LOUISIANA SALES AND USE TAX PROVISIONAL SUM CLOSURE

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc CHANGE ORDER NUMBER: CO-00077 DATE OF CHANGE ORDER: 16-Jun-2023 DATE OF AGREEMENT: November 7, 2018

The Agreement between the Parties listed above is changed as follows:

1.    In accordance with Section 2.1 Louisiana Sales and Use Tax Provisional Sumof Schedule EE-2 of the Agreement, this Change Order amends Section 2.1 Louisiana Sales and Use Tax Provisional Sum to reflect actual and final costs incurred by Contractor, as follows:

a.The current amount for the Louisiana Sales and Use Tax Provisional Sum is U.S. $42,543,792;

b.The actual and final costs incurred by Contractor for the Louisiana Sales and Use Tax Provisional Sum is U.S. 29,361,818; and

c.The Louisiana Sales and Use Tax Provisional Sum amount is hereby reduced by Thirteen Million, One Hundred and Eighty-One Thousand, Nine Hundred and Seventy-Four U.S. Dollars (U.S. $13,181,974).

d.Therefore the final Louisiana Sales and Use TaxProvisional Sum amount as amended by this Change Order shall be Twenty-Nine Million, Three Hundred and Sixty-One Thousand, Eight Hundred and Eighteen U.S. Dollars (U.S. $29,361,818).

2.    The detailed cost breakdown for this Change Order is provided in Exhibit A of this Change Order.

3.    The detailed reconciliation for this provisional sum is provided in Exhibit B of this Change Order.

4.    Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit C of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was ……………………...........................	$	2,016,892,573
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49, 51, 53-58, 61, 68, 75) ....................................................................................................................................................	$	8,116,678
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was .............................	$	2,025,009,251
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of …………………………………………..……...................................................................	$	0
5. The Provisional Sum Applicable to Subproject 6(a) will be reduced by this Change Order in the amount of ….........................................................................................................................................	$	13,181,974
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be ………….....	$	2,011,827,277
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was …..….......….............	$	457,969,000
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50, 52, 59-60, 62-67, 69-74, 76).	$	11,204,825
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ..….......................	$	468,900,825

10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order .............	$	0
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order ...........	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be .....................	$	468,900,825
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) ............	$	2,474,588,573
14. The Contract Price prior to this Change Order was (add lines 3 and 9) ……………...........................	$	2,493,910,076
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11) .........................................................................................................................................................	$	13,181,974
16. The new Contract Price including this Change Order will be (add lines 14 and 15) ….......................	$	2,480,728,102

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit C

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

___________________________________________________________________________________________________

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

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/ SMS Contractor_/s/ DC_ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change.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.

/s/ David Craft	/s/ Steve Smith
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP, Engineering & Construction	Senior Project Manager & Principal Vice President
Title	Title
July 25, 2023	July 18, 2023
Date of Signing	Date of Signing

CHANGE ORDER

NATURAL GAS PIPELINE (NGPL) SECURITY COORDINATION PROVISIONAL SUM CLOSURE

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. CHANGE ORDER NUMBER: CO-00078 DATE OF CHANGE ORDER: 22-Jun-2023 DATE OF AGREEMENT: November 7, 2018

The Agreement between the Parties listed above is changed as follows:

1.    In accordance with Section 2.4 NGPL Gate Access Security Coordination Provisional Sum of Schedule EE-2 of the Agreement, this Change Order amends Section 2.4 NGPL Gate Access Security Coordination Provisional Sum to reflect actual and final costs incurred by Contractor, as follows:

a.The current amount for the NGPL Gate Access Security Coordination Provisional Sum, as amended by previous Change Order CO-00046,is U.S. $253,207 (inclusive of 6% fee component);

b.The actual and final costs incurred by Contractor for the NGPL Gate Access Security Coordination Provisional Sum (inclusive of fee)is U.S. $264,576;

c.The NGPL Gate Access Security Coordination Provisional Sum amount is hereby increased by Eleven Thousand, Three Hundred and Sixty-Nine U.S. Dollars (U.S. $11,369);

d.Therefore the final NGPL Gate Access Security Coordination Provisional Sum amount as amended by this Change Order shall be Two Hundred and Sixty-Four Thousand, Five Hundred and Seventy-Six U.S. Dollars (U.S. $264,576); and

e.For context the NGPL Gate Access Security Coordination Provisional Sum services were provided in the period November 2019 through January 2022.

2.    The detailed cost breakdown for this Change Order is provided in Exhibit A of this Change Order.

3.    The detailed reconciliation for this provisional sum is provided in Exhibit B of this Change Order.

4.    Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit C of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was ……………………..….................	$	2,016,892,573
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49, 51, 53-58, 61, 68, 75, 77)…................................................................................................................................	$	(5,065,296)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was …….................	$	2,011,827,277
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ..........................................................................................................................................	$	0
5. The Provisional Sum Applicable to Subproject 6(a) will be increased by this Change Order in the amount of...	$	11,369
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be ...................	$	2,011,838,646
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was …..…....................	$	457,696,000

8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorize Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50, 52, 59-60, 62-67, 69-74, 76) .....................................................................................................................................................	$	11,204,825
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ..…..................	$	468,900,825
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order .........	$	0
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order .....	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be ..............	$	468,900,825
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) ...…	$	2,474,588,573
14. The Contract Price prior to this Change Order was (add lines 3 and 9) ……………......................	$	2,480,728,102
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) .............................................................................................................................................	$	11,369
16. The new Contract Price including this Change Order will be (add lines 14 and 15) ........................	$	2,480,739,471

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit C

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

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/ SMS Contractor /s/ DC Owner

[B]This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: Contractor _ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Steve Smith
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP, Engineering & Construction	Senior Project Manager & Principal Vice President
Title	Title
July 25, 2023	July 18, 2023
Date of Signing	Date of Signing

CHANGE ORDER

INSURANCE PROVISIONAL SUM CLOSURE

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. CHANGE ORDER NUMBER: CO-00079 DATE OF CHANGE ORDER: 27-Jul-2023 DATE OF AGREEMENT: November 7, 2018

The Agreement between the Parties listed above is changed as follows:

1.    In accordance with Section 2.3 Insurance Provisional Sum of Schedule EE-3 of the Agreement, this Change Order amends Section 2.3 Insurance Provisional Sum to reflect actual and final costs incurred by Contractor, as follows:

a.    The current amount for the Insurance Provisional Sum, as amended by previous Change Order(s) CO-00001, CO-00009, CO-00011 and CO-00031, is U.S. $39,840,850;

b.    The actual and final costs incurred by Contractor for the Insurance Provisional Sum is U.S. $39,840,110;

c.    Therefore the Insurance Provisional Sum amount is decreased by Seven Hundred and Forty U.S. Dollars (U.S. $740);

d.    Therefore the final Insurance Provisional Sum amount as amended by this Change Order shall be Thirty Nine Million, Eight Hundred and Forty Thousand, One Hundred and Ten U.S. Dollars (U.S. $39,840,110); and

2.    The detailed cost summary and reconciliation for this Change Order is provided in Exhibit A of this Change Order.

3.    Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was ……………………..…..................	$	2,016,892,573
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49, 51, 53-58, 61, 68, 75, 77, 78)......................................................................................................................................	$	(5,053,927)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was ...........................	$	2,011,838,646
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of …………………………………………..……..................................................................	$	0
5. The Provisional Sum Applicable to Subproject 6(a) will be decreased by this Change Order in the amount of …........................................................................................................................................	$	740
6. The Contract Price Applicable to Subproject 6(a) including this change Order will be....................	$	2,011,837,906
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was …..…......................	$	457,696,000
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50, 52, 59-60, 62-67, 69-74, 76) .......................................................................................................................................................	$	11,204,825
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ..….....................	$	468,900,825

10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order ……....	$	0
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order ........	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be ....................	$	468,900,825
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) ……...	$	2,474,588,573
14. The Contract Price prior to this Change Order was (add lines 3 and 9) ……………..........................	$	2,480,739,471
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, and 11) .......................................................................................................................................................	$	740
16. The new Contract Price including this Change Order will be (add lines 14 and 15) …......................	$	2,480,738,731

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

__________________________________________________________________________________________________

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

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/ SMS Contractor _/s/ DC_ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. 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.

/s/ David Craft	Steve Smith
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP E&C	Senior Project Manager & Principal Vice President
Title	Title
August 3, 2023	July 31, 2023
Date of Signing	Date of Signing

CHANGE ORDER

BORROWED ITEMS

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. CHANGE ORDER NUMBER: CO-00080 DATE OF CHANGE ORDER: 06-Sep-2023 DATE OF AGREEMENT: 07-Nov-2018

The Agreement between the Parties listed above is changed as follows:

1.Owner and Contractor agree that the Contract Price Applicable to Subproject 6(a) is reduced by Two Hundred Fifty-Five Thousand, Five Hundred and Sixty-Two U.S. Dollars (U.S. $255,562) as full and final settlement for Owner to purchase the items identified in Attachment 1 of this Change Order.

2.     For context the items in Attachment 1 of this Change Order were borrowed by Contractor from Owner but will not be returned. Therefore Parties agree that by this Change Order, Contractor shall have no responsibility to purchase such replacement items.

3.     The detailed cost summary and reconciliation for this Change Order is provided in Exhibit A of this Change Order. Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was ……………………..........................	$	2,016,892,573
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49, 51, 53-58, 61, 68, 75, 77-79).......................................................................................................................................	$	(5,054,667)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was ……....................	$	2,011,837,906
4. The Contract Price Applicable to Subproject 6(a) will be reduced by this Change Order in the amount of …………………………………………..……..................................................................	$	255,562
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ............................................................................................................................................	$	0
6. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ………………………………………………………………………………………........	$	2,011,582,344
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was …..….......................	$	457,696,000
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50, 52, 59-60, 62-67, 69-74, 76).......................................................................................................................................................	$	11,204,825
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ..…....................	$	468,900,825
10. The Contract Price Applicable to Subproject 6(b) will be reduced by this Change Order ...............	$	0
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order .......	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be ..................	$	468,900,825
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) .........	$	2,474,588,573

14. The Contract Price prior to this Change Order was (add lines 3 and 9) …………….......................	$	2,480,738,731
15. The Contract Price will be reduced by this Change Order in the amount of (add lines 4, 5, 10 and 11) .......................................................................................................................................................	$	255,562
16. The new Contract Price including this Change Order will be (add lines 14 and 15) …....................	$	2,480,483,169

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

__________________________________________________________________________________________________

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

__________________________________________________________________________________________________

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor _/s/ DC_ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. 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.

/s/ David Craft	/s/ Steve Smith
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP, Engineering and Construction	Senior Project Manager & Principal Vice President
Title	Title
September 27, 2023	September 15, 2023
Date of Signing	Date of Signing

EX-10.2

Exhibit 10.2

[***] 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

Payment Milestone Updates (Schedule C-1)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00036 DATE OF CHANGE ORDER: 19-Jun-2023 DATE OF AGREEMENT: 01-Mar-2022

The Agreement between the Parties listed above is changed as follows:

The Parties hereby agree that Schedule C-1 (“Aggregate Labor and Skills Price Milestone Payment Schedule”) of Attachment C (“Payment Schedule for Stage 3”) of the Agreement is amended as follows:

Month No.	Milestone	Description	Milestone Achievement Criteria	Cumulative Value	Milestone Value
	ALS5.3
	ALS14.3
16	ALS16.10	Fire proofing work starts	Progress report or equivalent showing start of construction process	[***]	[***]
21	ALS21.10	Finish Fire proofing work (90% complete) Train 1	Progress report or equivalent shows 90% of non-repair budget completed	[***]	[***]
25	ALS25.8	Finish Fire proofing work (90% complete) Train 2	Progress report or equivalent shows 90% of non-repair budget completed	[***]	[***]
28	ALS28.13	Finish Fire proofing work (90% complete) Train 3	Progress report or equivalent shows 90% of non-repair budget completed	[***]	[***]
30	ALS30.13	Finish Fire proofing work (90% complete) Train 4	Progress report or equivalent shows 90% of non-repair budget completed	[***]	[***]
32	ALS32.9	Finish Fire proofing work (90% complete) Train 5	Progress report or equivalent shows 90% of non-repair budget completed	[***]	[***]
34	ALS34.4	Finish Fire proofing work (90% complete) Train 6	Progress report or equivalent shows 90% of non-repair budget completed	[***]	[***]
36	ALS26.4	Finish Fire proofing work (90% complete) Train 7	Progress report or equivalent shows 90% of non-repair budget completed	[***]	[***]
Month No.	Milestone	Description	Milestone Achievement Criteria	Cumulative Value	Milestone Value
	ALS5.2
	ALS15.2
16	ALS16.4	Equipment insulation work starts	Progress report or equivalent showing start of construction progress	[***]	[***]
24	ALS24.4	Finish Equipment insulation work (90% complete) Train 1	Progress report or equivalent shows 90% complete of forecasted quantity earned	[***]	[***]
28	ALS28.4	Finish Equipment insulation work (90% complete) Train 2	Progress report or equivalent shows 90% complete of forecasted quantity earned	[***]	[***]
31	ALS31.3	Finish Equipment insulation work (90% complete) Train 3	Progress report or equivalent shows 90% complete of forecasted quantity earned	[***]	[***]
33	ALS33.6	Finish Equipment insulation work (90% complete) Train 4	Progress report or equivalent shows 90% complete of forecasted quantity earned	[***]	[***]
35	ALS35.7	Finish Equipment insulation work (90% complete) Train 5	Progress report or equivalent shows 90% complete of forecasted quantity earned	[***]	[***]
37	ALS37.7	Finish Equipment insulation work (90% complete) Train 6	Progress report or equivalent shows 90% complete of forecasted quantity earned	[***]	[***]
39	ALS39.9	Finish Equipment insulation work (90% complete) Train 7	Progress report or equivalent shows 90% complete of forecasted quantity earned	[***]	[***]

Month No.	Milestone	Description	Milestone Achievement Criteria	Cumulative Value	Milestone Value
24	ALS13.2	50% complete or structural concrete Train 1	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
28	ALS17.2	50% complete or structural concrete Train 2	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
32	ALS20.2	50% complete or structural concrete Train 3	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
35	ALS22.1	50% complete or structural concrete Train 4	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
37	ALS24.7	50% complete or structural concrete Train 5	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
40	ALS26.8	50% complete or structural concrete Train 6	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
42	ALS28.9	50% complete or structural concrete Train 7	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
18	ALS7.4	50% Complete of sitework (site preparation, rough grade and drainage)	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
32	ALS21.1	Finish sitework (90% complete) Train 1 (site preparation, rough grade and drainage)	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
15	ALS25.1	Finish sitework (90% complete) Train 2 (site preparation, rough grade and drainage)	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
18	ALS28.1	Finish sitework (90% complete) Train 3 (site preparation, rough grade and drainage)	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
28	ALS30.1	Finish sitework (90% complete) Train 4 (site preparation, rough grade and drainage)	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
33	ALS32.1	Finish sitework (90% complete) Train 5 (site preparation, rough grade and drainage)	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
33	ALS24.1	Finish sitework (90% complete) Train 6 (site preparation, rough grade and drainage)	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
38	ALS26.1	Finish sitework (90% complete) Train 7 (site preparation, rough grade and drainage)	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
25	ALS20.1	Finish structural concrete for (90% complete) Train1	Progress report or equivalent shows 50% complete of forecasted quantity earned	[***]	[***]
Summary of changes
1	Merge ALS5.3, ALS14.3 and ALS16.10 into ALS16.10
2	Merge ALS5.2 and ALS16.4 into ALS16.4
3	Various Milestone Achievement Criteria descriptions amended
4	The Descriptions of fireproofing and equipment insulation items are amended

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-00035) ...............................	$	143,669,244
3. The Contract Price prior to this Change Order was .............................................................................	$	5,627,669,244
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of ............	$	0
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of ...	$	0
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ...............................................................................................................................................	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of .........................................................................................................................................	$	0
8. The new Contract Price including this Change Order will be ...............................................................	$	5,627,669,244

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: Y

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/ NT Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: Contractor _Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:	/s/ David Craft
Name:	David Craft
Title:	SVP, Engineering & Construction

BECHTEL ENERGY INC.

By:	/s/ Nirav Thakkar
Name:	Nirav Thakkar for Steve Smith
Title:	Sr. Project Manager and Principal Vice President

CHANGE ORDER

GEOTECHNICAL SOILS INVESTIGATION PERIOD & SECURITY DIVISION OF RESPONSIBILITY CHANGE

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00037 DATE OF CHANGE ORDER: 20-Jun-2023 DATE OF AGREEMENT: 01-Mar-2022

The Agreement between the Parties listed above is changed as follows:

1.GEOTECHNICAL SOILS INVESTIGATION PERIOD

1.1    In accordance with Section 2.5B.2(i) of the Agreement (“Conditions of the Site and the Supporting Real Estate”), the Parties agree the Contract Price is increased by Seventeen Million, Seven Hundred and Sixty-Four Thousand, Two Hundred and Thirty-Five U.S. Dollars (U.S. $17,764,235) to address Contractor’s increased costs to perform the Work owing to the discovery of subsurface conditions that differs from the Soils Data;

1.2    Parties agree that Contractor shall not be entitled to any further relief with respect to the Soils Investigation Period under Section 2.5B.2(i) of the Agreement;

1.3    For the avoidance of doubt, the Guaranteed Dates are unchanged;

1.4    While implementing Trencher Method DMM, Contractor shall not cut and mix at plant elevation below approximately 95 feet. Contractor shall make reasonable efforts to minimize waste, which such waste shall be addressed in accordance with the EPC Agreement;

1.5    A general illustration of Zone 2 DMM is provided in Attachment 1 of this Change Order; and

1.6    The cost summary for the Geotechnical Soils Investigation Period is provided in Exhibit A of this Change Order.

2.    SITE SECURITY DIVISION OF RESPONSIBILITY CHANGE

2.1    In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, the Parties agree Contractor will assume the additional responsibility for the overall security of the Supporting Real Estate;

2.2    The Parties agree the Contract Price is increased by Four Million, Two Hundred and Thirty-Five Thousand, Seven Hundred and Sixty-Five U.S. Dollars (U.S. $4,235,765);

2.3    Accordingly, Section 6.5A of Attachment A of the EPC Agreement is amended to add the words “and Supporting Real Estate”, as follows:

“Contractor shall be responsible at all times for the overall security at the Site and the Supporting Real Estate until Substantial Completion of all Trains, provided however that once a Train is turned over to Owner at Substantial Completion in accordance with the Agreement, Owner shall be responsible for security of that Train, associated equipment and area (e.g. OSBL, Flare). Adequate fencing and security devices shall be provided and maintained. The Contractor shall employ sufficient security personnel to monitor and control the Site entrances, perimeter fencing and secure areas at all times and to carry out random searches of vehicle arriving or leaving the Site. Adequate security lighting of the Site shall be provided.”; and

2.4    The cost summary for the Site Security Division of Responsibility Change is provided in Exhibit B of this Change Order.

3.    Schedules C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ……………………………………………………………….........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00036)……………........	$	143,669,244
3. The Contract Price prior to this Change Order was ………………………………………...............	$	5,627,669,244
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 ……………………………………………………………………………….....................	[***]
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..………………………………………………………………………...................	[***]
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,649,669,244

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A]    This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B]    This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: Contractor _ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order.Except as modifiedbythisandanypreviouslyissuedChangeOrders,allothertermsandconditionsoftheAgreementshallremainin full force and effect.This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:	/s/ David Craft
Name:	David Craft
Title:	SVP E&C

BECHTEL ENERGY INC.

By:	/s/ Steve Smith
Name:	Steve Smith
Title:	Sr. Project Manager and Principal Vice President

CHANGE ORDER

POWER MONITORING SYSTEM (ETAP HMI)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00038 DATE OF AGREEMENT: March 1, 2022 DATE OF CHANGE ORDER: 29-Jun-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, the Parties agree this Change Order:

1.1    Incorporates into the scope of work Owner’s request for Contractor to reconfigure the Power Monitoring System’s ETAP servers and gateways and supply and install the ETAP HMI.

2.Separately, this Change order includes a $75,089.00 credit, as an agreed reconciliation to Change Order CO-00023 EFG Package #2.

3.The cost summary is provided in Exhibit A of this Change Order.

4.    Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestones 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-00037)................................	$	165,669,244
3. The Contract Price prior to this Change Order was ………………………………………..................	$	5,649,669,244
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 …………………………………………………………………………………………......	[***]
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………......................	[***]
8. The new Contract Price including this Change Order will be …………………………………….......	$	5,650,827,463

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A]    This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B]    This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: Contractor _ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order.Except as modifiedbythisandanypreviouslyissuedChangeOrders,allothertermsandconditionsoftheAgreementshallremainin full force and effect.This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:	/s/ David Craft
Name:	David Craft
Title:	SVP, E&C

BECHTEL ENERGY INC.

By:	/s/ Steve Smith
Name:	Steve Smith
Title:	Sr. Project Manager and Principal Vice President

CHANGE ORDER

EFG FIREWATER CONNECTION

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00039 DATE OF CHANGE ORDER: 30-Jun-2023 DATE OF AGREEMENT: March 1, 2022

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor shall provide an additional firewater connection on the main firewater header near Train 2, to run under the main North/South Firewater Piperack and located on the Northern side of the EFG plot, to allow for a firewater loop around the EFG area.

2.    The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.    An illustrative scope sketch is provided in Attachment 1 of this Change Order.

4.    Schedules C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………………………………….…...	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00038)……..…………….	$	166,827,463
3. The Contract Price prior to this Change Order was ………………………………………………......	$	5,650,827,463
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 …………………………………………………………………………………………....	[***]
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..………………………………………………………………………….....................	[***]
8. The new Contract Price including this Change Order will be …………………………………….....	$	5,651,451,690

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A]    This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B]    This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: Contractor _ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:	/s/ David Craft
Name:	David Craft
Title:	SVP E&C

BECHTEL ENERGY INC.

By:	/s/ Steve Smith
Name:	Steve Smith
Title:	Sr. Project Manager and Principal Vice President

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: November 1, 2023 

/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: November 1, 2023

/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 September 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 1, 2023 

/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 September 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Zach Davis, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 1, 2023 

/s/ Zach Davis

Zach Davis
Chief Financial Officer of

Cheniere Energy, Inc.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2023	Oct. 26, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2023
Document Transition Report	false
Entity File Number	001-16383
Entity Registrant Name	CHENIERE ENERGY, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	95-4352386
Entity Address, Address Line One	700 Milam Street
Entity Address, Address Line Two	Suite 1900
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	NYSEAMER
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		238,254,866
Entity Central Index Key	0000003570
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Revenues
Revenues		$ 4,159	$ 8,852	$ 15,571	$ 24,343
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below)		556	11,073	(71)	24,161
Operating and maintenance expense		445	419	1,376	1,227
Selling, general and administrative expense		102	92	296	265
Depreciation and amortization expense		298	280	892	827
Other		3	4	24	15
Total operating costs and expenses		1,404	11,868	2,517	26,495
Income (loss) from operations		2,755	(3,016)	13,054	(2,152)
Other income (expense)
Interest expense, net of capitalized interest		(283)	(354)	(871)	(1,060)
Gain (loss) on modification or extinguishment of debt		(3)	3	15	(43)
Interest and dividend income		58	20	147	28
Other income (expense), net		4	(49)	7	(47)
Total other expense		(224)	(380)	(702)	(1,122)
Income (loss) before income taxes and non-controlling interest		2,531	(3,396)	12,352	(3,274)
Less: income tax provision (benefit)		440	(752)	2,119	(762)
Net income (loss)		2,091	(2,644)	10,233	(2,512)
Less: net income (loss) attributable to non-controlling interest		390	(259)	1,729	(3)
Net income (loss) attributable to common stockholders		$ 1,701	$ (2,385)	$ 8,504	$ (2,509)
Net income (loss) per share attributable to common stockholders—basic (1)	[1]	$ 7.08	$ (9.54)	$ 35.12	$ (9.94)
Net income (loss) per share attributable to common stockholders—diluted (1)	[1]	$ 7.03	$ (9.54)	$ 34.87	$ (9.94)
Weighted average number of common shares outstanding—basic		240.2	249.9	242.1	252.5
Weighted average number of common shares outstanding—diluted		242.0	249.9	243.9	252.5
LNG [Member]
Revenues
Revenues		$ 3,974	$ 8,236	$ 14,984	$ 23,449
Regasification [Member]
Revenues
Revenues		34	455	101	591
Other [Member]
Revenues
Revenues		$ 151	$ 161	$ 486	$ 303

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

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2023		Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 3,861	[1]	$ 1,353
Restricted cash and cash equivalents	422	[1]	1,134
Trade and other receivables, net of current expected credit losses	811		1,944
Inventory	400		826
Current derivative assets	95		120
Margin deposits	73		134
Other current assets, net	107		97
Total current assets	5,769		5,608
Property, plant and equipment, net of accumulated depreciation	32,053		31,528
Operating lease assets	2,549		2,625
Derivative assets	620		35
Goodwill	77		77
Deferred tax assets	40		864
Other non-current assets, net	611		529
Total assets	41,719	[1]	41,266
Current liabilities
Accounts payable	126		124
Accrued liabilities	1,433		2,679
Current debt, net of discount and debt issuance costs	349		813
Deferred revenue	209		234
Current operating lease liabilities	612		616
Current derivative liabilities	991		2,301
Other current liabilities	38		28
Total current liabilities	3,758		6,795
Long-term debt, net of discount and debt issuance costs	23,389		24,055
Operating lease liabilities	1,907		1,971
Finance lease liabilities	476		494
Derivative liabilities	2,882		7,947
Deferred tax liabilities	1,178		0
Other non-current liabilities	222		175
Stockholders’ equity (deficit)
Preferred stock: $0.0001 par value, 5.0 million shares authorized, none issued	0		0
Common stock: $0.003 par value, 480.0 million shares authorized; 277.8 million shares and 276.7 million shares issued at September 30, 2023 and December 31, 2022, respectively	1		1
Treasury stock: 39.0 million shares and 31.2 million shares at September 30, 2023 and December 31, 2022, respectively, at cost	(3,522)		(2,342)
Additional paid-in-capital	4,394		4,314
Accumulated income (deficit)	3,271		(4,942)
Total Cheniere stockholders’ equity (deficit)	4,144		(2,969)
Non-controlling interest	3,763		2,798
Total stockholders’ equity (deficit)	7,907		(171)
Total liabilities and stockholders’ equity (deficit)	$ 41,719	[1]	$ 41,266

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 7—Non-controlling Interest and Variable Interest Entity. As of September 30, 2023, total assets and liabilities of CQP were $17.8 billion and $19.0 billion, respectively, including $499 million of cash and cash equivalents and $35 million of restricted cash and cash equivalents.

XML

Consolidated Balance Sheets Parentheticals - USD ($) $ in Millions	Sep. 30, 2023		Dec. 31, 2022
Assets	$ 41,719	[1]	$ 41,266
Cash and cash equivalents	$ 3,861	[1]	$ 1,353
Preferred Stock, Par Value	$ 0.0001		$ 0.0001
Preferred Stock, Shares Authorized	5,000,000		5,000,000
Preferred Stock, Shares Issued	0		0
Common Stock, Par Value Per Share	$ 0.003		$ 0.003
Common stock, Shares Authorized	480,000,000		480,000,000
Common Stock, Shares, Issued	277,800,000		276,700,000
Restricted cash and cash equivalents	$ 422	[1]	$ 1,134
Treasury Stock
Treasury Stock, Common	39,000,000		31,200,000
CQP [Member]
Assets	$ 17,764		$ 18,905
Liabilities	18,978		21,664
Cash and cash equivalents	499		904
Restricted cash and cash equivalents	$ 35		$ 92

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 7—Non-controlling Interest and Variable Interest Entity. As of September 30, 2023, total assets and liabilities of CQP were $17.8 billion and $19.0 billion, respectively, including $499 million of cash and cash equivalents and $35 million of restricted cash and cash equivalents.

XML

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions	Total	$0.33 per Common Share	$0.395 per Common Share	Common Stock	Treasury Stock	Additional Paid-in Capital	Accumulated Income (Deficit)	Accumulated Income (Deficit) $0.33 per Common Share	Accumulated Income (Deficit) $0.395 per Common Share	Non-controlling Interest
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2021				253,600
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2021					21,600
Stockholders' Equity, Beginning of Period at Dec. 31, 2021	$ (33)			$ 1	$ (928)	$ 4,377	$ (6,021)			$ 2,538
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of share-based compensation awards, shares				1,300	0
Vesting of share-based compensation awards	0			$ 0	$ 0	0	0			0
Share-based compensation	38			$ 0	$ 0	38	0			0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock				(300)
Shares withheld from employees related to share-based compensation, at cost, shares, treasury shares					300
Shares withheld from employees related to share-based compensation, at cost	(53)			$ 0	$ (35)	(18)	0			0
Shares repurchased, at cost, shares				(200)	200
Shares repurchased, at cost	(25)			$ 0	$ (25)	0	0			0
Reacquisition of equity component of convertible notes, net of tax	(149)			0	0	(153)	4			0
Net income attributable to non-controlling interest	84			0	0	0	0			84
Distributions to non-controlling interest	(171)			0	0	0	0			(171)
Dividends declared	(85)			0	0	0	(85)			0
Net income (loss) attributable to common stockholders	(865)			$ 0	$ 0	0	(865)			0
Common Stock, Shares, Outstanding, End of Period at Mar. 31, 2022				254,400
Treasury Stock, Shares, End of Period at Mar. 31, 2022					22,100
Stockholders' Equity, End of Period at Mar. 31, 2022	(1,259)			$ 1	$ (988)	4,244	(6,967)			2,451
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared				$ 0.33
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2021				253,600
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2021					21,600
Stockholders' Equity, Beginning of Period at Dec. 31, 2021	$ (33)			$ 1	$ (928)	4,377	(6,021)			2,538
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares repurchased, at cost, shares	4,970
Net income attributable to non-controlling interest	$ (3)
Net income (loss) attributable to common stockholders	(2,509)
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2022				249,900
Treasury Stock, Shares, End of Period at Sep. 30, 2022					26,800
Stockholders' Equity, End of Period at Sep. 30, 2022	$ (4,330)			$ 1	$ (1,609)	4,309	(8,880)			1,849
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.99
Common Stock, Shares, Outstanding, Beginning of Period at Mar. 31, 2022				254,400
Treasury Stock, Shares, Beginning of Period at Mar. 31, 2022					22,100
Stockholders' Equity, Beginning of Period at Mar. 31, 2022	$ (1,259)			$ 1	$ (988)	4,244	(6,967)			2,451
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of share-based compensation awards, shares				100	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
Shares withheld from employees related to share-based compensation, at cost, shares, treasury shares					0
Shares withheld from employees related to share-based compensation, at cost	(2)			$ 0	$ (1)	(1)	0			0
Shares repurchased, at cost, shares				(4,100)	4,100
Shares repurchased, at cost	(540)			$ 0	$ (540)	0	0			0
Net income attributable to non-controlling interest	172			0	0	0	0			172
Distributions to non-controlling interest	(256)			0	0	0	0			(256)
Dividends declared	(85)			0	0	0	(85)			0
Net income (loss) attributable to common stockholders	741			$ 0	$ 0	0	741			0
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2022				250,400
Treasury Stock, Shares, End of Period at Jun. 30, 2022					26,200
Stockholders' Equity, End of Period at Jun. 30, 2022	(1,195)			$ 1	$ (1,529)	4,277	(6,311)			2,367
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared				$ 0.33
Vesting of share-based compensation awards, shares				100	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
Shares withheld from employees related to share-based compensation, at cost, shares, treasury shares					0
Shares withheld from employees related to share-based compensation, at cost	$ (7)			$ 0	$ (5)	(2)	0			0
Shares repurchased, at cost, shares	600			(600)	600
Shares repurchased, at cost	$ (75)			$ 0	$ (75)	0	0			0
Net income attributable to non-controlling interest	(259)			0	0	0	0			(259)
Distributions to non-controlling interest	(259)			0	0	0	0			(259)
Dividends declared		$ (84)	$ (100)	0	0	0		$ (84)	$ (100)	0
Net income (loss) attributable to common stockholders	(2,385)			$ 0	$ 0	0	(2,385)			0
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2022				249,900
Treasury Stock, Shares, End of Period at Sep. 30, 2022					26,800
Stockholders' Equity, End of Period at Sep. 30, 2022	$ (4,330)			$ 1	$ (1,609)	4,309	(8,880)			1,849
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.33			$ 0.33
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
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)
Shares withheld from employees related to share-based compensation, at cost, shares, treasury shares					200
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 attributable to non-controlling interest	1,001			0	0	0	0			1,001
Distributions to non-controlling interest	(261)			0	0	0	0			(261)
Dividends declared	(98)			0	0	0	(98)			0
Net income (loss) attributable to common stockholders	5,434			$ 0	$ 0	0	5,434			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
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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares repurchased, at cost, shares	7,570
Net income attributable to non-controlling interest	$ 1,729
Net income (loss) attributable to common stockholders	8,504
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2023				238,800
Treasury Stock, Shares, End of Period at Sep. 30, 2023					39,000
Stockholders' Equity, End of Period at Sep. 30, 2023	$ 7,907			$ 1	$ (3,522)	4,394	3,271			3,763
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 1.185
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
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
Shares withheld from employees related to share-based compensation, at cost, shares, treasury shares					0
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
Shares repurchased, at cost	(341)			$ 0	$ (341)	0	0			0
Net income attributable to non-controlling interest	338			0	0	0	0			338
Distributions to non-controlling interest	(252)			0	0	0	0			(252)
Dividends declared	(97)			0	0	0	(97)			0
Net income (loss) attributable to common stockholders	1,369			$ 0	$ 0	0	1,369			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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared				$ 0.395
Vesting of share-based compensation awards, shares				100	0
Vesting of share-based compensation awards	0			$ 0	$ 0	0	0			0
Share-based compensation	37			$ 0	$ 0	37	0			0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock				0
Shares withheld from employees related to share-based compensation, at cost, shares, treasury shares					0
Shares withheld from employees related to share-based compensation, at cost	$ (6)			$ 0	$ 0	(6)	0			0
Shares repurchased, at cost, shares	2,210			(2,200)	2,200
Shares repurchased, at cost	$ (360)			$ 0	$ (360)	0	0			0
Net income attributable to non-controlling interest	390			0	0	0	0			390
Distributions to non-controlling interest	(251)			0	0	0	0			(251)
Dividends declared	(96)			0	0	0	(96)			0
Net income (loss) attributable to common stockholders	1,701			$ 0	$ 0	0	1,701			0
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2023				238,800
Treasury Stock, Shares, End of Period at Sep. 30, 2023					39,000
Stockholders' Equity, End of Period at Sep. 30, 2023	$ 7,907			$ 1	$ (3,522)	$ 4,394	$ 3,271			$ 3,763
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.395			$ 0.395

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Cash flows from operating activities
Net income (loss)	$ 10,233	$ (2,512)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized foreign currency exchange gain, net	(2)	(10)
Depreciation and amortization expense	892	827
Share-based compensation expense	128	115
Amortization of debt issuance costs, premium and discount	34	43
Reduction of right-of-use assets	464	444
Loss (gain) on modification or extinguishment of debt	(15)	43
Total losses (gains) on derivative instruments, net	(6,839)	10,228
Net cash used for settlement of derivative instruments	(96)	(702)
Equity in losses (earnings) of unconsolidated entities	(4)	55
Deferred taxes	2,015	(856)
Other, net	7	11
Changes in operating assets and liabilities:
Trade and other receivables	1,134	(389)
Inventory	422	(426)
Margin deposits	61	498
Contract assets	11	(387)
Other current assets	(24)	57
Accounts payable and accrued liabilities	(1,261)	938
Total deferred revenue	27	91
Total operating lease liabilities	(456)	(460)
Other, net	(33)	(37)
Net cash provided by operating activities	6,698	7,571
Cash flows from investing activities
Property, plant and equipment, net	(1,430)	(1,339)
Investment in equity method investments	(36)	(10)
Other, net	(12)	1
Net cash used in investing activities	(1,478)	(1,348)
Cash flows from financing activities
Proceeds from issuances of debt	1,397	1,015
Redemptions, repayments and repurchases of debt	(2,548)	(4,005)
Debt issuance and other financing costs	(32)	(44)
Debt modification or extinguishment gains (costs)	26	(33)
Distributions to non-controlling interest	(764)	(686)
Payments related to tax withholdings for share-based compensation	(62)	(62)
Repurchase of common stock	(1,132)	(640)
Dividends to stockholders	(291)	(251)
Payments of finance lease liabilities	(20)	(1)
Net cash used in financing activities	(3,426)	(4,707)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	2	5
Net increase in cash, cash equivalents and restricted cash and cash equivalents	1,796	1,521
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	2,487	1,817
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$ 4,283	$ 3,338

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Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2023		Dec. 31, 2022	Sep. 30, 2022	Dec. 31, 2021
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 3,861	[1]	$ 1,353
Restricted cash and cash equivalents	422	[1]	1,134
Total cash, cash equivalents and restricted cash and cash equivalents	$ 4,283		$ 2,487	$ 3,338	$ 1,817

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 7—Non-controlling Interest and Variable Interest Entity. As of September 30, 2023, total assets and liabilities of CQP were $17.8 billion and $19.0 billion, respectively, including $499 million of cash and cash equivalents and $35 million of restricted cash and cash equivalents.

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Nature of Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2023

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. Additionally, the Sabine Pass LNG Terminal includes a 94-mile pipeline owned by CTPL, a subsidiary of CQP, that interconnects our facilities with a number of large interstate and intrastate pipelines. As of September 30, 2023, we owned 100% of the general partner interest and a 48.6% limited partner interest in CQP.

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

We have increased available liquefaction capacity at the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) as a result of debottlenecking and other optimization projects. 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 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. In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the National Environmental Policy Act for an expansion adjacent to the SPL Project with a potential production capacity of up to 20 mtpa of LNG. 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, they 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, 2022.

Results of operations for the three and nine months ended September 30, 2023 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2023.

Recent Accounting Standards

ASU 2020-04

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 9—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities subsequent to the effective date of ASU

2020-04. We elected to apply the optional expedients as applicable to certain modified or replaced facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

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Restricted Cash and Cash Equivalents

9 Months Ended

Sep. 30, 2023

Restricted Cash and Cash Equivalents [Abstract]

Restricted Cash and Cash Equivalents

RESTRICTED CASH AND CASH EQUIVALENTS

As of September 30, 2023 and December 31, 2022, we had $422 million and $1.1 billion of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is restricted, primarily to the payment of liabilities related to the Liquefaction Projects, as required under certain debt arrangements.

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Trade and Other Receivables, Net of Current Expected Credit Losses

9 Months Ended

Sep. 30, 2023

Receivables [Abstract]

Trade and Other Receivables, Net of Current Expected Credit Losses

TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

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

	September 30,		December 31,
	2023		2022
Trade receivables
SPL and CCL	$	418	$	922
Cheniere Marketing	323		917
Other receivables	70		105
Total trade and other receivables, net of current expected credit losses	$	811	$	1,944

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Inventory

9 Months Ended

Sep. 30, 2023

Inventory Disclosure [Abstract]

Inventory

INVENTORY

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
LNG in-transit	$	82	$	356
LNG	90		212
Materials	199		194
Natural gas	27		60
Other	2		4
Total inventory	$	400	$	826

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Property, Plant and Equipment, Net of Accumulated Depreciation

9 Months Ended

Sep. 30, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

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

	September 30,		December 31,
	2023		2022
LNG terminal
Terminal and interconnecting pipeline facilities	$	33,881	$	33,815
Site and related costs	461		451
Construction-in-process	2,981		1,685
Accumulated depreciation	(5,821)		(4,985)
Total LNG terminal, net of accumulated depreciation	31,502		30,966
Fixed assets and other
Computer and office equipment	36		33
Furniture and fixtures	20		20
Computer software	125		121
Leasehold improvements	69		48
Other	21		20
Accumulated depreciation	(202)		(191)
Total fixed assets and other, net of accumulated depreciation	69		51
Assets under finance leases
Marine assets	532		533
Accumulated depreciation	(50)		(22)
Total assets under finance leases, net of accumulated depreciation	482		511
Property, plant and equipment, net of accumulated depreciation	$	32,053	$	31,528

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Depreciation expense	$	296	$	278	$	887	$	822
Offsets to LNG terminal costs (1)	—		—		—		204

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

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Derivative Instruments

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments:

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

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

•foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with cash flows denominated in currencies other than United States 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 or fair value 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, by the fair value hierarchy levels prescribed by GAAP (in millions):

	Fair Value Measurements as of
	September 30, 2023								December 31, 2022
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset (liability)	$	19	$	54	$	(3,216)	$	(3,143)	$	(66)	$	(29)	$	(9,924)	$	(10,019)
LNG Trading Derivatives asset (liability)	(29)		7		—		(22)		1		(47)		—		(46)
FX Derivatives asset (liability)	—		7		—		7		—		(28)		—		(28)

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

The fair value of our Liquefaction Supply Derivatives and LNG Trading Derivatives are predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

We include a significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.

The Level 3 fair value measurements of our natural gas positions within our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of September 30, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(3,216)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.245) - $0.638 / $(0.031)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	83% - 422% / 188%

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

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

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Balance, beginning of period	$	(4,611)	$	(8,462)	$	(9,924)	$	(4,036)
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	1,197		(5,668)		5,350		(8,825)
Included in cost of sales, new deals (3)	8		—		26		—
Purchases and settlements:
Purchases (4)	—		4		—		(1,390)
Settlements (5)	187		322		1,323		446
Transfers out of level 3 (6)	3		(1)		9		—
Balance, end of period	$	(3,216)	$	(13,805)	$	(3,216)	$	(13,805)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	1,205	$	(5,668)	$	5,376	$	(8,825)

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

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

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

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

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

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

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

Commodity Derivatives

SPL and CCL hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The firm terms of the Liquefaction Supply Derivatives range up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.

Cheniere Marketing has historically entered into, and may from time to time enter into, LNG transactions that provide for contractual net settlement. Such transactions are accounted for as LNG Trading Derivatives along with financial

commodity contracts in the form of swaps or futures. The terms of LNG Trading Derivatives range up to approximately one year.

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

	September 30, 2023		December 31, 2022
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,542	6	14,504	50

(1)Excludes notional amounts associated with extension options that were uncertain to be taken as of September 30, 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 September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
LNG Trading Derivatives	LNG revenues	$	19	$	(237)	$	34	$	(454)
LNG Trading Derivatives	Recovery (cost) of sales	(8)		(4)		(95)		103
Liquefaction Supply Derivatives (2)	LNG revenues	1		(3)		(5)		8
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales	1,403		(5,508)		6,900		(10,008)

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

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

FX Derivatives

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

The total notional amount of our FX Derivatives was $266 million and $619 million as of September 30, 2023 and December 31, 2022, respectively.

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

		Gain Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
FX Derivatives	LNG revenues	$	13	$	54	$	5	$	121

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

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

	September 30, 2023
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	62	$	23	$	10	$	95
Derivative assets	620		—		—		620
Total derivative assets	682		23		10		715
Current derivative liabilities	(943)		(45)		(3)		(991)
Derivative liabilities	(2,882)		—		—		(2,882)
Total derivative liabilities	(3,825)		(45)		(3)		(3,873)
Derivative asset (liability), net	$	(3,143)	$	(22)	$	7	$	(3,158)
	December 31, 2022
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	36	$	84	$	—	$	120
Derivative assets	35		—		—		35
Total derivative assets	71		84		—		155
Current derivative liabilities	(2,143)		(130)		(28)		(2,301)
Derivative liabilities	(7,947)		—		—		(7,947)
Total derivative liabilities	(10,090)		(130)		(28)		(10,248)
Derivative liability, net	$	(10,019)	$	(46)	$	(28)	$	(10,093)

(1)Does not include collateral posted with counterparties by us of $1 million and $111 million as of September 30, 2023 and December 31, 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $1 million and zero as of September 30, 2023 and December 31, 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $72 million and $23 million, as of September 30, 2023 and December 31, 2022, respectively, which are included in margin deposits 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 September 30, 2023
Gross assets	$	1,161	$	23	$	10
Offsetting amounts	(479)		—		—
Net assets (1)	$	682	$	23	$	10
Gross liabilities	$	(3,911)	$	(51)	$	(3)
Offsetting amounts	86		6		—
Net liabilities (2)	$	(3,825)	$	(45)	$	(3)
As of December 31, 2022
Gross assets	$	76	$	87	$	—
Offsetting amounts	(5)		(3)		—
Net assets (1)	$	71	$	84	$	—
Gross liabilities	$	(10,436)	$	(132)	$	(29)
Offsetting amounts	346		2		1
Net liabilities (2)	$	(10,090)	$	(130)	$	(28)

(1)Includes current and non-current derivative assets of $95 million and $620 million, respectively, as of September 30, 2023 and $120 million and $35 million, respectively, as of December 31, 2022.

(2)Includes current and non-current derivative liabilities of $991 million and $2,882 million, respectively, as of September 30, 2023 and $2,301 million and $7,947 million, respectively, as of December 31, 2022.

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Non-Controlling Interest and Variable Interest Entity

9 Months Ended

Sep. 30, 2023

Noncontrolling Interest and Variable Interest Entity [Abstract]

Non-Controlling Interest and Variable Interest Entity

NON-CONTROLLING INTEREST AND VARIABLE INTEREST ENTITY CQP is accounted for as a consolidated VIE. We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. We also own 100% of the general partner interest and the incentive distribution rights in CQP.

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

	September 30,		December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	499	$	904
Restricted cash and cash equivalents	35		92
Trade and other receivables, net of current expected credit losses	287		627
Other current assets	225		269
Total current assets	1,046		1,892
Property, plant and equipment, net of accumulated depreciation	16,341		16,725
Other non-current assets, net	377		288
Total assets	$	17,764	$	18,905
LIABILITIES
Current liabilities
Accrued liabilities	$	646	$	1,384
Current debt, net of discount and debt issuance costs	349		—
Current derivative liabilities	294		769
Other current liabilities	217		191
Total current liabilities	1,506		2,344
Long-term debt, net of premium, discount and debt issuance costs	15,600		16,198
Derivative liabilities	1,731		3,024
Other non-current liabilities	141		98
Total liabilities	$	18,978	$	21,664

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Accrued Liabilities

9 Months Ended

Sep. 30, 2023

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2023		2022
Natural gas purchases	$	607	$	1,621
Interest costs and related debt fees	260		383
LNG terminals and related pipeline costs	244		240
Compensation and benefits	118		245
LNG purchases	22		88
Other accrued liabilities	182		102
Total accrued liabilities	$	1,433	$	2,679

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Debt

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Debt

DEBT

Debt consisted of the following (in millions): 

	September 30,		December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.75% due 2024 (the “2024 SPL Senior Notes”)	$	350	$	2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,482		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,482		12,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
5.95% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
CCH:
Senior Secured Notes:
7.000% due 2024 (the “2024 CCH Senior Notes”)	—		498
5.875% due 2025	1,491		1,491
5.125% due 2027	1,201		1,271
3.700% due 2029	1,125		1,361
3.788% weighted average rate due 2039	2,539		2,633
Total CCH Senior Secured Notes	6,356		7,254
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”) (1)	—		—
Total debt - CCH	6,356		7,254
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		1,500
Total debt	23,938		25,086
Current debt, net of discount and debt issuance costs	(349)		(813)
Long-term portion of unamortized discount and debt issuance costs, net	(200)		(218)
Total long-term debt, net of discount and debt issuance costs	$	23,389	$	24,055

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

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of September 30, 2023 (in millions):

	SPL Revolving Credit Facility (1)		CQP Revolving Credit Facility (1)		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility (2)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	284		—		—		155		—
Available commitment	$	716	$	1,000	$	3,260	$	1,345	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (3)	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 0.115% - 0.365%
Commitment fees on undrawn balance (3)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365% (4)
Maturity date	June 23, 2028		June 23, 2028		(5)		June 15, 2027		October 28, 2026

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

(2)In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR.

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

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

(5)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.

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 September 30, 2023, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total interest cost	$	316	$	376	$	956	$	1,118
Capitalized interest	(33)		(22)		(85)		(58)
Total interest expense, net of capitalized interest	$	283	$	354	$	871	$	1,060

Fair Value Disclosures

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

	September 30, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,938	$	22,052	$	25,086	$	23,500

(1)As of September 30, 2023 and December 31, 2022, $2.8 billion and $3.0 billion, respectively, of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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

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Leases

9 Months Ended

Sep. 30, 2023

Leases [Abstract]

Leases

LEASES

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

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

		September 30,		December 31,
	Consolidated Balance Sheets Location	2023		2022
Right-of-use assets—Operating	Operating lease assets	$	2,549	$	2,625
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	482		511
Total right-of-use assets		$	3,031	$	3,136
Current operating lease liabilities	Current operating lease liabilities	$	612	$	616
Current finance lease liabilities	Other current liabilities	35		28
Non-current operating lease liabilities	Operating lease liabilities	1,907		1,971
Non-current finance lease liabilities	Finance lease liabilities	476		494
Total lease liabilities		$	3,030	$	3,109

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

	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
Operating lease cost (a)	Operating costs and expenses (1)	$	185	$	213	$	583	$	604
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	13		1		37		3
Interest on lease liabilities	Interest expense, net of capitalized interest	11		2		27		7
Total lease cost		$	209	$	216	$	647	$	614
(a) Included in operating lease cost:
Short-term lease costs		$	6	$	16	$	31	$	80
Variable lease costs		1		7		15		16

(1)Presented in cost (recovery) of sales, operating and maintenance expense or selling, general and administrative expense consistent with the use of the asset under lease.

Future annual minimum lease payments for operating and finance leases as of September 30, 2023 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2023	$	167	$	17
2024	702		67
2025	583		72
2026	450		75
2027	353		77
Thereafter	687		427
Total lease payments (1)	2,942		735
Less: Interest	(423)		(224)
Present value of lease liabilities	$	2,519	$	511

(1)Does not include approximately $4.1 billion of legally binding minimum payments primarily for vessel charters executed as of September 30, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years.

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

	September 30, 2023		December 31, 2022
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.0	9.9	5.9	10.6
Weighted-average discount rate (1)	4.5%	7.7%	4.2%	7.8%

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

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

	Nine Months Ended September 30,
	2023		2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	538	$	524
Operating cash flows from finance leases	26		6
Financing cash flows from finance leases	20		1
Right-of-use assets obtained in exchange for operating lease liabilities	388		1,139
Right-of-use assets obtained in exchange for finance lease liabilities	8		23

LNG Vessel Subcharters

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Fixed income	$	96	$	122	$	327	$	188
Variable income	5		12		41		37
Total sublease income	$	101	$	134	$	368	$	225

Future annual minimum sublease payments to be received from LNG vessel subcharters as of September 30, 2023 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2023	$	76
2024	120
Thereafter	—
Total sublease payments	$	196

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Revenues

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Revenues

REVENUES

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues from contracts with customers
LNG revenues	$	3,941	$	8,422	$	14,950	$	23,774
Regasification revenues	34		455		101		591
Other revenues	50		27		120		78
Total revenues from contracts with customers	4,025		8,904		15,171		24,443
Net derivative gain (loss) (1)	33		(186)		34		(325)
Other (2)	101		134		366		225
Total revenues	$	4,159	$	8,852	$	15,571	$	24,343

(1)See Note 6—Derivative Instruments for additional information about our derivatives.

(2)Includes revenues from LNG vessel subcharters. See Note 10—Leases for additional information about our subleases.

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. (“Chevron”) entered into an agreement with SPLNG providing for the early termination of the TUA and an associated terminal marine services agreement between the parties and their affiliates (the “Termination Agreement”), effective July 2022, for a lump sum fee of $765 million (the “Termination Fee”). Obligations pursuant to the TUA and associated agreement, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million

annually (adjusted for inflation) from 2023 through 2029, terminated on December 31, 2022, upon SPLNG’s receipt of the Termination Fee in December 2022. We allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which was recognized ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations.

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):

	September 30,		December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	218	$	186

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

	Nine Months Ended September 30, 2023
Deferred revenue, beginning of period	$	320
Cash received but not yet recognized in revenue	345
Revenue recognized from prior period deferral	(320)
Deferred revenue, end of period	$	345

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:

	September 30, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	112.5	9	$	112.0	9
Regasification revenues	0.7		3	0.8		4
Total revenues	$	113.2		$	112.8

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

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

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

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	63	%	76	%	71	%	72	%
Regasification revenues	7	%	1	%	7	%	2	%

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Related Party Transactions

9 Months Ended

Sep. 30, 2023

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG Revenues
Natural Gas Transportation and Storage Agreements with a related party through Brookfield Asset Management, Inc. (“Brookfield”) (1)	$	—	$	—	$	—	$	4
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (2)	2		3		7		5
Cost of sales
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	—		—		—		1
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	5		—		9		—
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	14		18		44		45

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

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

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):

	September 30,		December 31,
	2023		2022
Trade and other receivables, net of current expected credit losses	$	2	$	1
Accrued liabilities	6		1

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Income Taxes

9 Months Ended

Sep. 30, 2023

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

We recorded an income tax provision of $440 million and $2.1 billion during the three and nine months ended September 30, 2023, respectively, which was calculated using the annual effective tax rate method. We recorded an income tax benefit of $752 million and $762 million during the three and nine months ended September 30, 2022, which was calculated using the year-to-date effective tax rate method.

Our effective tax rate was 17.4% and 17.2% for the three and nine months ended September 30, 2023, respectively, and 22.1% and 23.3% for the three and nine months ended September 30, 2022, respectively. The effective tax rate for the three and nine months ended September 30, 2023 represents a tax provision and was lower than the statutory rate of 21% primarily

due to CQP’s income that is not taxable to us. The effective tax rate for the three and nine months ended September 30, 2022 represents a tax benefit and was higher than the statutory rate of 21% primarily due to the foreign derived intangible income (“FDII”) deduction, which results in income from our sales to foreign customers being taxed at a lower effective tax rate. The year-to-date effective tax rate method was used for the three and nine months ended September 30, 2022 because a relatively small change in estimated ordinary income or loss caused significant changes to the estimated annual effective tax rate such that the annual effective tax rate did not provide a reliable estimate.

In August 2022, President Biden signed into U.S. federal law the Inflation Reduction Act which, among other things, introduced a new 15% corporate alternative minimum tax (“CAMT”), effective in 2023, that is based on 15% of an applicable corporation’s adjusted financial statement income (“AFSI”). A corporation is subject to the CAMT if its average AFSI over three prior years is greater than $1 billion (“Applicable Corporation”). We expect to become an Applicable Corporation beginning in 2024, but such timing is dependent on future earnings and the resultant impact of any future regulatory guidance issued by the U.S. Department of the Treasury and the Internal Revenue Service. The CAMT may accelerate and cause volatility in our cash tax payment obligations, particularly in periods of significant commodity, currency or financial market variability resulting in potential changes in the fair value of our derivative instruments.

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Net Income (Loss) Per Share Attributable to Common Stockholders

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Net Income (Loss) Per Share Attributable to Common Stockholders

NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net income (loss) attributable to common stockholders	$	1,701	$	(2,385)	$	8,504	$	(2,509)
Weighted average common shares outstanding:
Basic	240.2		249.9		242.1		252.5
Dilutive unvested stock	1.8		—		1.8		—
Diluted	242.0		249.9		243.9		252.5
Net income (loss) per share attributable to common stockholders—basic (1)	$	7.08	$	(9.54)	$	35.12	$	(9.94)
Net income (loss) per share attributable to common stockholders—diluted (1)	$	7.03	$	(9.54)	$	34.87	$	(9.94)
Dividends paid per common share	$	0.395	$	0.33	$	1.185	$	0.99

(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 October 30, 2023, we declared a quarterly dividend of $0.435 per share of common stock that is payable on November 17, 2023 to stockholders of record as of the close of business on November 9, 2023.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Unvested stock (1)	—	2.5	—	2.3
4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) (2)	—	—	—	0.2
Total potentially dilutive common shares	—	2.5	—	2.5

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

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

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Share Repurchase Programs

9 Months Ended

Sep. 30, 2023

Equity [Abstract]

Share Repurchase Programs

SHARE REPURCHASE PROGRAMS

On September 7, 2021, our board of directors (our “Board”) authorized a reset in the previously existing share repurchase program to $1.0 billion, inclusive of any amounts remaining under the previous authorization as of September 30, 2021, for an additional three years beginning on October 1, 2021. On September 12, 2022, our Board authorized an increase in the existing share repurchase program by $4.0 billion for an additional three years, beginning on October 1, 2022. The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total shares repurchased	2.21		0.60		7.57		4.97
Weighted average price paid per share	$	161.98	$	125.34	$	151.29	$	128.73
Total cost of repurchases (1)	$	357	$	75	$	1,145	$	640

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

As of September 30, 2023, we had approximately $2.5 billion remaining under our share repurchase program.

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Customer Concentration

9 Months Ended

Sep. 30, 2023

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

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

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2023	2022	2023	2022	2023	2022
Customer A	*	*	*	*	16%	*
Customer B	*	—%	*	*	12%	—%

* Less than 10%

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2023

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2023		2022
Cash paid during the period for interest on debt, net of amounts capitalized	$	906	$	891
Cash paid for income taxes, net	85		28
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net	204		217
Share-based compensation capitalized to property, plant and equipment	3		3
Non-cash conveyance of property, plant and equipment	—		17
Commitments due to equity method investments	14		—
Contribution of other non-current assets in exchange for equity method investment	30		—
Non-cash financing activity:
Unpaid dividends declared on unvested common stock	3		5
Unpaid repurchases of treasury stock inclusive of excise taxes	22		—

See Note 10—Leases for supplemental cash flow information related to our leases.

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Pay vs Performance Disclosure - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2023	Sep. 30, 2022
Pay vs Performance Disclosure
Net loss attributable to common stockholders	$ 1,701	$ 1,369	$ 5,434	$ (2,385)	$ 741	$ (865)	$ 8,504	$ (2,509)

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Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Nature of Operations and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2023

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, they 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, 2022.

Results of operations for the three and nine months ended September 30, 2023 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2023.

Recent Accounting Standards

Recent Accounting Standards

ASU 2020-04

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 9—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities subsequent to the effective date of ASU

2020-04. We elected to apply the optional expedients as applicable to certain modified or replaced facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

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

9 Months Ended

Sep. 30, 2023

Receivables [Abstract]

Schedule of Accounts and Other Receivables, Net of Current Expected Credit Losses

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

	September 30,		December 31,
	2023		2022
Trade receivables
SPL and CCL	$	418	$	922
Cheniere Marketing	323		917
Other receivables	70		105
Total trade and other receivables, net of current expected credit losses	$	811	$	1,944

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Inventory (Tables)

9 Months Ended

Sep. 30, 2023

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
LNG in-transit	$	82	$	356
LNG	90		212
Materials	199		194
Natural gas	27		60
Other	2		4
Total inventory	$	400	$	826

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

9 Months Ended

Sep. 30, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

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

	September 30,		December 31,
	2023		2022
LNG terminal
Terminal and interconnecting pipeline facilities	$	33,881	$	33,815
Site and related costs	461		451
Construction-in-process	2,981		1,685
Accumulated depreciation	(5,821)		(4,985)
Total LNG terminal, net of accumulated depreciation	31,502		30,966
Fixed assets and other
Computer and office equipment	36		33
Furniture and fixtures	20		20
Computer software	125		121
Leasehold improvements	69		48
Other	21		20
Accumulated depreciation	(202)		(191)
Total fixed assets and other, net of accumulated depreciation	69		51
Assets under finance leases
Marine assets	532		533
Accumulated depreciation	(50)		(22)
Total assets under finance leases, net of accumulated depreciation	482		511
Property, plant and equipment, net of accumulated depreciation	$	32,053	$	31,528

Schedule of Depreciation and Offsets to LNG Terminal Costs

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Depreciation expense	$	296	$	278	$	887	$	822
Offsets to LNG terminal costs (1)	—		—		—		204

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

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

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

	Fair Value Measurements as of
	September 30, 2023								December 31, 2022
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset (liability)	$	19	$	54	$	(3,216)	$	(3,143)	$	(66)	$	(29)	$	(9,924)	$	(10,019)
LNG Trading Derivatives asset (liability)	(29)		7		—		(22)		1		(47)		—		(46)
FX Derivatives asset (liability)	—		7		—		7		—		(28)		—		(28)

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of September 30, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(3,216)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.245) - $0.638 / $(0.031)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	83% - 422% / 188%

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

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

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Balance, beginning of period	$	(4,611)	$	(8,462)	$	(9,924)	$	(4,036)
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	1,197		(5,668)		5,350		(8,825)
Included in cost of sales, new deals (3)	8		—		26		—
Purchases and settlements:
Purchases (4)	—		4		—		(1,390)
Settlements (5)	187		322		1,323		446
Transfers out of level 3 (6)	3		(1)		9		—
Balance, end of period	$	(3,216)	$	(13,805)	$	(3,216)	$	(13,805)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	1,205	$	(5,668)	$	5,376	$	(8,825)

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

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

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

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

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

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

Fair Value of Derivative Instruments by Balance Sheet Location

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

	September 30, 2023
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	62	$	23	$	10	$	95
Derivative assets	620		—		—		620
Total derivative assets	682		23		10		715
Current derivative liabilities	(943)		(45)		(3)		(991)
Derivative liabilities	(2,882)		—		—		(2,882)
Total derivative liabilities	(3,825)		(45)		(3)		(3,873)
Derivative asset (liability), net	$	(3,143)	$	(22)	$	7	$	(3,158)
	December 31, 2022
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	36	$	84	$	—	$	120
Derivative assets	35		—		—		35
Total derivative assets	71		84		—		155
Current derivative liabilities	(2,143)		(130)		(28)		(2,301)
Derivative liabilities	(7,947)		—		—		(7,947)
Total derivative liabilities	(10,090)		(130)		(28)		(10,248)
Derivative liability, net	$	(10,019)	$	(46)	$	(28)	$	(10,093)

(1)Does not include collateral posted with counterparties by us of $1 million and $111 million as of September 30, 2023 and December 31, 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $1 million and zero as of September 30, 2023 and December 31, 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $72 million and $23 million, as of September 30, 2023 and December 31, 2022, respectively, which are included in margin deposits 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 September 30, 2023
Gross assets	$	1,161	$	23	$	10
Offsetting amounts	(479)		—		—
Net assets (1)	$	682	$	23	$	10
Gross liabilities	$	(3,911)	$	(51)	$	(3)
Offsetting amounts	86		6		—
Net liabilities (2)	$	(3,825)	$	(45)	$	(3)
As of December 31, 2022
Gross assets	$	76	$	87	$	—
Offsetting amounts	(5)		(3)		—
Net assets (1)	$	71	$	84	$	—
Gross liabilities	$	(10,436)	$	(132)	$	(29)
Offsetting amounts	346		2		1
Net liabilities (2)	$	(10,090)	$	(130)	$	(28)

(1)Includes current and non-current derivative assets of $95 million and $620 million, respectively, as of September 30, 2023 and $120 million and $35 million, respectively, as of December 31, 2022.

(2)Includes current and non-current derivative liabilities of $991 million and $2,882 million, respectively, as of September 30, 2023 and $2,301 million and $7,947 million, respectively, as of December 31, 2022.

Commodity Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

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

	September 30, 2023		December 31, 2022
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,542	6	14,504	50

(1)Excludes notional amounts associated with extension options that were uncertain to be taken as of September 30, 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 September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
LNG Trading Derivatives	LNG revenues	$	19	$	(237)	$	34	$	(454)
LNG Trading Derivatives	Recovery (cost) of sales	(8)		(4)		(95)		103
Liquefaction Supply Derivatives (2)	LNG revenues	1		(3)		(5)		8
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales	1,403		(5,508)		6,900		(10,008)

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

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

FX Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Derivative Instruments, Gain (Loss)

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

		Gain Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
FX Derivatives	LNG revenues	$	13	$	54	$	5	$	121

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Non-Controlling Interest and Variable Interest Entity (Tables)

9 Months Ended

Sep. 30, 2023

CQP [Member]

Noncontrolling Interest and Variable Interest Entity [Line Items]

Condensed Balance Sheet of Cheniere Partners

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

	September 30,		December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	499	$	904
Restricted cash and cash equivalents	35		92
Trade and other receivables, net of current expected credit losses	287		627
Other current assets	225		269
Total current assets	1,046		1,892
Property, plant and equipment, net of accumulated depreciation	16,341		16,725
Other non-current assets, net	377		288
Total assets	$	17,764	$	18,905
LIABILITIES
Current liabilities
Accrued liabilities	$	646	$	1,384
Current debt, net of discount and debt issuance costs	349		—
Current derivative liabilities	294		769
Other current liabilities	217		191
Total current liabilities	1,506		2,344
Long-term debt, net of premium, discount and debt issuance costs	15,600		16,198
Derivative liabilities	1,731		3,024
Other non-current liabilities	141		98
Total liabilities	$	18,978	$	21,664

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Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2023

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2023		2022
Natural gas purchases	$	607	$	1,621
Interest costs and related debt fees	260		383
LNG terminals and related pipeline costs	244		240
Compensation and benefits	118		245
LNG purchases	22		88
Other accrued liabilities	182		102
Total accrued liabilities	$	1,433	$	2,679

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Debt (Tables)

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Schedule of Debt Instruments

Debt consisted of the following (in millions): 

	September 30,		December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.75% due 2024 (the “2024 SPL Senior Notes”)	$	350	$	2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,482		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,482		12,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
5.95% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
CCH:
Senior Secured Notes:
7.000% due 2024 (the “2024 CCH Senior Notes”)	—		498
5.875% due 2025	1,491		1,491
5.125% due 2027	1,201		1,271
3.700% due 2029	1,125		1,361
3.788% weighted average rate due 2039	2,539		2,633
Total CCH Senior Secured Notes	6,356		7,254
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”) (1)	—		—
Total debt - CCH	6,356		7,254
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		1,500
Total debt	23,938		25,086
Current debt, net of discount and debt issuance costs	(349)		(813)
Long-term portion of unamortized discount and debt issuance costs, net	(200)		(218)
Total long-term debt, net of discount and debt issuance costs	$	23,389	$	24,055

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

Schedule of Line of Credit Facilities and Delayed Draw Term Loan

Below is a summary of our committed credit facilities outstanding as of September 30, 2023 (in millions):

	SPL Revolving Credit Facility (1)		CQP Revolving Credit Facility (1)		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility (2)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	284		—		—		155		—
Available commitment	$	716	$	1,000	$	3,260	$	1,345	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (3)	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 0.115% - 0.365%
Commitment fees on undrawn balance (3)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365% (4)
Maturity date	June 23, 2028		June 23, 2028		(5)		June 15, 2027		October 28, 2026

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

(2)In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR.

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

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

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

Schedule of Interest Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total interest cost	$	316	$	376	$	956	$	1,118
Capitalized interest	(33)		(22)		(85)		(58)
Total interest expense, net of capitalized interest	$	283	$	354	$	871	$	1,060

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):

	September 30, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,938	$	22,052	$	25,086	$	23,500

(1)As of September 30, 2023 and December 31, 2022, $2.8 billion and $3.0 billion, respectively, of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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Leases (Tables)

9 Months Ended

Sep. 30, 2023

Leases [Abstract]

Schedule of Leases, Balance Sheet Location

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

		September 30,		December 31,
	Consolidated Balance Sheets Location	2023		2022
Right-of-use assets—Operating	Operating lease assets	$	2,549	$	2,625
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	482		511
Total right-of-use assets		$	3,031	$	3,136
Current operating lease liabilities	Current operating lease liabilities	$	612	$	616
Current finance lease liabilities	Other current liabilities	35		28
Non-current operating lease liabilities	Operating lease liabilities	1,907		1,971
Non-current finance lease liabilities	Finance lease liabilities	476		494
Total lease liabilities		$	3,030	$	3,109

Schedule of Lease Cost, Income Statement Location

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

	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
Operating lease cost (a)	Operating costs and expenses (1)	$	185	$	213	$	583	$	604
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	13		1		37		3
Interest on lease liabilities	Interest expense, net of capitalized interest	11		2		27		7
Total lease cost		$	209	$	216	$	647	$	614
(a) Included in operating lease cost:
Short-term lease costs		$	6	$	16	$	31	$	80
Variable lease costs		1		7		15		16

(1)Presented in cost (recovery) of sales, operating and maintenance expense or selling, general and administrative expense consistent with the use of the asset under lease.

Schedule of Maturity of Lease Liabilities

Future annual minimum lease payments for operating and finance leases as of September 30, 2023 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2023	$	167	$	17
2024	702		67
2025	583		72
2026	450		75
2027	353		77
Thereafter	687		427
Total lease payments (1)	2,942		735
Less: Interest	(423)		(224)
Present value of lease liabilities	$	2,519	$	511

(1)Does not include approximately $4.1 billion of legally binding minimum payments primarily for vessel charters executed as of September 30, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years.

Lease, Other Quantitative Information

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

	September 30, 2023		December 31, 2022
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.0	9.9	5.9	10.6
Weighted-average discount rate (1)	4.5%	7.7%	4.2%	7.8%

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

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

	Nine Months Ended September 30,
	2023		2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	538	$	524
Operating cash flows from finance leases	26		6
Financing cash flows from finance leases	20		1
Right-of-use assets obtained in exchange for operating lease liabilities	388		1,139
Right-of-use assets obtained in exchange for finance lease liabilities	8		23

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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Fixed income	$	96	$	122	$	327	$	188
Variable income	5		12		41		37
Total sublease income	$	101	$	134	$	368	$	225

Sublease Payment to be Received, Fiscal Year Maturity

Future annual minimum sublease payments to be received from LNG vessel subcharters as of September 30, 2023 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2023	$	76
2024	120
Thereafter	—
Total sublease payments	$	196

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Revenues (Tables)

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues from contracts with customers
LNG revenues	$	3,941	$	8,422	$	14,950	$	23,774
Regasification revenues	34		455		101		591
Other revenues	50		27		120		78
Total revenues from contracts with customers	4,025		8,904		15,171		24,443
Net derivative gain (loss) (1)	33		(186)		34		(325)
Other (2)	101		134		366		225
Total revenues	$	4,159	$	8,852	$	15,571	$	24,343

(1)See Note 6—Derivative Instruments for additional information about our derivatives.

(2)Includes revenues from LNG vessel subcharters. See Note 10—Leases for additional information about our subleases.

Contract Assets

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

	September 30,		December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	218	$	186

Contract Liabilities

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

	Nine Months Ended September 30, 2023
Deferred revenue, beginning of period	$	320
Cash received but not yet recognized in revenue	345
Revenue recognized from prior period deferral	(320)
Deferred revenue, end of period	$	345

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:

	September 30, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	112.5	9	$	112.0	9
Regasification revenues	0.7		3	0.8		4
Total revenues	$	113.2		$	112.8

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

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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	63	%	76	%	71	%	72	%
Regasification revenues	7	%	1	%	7	%	2	%

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2023

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG Revenues
Natural Gas Transportation and Storage Agreements with a related party through Brookfield Asset Management, Inc. (“Brookfield”) (1)	$	—	$	—	$	—	$	4
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (2)	2		3		7		5
Cost of sales
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	—		—		—		1
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	5		—		9		—
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	14		18		44		45

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

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

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):

	September 30,		December 31,
	2023		2022
Trade and other receivables, net of current expected credit losses	$	2	$	1
Accrued liabilities	6		1

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Net Income (Loss) Per Share Attributable to Common Stockholders (Tables)

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net income (loss) attributable to common stockholders	$	1,701	$	(2,385)	$	8,504	$	(2,509)
Weighted average common shares outstanding:
Basic	240.2		249.9		242.1		252.5
Dilutive unvested stock	1.8		—		1.8		—
Diluted	242.0		249.9		243.9		252.5
Net income (loss) per share attributable to common stockholders—basic (1)	$	7.08	$	(9.54)	$	35.12	$	(9.94)
Net income (loss) per share attributable to common stockholders—diluted (1)	$	7.03	$	(9.54)	$	34.87	$	(9.94)
Dividends paid per common share	$	0.395	$	0.33	$	1.185	$	0.99

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

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Unvested stock (1)	—	2.5	—	2.3
4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) (2)	—	—	—	0.2
Total potentially dilutive common shares	—	2.5	—	2.5

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

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

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Share Repurchase Programs (Tables)

9 Months Ended

Sep. 30, 2023

Equity [Abstract]

Schedule of Share Repurchases Under the Share Repurchase Program

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total shares repurchased	2.21		0.60		7.57		4.97
Weighted average price paid per share	$	161.98	$	125.34	$	151.29	$	128.73
Total cost of repurchases (1)	$	357	$	75	$	1,145	$	640

(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)

9 Months Ended

Sep. 30, 2023

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

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

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2023	2022	2023	2022	2023	2022
Customer A	*	*	*	*	16%	*
Customer B	*	—%	*	*	12%	—%

* Less than 10%

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2023

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Nine Months Ended September 30,
	2023		2022
Cash paid during the period for interest on debt, net of amounts capitalized	$	906	$	891
Cash paid for income taxes, net	85		28
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net	204		217
Share-based compensation capitalized to property, plant and equipment	3		3
Non-cash conveyance of property, plant and equipment	—		17
Commitments due to equity method investments	14		—
Contribution of other non-current assets in exchange for equity method investment	30		—
Non-cash financing activity:
Unpaid dividends declared on unvested common stock	3		5
Unpaid repurchases of treasury stock inclusive of excise taxes	22		—

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Nature of Operations and Basis of Presentation (Details)	9 Months Ended
	Sep. 30, 2023 unit mi milliontonnes / yr item trains
Organization and Nature of Operations [Line Items]
Number Of Natural Gas Liquefaction And Export Facilities | unit	2
Sabine Pass LNG Terminal [Member]
Organization and Nature of Operations [Line Items]
Number of Liquefaction LNG Trains Operating | trains	6
Total Production Capability	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	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 | trains	7
Corpus Christi Stage 3 Project | Minimum [Member]
Organization and Nature of Operations [Line Items]
Total Production Capability	10
Corpus Christi Pipeline [Member]
Organization and Nature of Operations [Line Items]
Length of Natural Gas Pipeline | mi	21.5
Corpus Christi LNG Terminal Expansion [Member]
Organization and Nature of Operations [Line Items]
Total Production Capability	3
Number of Liquefaction LNG Trains | trains	2
Sabine Pass LNG Terminal Expansion
Organization and Nature of Operations [Line Items]
Total Production Capability	20
CQP [Member]
Organization and Nature of Operations [Line Items]
General Partner ownership percentage	100.00%
Limited Partner ownership percentage	48.60%

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Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Sep. 30, 2023		Dec. 31, 2022
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 422	[1]	$ 1,134
SPL Project and CCL Project
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 422		$ 1,100

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 7—Non-controlling Interest and Variable Interest Entity. As of September 30, 2023, total assets and liabilities of CQP were $17.8 billion and $19.0 billion, respectively, including $499 million of cash and cash equivalents and $35 million of restricted cash and cash equivalents.

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Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Accounts and Other Receivables [Line Items]
Other receivables	$ 70	$ 105
Total trade and other receivables, net of current expected credit losses	811	1,944
SPL and CCL
Accounts and Other Receivables [Line Items]
Trade receivables	418	922
Cheniere Marketing
Accounts and Other Receivables [Line Items]
Trade receivables	$ 323	$ 917

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Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Inventory [Line Items]
Inventory	$ 400	$ 826
LNG in-transit [Member]
Inventory [Line Items]
Inventory	82	356
LNG [Member]
Inventory [Line Items]
Inventory	90	212
Materials [Member]
Inventory [Line Items]
Inventory	199	194
Natural gas [Member]
Inventory [Line Items]
Inventory	27	60
Other [Member]
Inventory [Line Items]
Inventory	$ 2	$ 4

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 32,053	$ 31,528
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(5,821)	(4,985)
Property, plant and equipment, net of accumulated depreciation	31,502	30,966
Terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	33,881	33,815
Site and related costs [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	461	451
Construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,981	1,685
Fixed assets and other [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(202)	(191)
Property, plant and equipment, net of accumulated depreciation	69	51
Computer and office equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	36	33
Furniture and fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	20	20
Computer software [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	125	121
Leasehold improvements [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	69	48
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	21	20
Assets under finance leases [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	532	533
Accumulated depreciation	(50)	(22)
Property, plant and equipment, net of accumulated depreciation	$ 482	$ 511

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 296	$ 278	$ 887	$ 822
Offsets to LNG terminal costs	[1]	$ 0	$ 0	$ 0	$ 204

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

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Derivative Instruments - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Dec. 31, 2022
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	$ 266	$ 619
FX Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	1 year

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (3,143)	$ (10,019)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	19	(66)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	54	(29)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(3,216)	(9,924)
LNG Trading Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(22)	(46)
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(29)	1
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	7	(47)
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
FX Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	7	(28)
FX Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
FX Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	7	(28)
FX Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	9 Months Ended
	Sep. 30, 2023 USD ($)
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Net Fair Value Liabilities	$ (3,216,000,000)
Valuation, Market Approach [Member] | Minimum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	(1.245)	[1]
Valuation, Market Approach [Member] | Maximum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	0.638	[1]
Valuation, Market Approach [Member] | Weighted Average [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	$ (0.031)	[1]
Valuation Technique, Option Pricing Model [Member] | Minimum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	83.00%	[1],[2]
Valuation Technique, Option Pricing Model [Member] | Maximum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	422.00%	[1],[2]
Valuation Technique, Option Pricing Model [Member] | Weighted Average [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	188.00%	[1],[2]

[1] Unobservable inputs were weighted by the relative fair value of the instruments.

[2] Spread contemplates U.S. dollar-denominated pricing.

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Derivative Instruments - Schedule of Level 3 Derivatives Activity (Details) - Physical Liquefaction Supply Derivatives and Physical LNG Trading Derivative - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Fair Value, Assets (Liabilities) Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (4,611)	$ (8,462)	$ (9,924)	$ (4,036)
Realized and change in fair value gains (losses) included in net income:
Included in cost of sales, existing deals	[1],[2]	1,197	(5,668)	5,350	(8,825)
Included in cost of sales, new deals	[1],[3]	8	0	26	0
Purchases and settlements:
Purchases	[4]	0	4	0	(1,390)
Settlements	[5]	187	322	1,323	446
Transfers out of level 3	[6]	3	(1)	9	0
Balance, end of period		(3,216)	(13,805)	(3,216)	(13,805)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period		$ 1,205	$ (5,668)	$ 5,376	$ (8,825)

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

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

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

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

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

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

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Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - tbtu	Sep. 30, 2023		Dec. 31, 2022
Liquefaction Supply Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	13,542	[1]	14,504
LNG Trading Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6		50

[1] Excludes notional amounts associated with extension options that were uncertain to be taken as of September 30, 2023.

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
LNG Trading Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 19	$ (237)	$ 34	$ (454)
LNG Trading Derivatives [Member] | Recovery (cost) of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	(8)	(4)	(95)	103
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	1	(3)	(5)	8
Liquefaction Supply Derivatives [Member] | Recovery (cost) of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	1,403	(5,508)	6,900	(10,008)
FX Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 13	$ 54	$ 5	$ 121
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 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		Sep. 30, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Current derivative assets		$ 95	$ 120
Derivative assets		620	35
Total derivative assets		715	155
Current derivative liabilities		(991)	(2,301)
Derivative liabilities		(2,882)	(7,947)
Total derivative liabilities		(3,873)	(10,248)
Derivative asset (liability), net		$ (3,158)	$ (10,093)
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]		Current derivative assets	Current derivative assets
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Derivative assets	Derivative assets
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]		Current derivative liabilities	Current derivative liabilities
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Derivative liabilities	Derivative liabilities
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[1]	$ 62	$ 36
Derivative assets	[1]	620	35
Total derivative assets	[1]	682	71
Current derivative liabilities	[1]	(943)	(2,143)
Derivative liabilities	[1]	(2,882)	(7,947)
Total derivative liabilities	[1]	(3,825)	(10,090)
Derivative asset (liability), net	[1]	(3,143)	(10,019)
Derivative, collateral posted by counterparties		1	0
Derivative, collateral posted by us		1	111
LNG Trading Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[2]	23	84
Derivative assets	[2]	0	0
Total derivative assets	[2]	23	84
Current derivative liabilities	[2]	(45)	(130)
Derivative liabilities	[2]	0	0
Total derivative liabilities	[2]	(45)	(130)
Derivative asset (liability), net	[2]	(22)	(46)
Derivative, collateral posted by us		72	23
FX Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets		10	0
Derivative assets		0	0
Total derivative assets		10	0
Current derivative liabilities		(3)	(28)
Derivative liabilities		0	0
Total derivative liabilities		(3)	(28)
Derivative asset (liability), net		$ 7	$ (28)

[1] Does not include collateral posted with counterparties by us of $1 million and $111 million as of September 30, 2023 and December 31, 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $1 million and zero as of September 30, 2023 and December 31, 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

[2] Does not include collateral posted with counterparties by us of $72 million and $23 million, as of September 30, 2023 and December 31, 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets.

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Derivative Instruments - Derivative Net Presentation on Consolidated Balance Sheets (Details) - USD ($) $ in Millions		Sep. 30, 2023	Dec. 31, 2022
Derivative [Line Items]
Current derivative assets		$ 95	$ 120
Derivative assets		620	35
Derivative Liability, Current		(991)	(2,301)
Derivative Liability, Noncurrent		(2,882)	(7,947)
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		1,161	76
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(479)	(5)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	682	71
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(3,911)	(10,436)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		86	346
Derivative Assets (Liabilities), at Fair Value, Net	[2]	(3,825)	(10,090)
LNG Trading Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		23	87
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		0	(3)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	23	84
LNG Trading Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(51)	(132)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		6	2
Derivative Assets (Liabilities), at Fair Value, Net	[2]	(45)	(130)
FX Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		10	0
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		0	0
Derivative Assets (Liabilities), at Fair Value, Net	[1]	10	0
FX Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(3)	(29)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		0	1
Derivative Assets (Liabilities), at Fair Value, Net	[2]	$ (3)	$ (28)

[1] Includes current and non-current derivative assets of $95 million and $620 million, respectively, as of September 30, 2023 and $120 million and $35 million, respectively, as of December 31, 2022.

[2] Includes current and non-current derivative liabilities of $991 million and $2,882 million, respectively, as of September 30, 2023 and $2,301 million and $7,947 million, respectively, as of December 31, 2022.

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Non-Controlling Interest and Variable Interest Entity (Details) - USD ($) shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2023		Dec. 31, 2022
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 3,861	[1]	$ 1,353
Restricted cash and cash equivalents	422	[1]	1,134
Other current assets, net	107		97
Total current assets	5,769		5,608
Property, plant and equipment, net of accumulated depreciation	32,053		31,528
Other non-current assets, net	611		529
Total assets	41,719	[1]	41,266
Accrued liabilities	1,433		2,679
Current debt, net of discount and debt issuance costs	349		813
Current derivative liabilities	991		2,301
Other current liabilities	38		28
Total current liabilities	3,758		6,795
Long-term debt, net of discount and debt issuance costs	23,389		24,055
Derivative liabilities	2,882		7,947
Other non-current liabilities	$ 222		175
CQP [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Limited Partner ownership percentage	48.60%
General Partner ownership percentage	100.00%
CQP [Member] | Common Units [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Partners Capital Account, Units, Units Held	239.9
CQP [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 499		904
Restricted cash and cash equivalents	35		92
Trade and other receivables, net of current expected credit losses	287		627
Other current assets, net	225		269
Total current assets	1,046		1,892
Property, plant and equipment, net of accumulated depreciation	16,341		16,725
Other non-current assets, net	377		288
Total assets	17,764		18,905
Accrued liabilities	646		1,384
Current debt, net of discount and debt issuance costs	349		0
Current derivative liabilities	294		769
Other current liabilities	217		191
Total current liabilities	1,506		2,344
Long-term debt, net of discount and debt issuance costs	15,600		16,198
Derivative liabilities	1,731		3,024
Other non-current liabilities	141		98
Total liabilities	$ 18,978		$ 21,664

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 7—Non-controlling Interest and Variable Interest Entity. As of September 30, 2023, total assets and liabilities of CQP were $17.8 billion and $19.0 billion, respectively, including $499 million of cash and cash equivalents and $35 million of restricted cash and cash equivalents.

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Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Accrued Liabilities, Current [Abstract]
Natural gas purchases	$ 607	$ 1,621
Interest costs and related debt fees	260	383
LNG terminals and related pipeline costs	244	240
Compensation and benefits	118	245
LNG purchases	22	88
Other accrued liabilities	182	102
Total accrued liabilities	$ 1,433	$ 2,679

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 23,938	$ 25,086
Current portion of long-term debt		(349)	(813)
Long-term portion of unamortized discount and debt issuance costs, net		(200)	(218)
Total Long-Term Debt, Net of Premium, Discount and Debt Issuance Costs		23,389	24,055
SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		10,482	12,132
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 350	2,000
Debt Instrument, Interest Rate, Stated Percentage		5.75%
2025 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		5.875%
2027 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,350	1,350
Debt Instrument, Interest Rate, Stated Percentage		4.20%
2030 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage		4.50%
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,782	1,782
2037 SPL Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.746%
SPL Working Capital Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
SPL Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		0	0
CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		5,600	4,200
2029 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.50%
2031 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.00%
2032 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,200	1,200
Debt Instrument, Interest Rate, Stated Percentage		3.25%
2033 Cheniere Energy Partners Senior Notes
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,400	0
Debt Instrument, Interest Rate, Stated Percentage		5.95%
CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
CQP Revolving Credit Facility
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		0	0
CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		6,356	7,254
2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	498
Debt Instrument, Interest Rate, Stated Percentage		7.00%
2025 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,491	1,491
Debt Instrument, Interest Rate, Stated Percentage		5.875%
2027 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,201	1,271
Debt Instrument, Interest Rate, Stated Percentage		5.125%
2029 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,125	1,361
Debt Instrument, Interest Rate, Stated Percentage		3.70%
2039 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 2,539	2,633
2039 CCH Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.788%
CCH Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
CCH Working Capital Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[1]	0	0
2028 Cheniere Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.625%
Cheniere Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
Cheniere [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		1,500	1,500
SPL [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		10,482	12,132
CQP [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		5,600	4,200
CCH [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 6,356	$ 7,254

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

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Debt - Credit Facilities Table (Details) $ in Millions	9 Months Ended
	Sep. 30, 2023 USD ($) unit Rate
Line of Credit Facility [Line Items]
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio | unit	1.25
SPL Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size | $	$ 1,000	[1]
Outstanding balance | $	0	[1]
Letters of credit issued | $	284	[1]
Available commitment | $	$ 716	[1]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Jun. 23, 2028	[1]
SPL Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.075%	[1],[2]
SPL Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[1],[2]
SPL Revolving Credit Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate | Rate	0.10%	[1],[2]
SPL Revolving Credit Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.00%	[1],[2]
SPL Revolving Credit Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.75%	[1],[2]
SPL Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.00%	[1],[2]
SPL Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.75%	[1],[2]
CQP Revolving Credit Facility
Line of Credit Facility [Line Items]
Total facility size | $	$ 1,000	[1]
Outstanding balance | $	0	[1]
Letters of credit issued | $	0	[1]
Available commitment | $	$ 1,000	[1]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Jun. 23, 2028	[1]
CQP Revolving Credit Facility | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%	[1],[2]
CQP Revolving Credit Facility | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[1],[2]
CQP Revolving Credit Facility | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate | Rate	0.10%	[1],[2]
CQP Revolving Credit Facility | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.125%	[1],[2]
CQP Revolving Credit Facility | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	2.00%	[1],[2]
CQP Revolving Credit Facility | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.125%	[1],[2]
CQP Revolving Credit Facility | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.00%	[1],[2]
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
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Line of Credit Facility, Commitment Fee Percentage	0.525%	[2]
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 | Rate	0.10%	[2]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.50%	[2]
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%	[2]
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size | $	$ 1,500
Outstanding balance - current | $	0
Letters of credit issued | $	155
Available commitment | $	$ 1,345
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
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%	[2]
CCH Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.20%	[2]
CCH Working Capital Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate | Rate	0.10%	[2]
CCH Working Capital Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.00%	[2]
CCH Working Capital Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.50%	[2]
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%	[2]
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%	[2]
Cheniere Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size | $	$ 1,250	[3]
Outstanding balance | $	0	[3]
Letters of credit issued | $	0	[3]
Available commitment | $	$ 1,250	[3]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Oct. 28, 2026	[3]
Cheniere Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.115%	[2],[3],[4]
Cheniere Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.365%	[2],[3],[4]
Cheniere Revolving Credit Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate | Rate	0.10%	[2],[3]
Cheniere Revolving Credit Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.075%	[2],[3]
Cheniere Revolving Credit Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	2.20%	[2],[3]
Cheniere Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.115%	[2],[3]
Cheniere Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.365%	[2],[3]

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

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

[3] In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR.

[4] In April 2023, the commitment fees for the Cheniere Revolving Credit Facility were reduced as a result of achieving certain ESG metrics.

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Debt Disclosure [Abstract]
Total interest cost	$ 316	$ 376	$ 956	$ 1,118
Capitalized interest	(33)	(22)	(85)	(58)
Total interest expense, net of capitalized interest	$ 283	$ 354	$ 871	$ 1,060

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2023	Dec. 31, 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 23,938	$ 25,086
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 and Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		23,938	25,086
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 and Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	22,052	23,500
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value		$ 2,800	$ 3,000

[1] As of September 30, 2023 and December 31, 2022, $2.8 billion and $3.0 billion, respectively, of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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Leases - Balance Sheet Location Table (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Leases [Abstract]
Right-of-use assets—Operating	$ 2,549	$ 2,625
Right-of-use assets—Financing	482	511
Total right-of-use assets	3,031	3,136
Current operating lease liabilities	612	616
Current finance lease liabilities	35	28
Operating lease liabilities	1,907	1,971
Non-current finance lease liabilities	476	494
Total lease liabilities	$ 3,030	$ 3,109
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Right-of-use assets—Operating	Right-of-use assets—Operating
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Property, plant and equipment, net of accumulated depreciation	Property, plant and equipment, net of accumulated depreciation
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Current operating lease liabilities	Current operating lease liabilities
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Operating lease liabilities	Operating lease liabilities
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Non-current finance lease liabilities	Non-current finance lease liabilities

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Leases - Income Statement Location Table (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Finance lease cost:
Total lease cost		$ 209	$ 216	$ 647	$ 614
Operating costs and expenses [Member]
Lessee, Lease, Description [Line Items]
Operating lease cost	[1]	185	213	583	604
Finance lease cost:
Short-term lease costs		6	16	31	80
Variable lease costs		1	7	15	16
Depreciation and amortization expense [Member]
Finance lease cost:
Amortization of right-of-use assets		13	1	37	3
Interest expense, net of capitalized interest [Member]
Finance lease cost:
Interest on lease liabilities		$ 11	$ 2	$ 27	$ 7

[1] Presented in cost (recovery) of sales, operating and maintenance expense or selling, general and administrative expense consistent with the use of the asset under lease.

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Leases - Future Minimum Payments Table (Details) $ in Millions	Sep. 30, 2023 USD ($)
Operating Leases, Future Minimum Payments
2023	$ 167
2024	702
2025	583
2026	450
2027	353
Thereafter	687
Total lease payments	2,942	[1]
Less: Interest	(423)
Present value of lease liabilities	2,519
Finance Leases, Future Minimum Payments
2023	17
2024	67
2025	72
2026	75
2027	77
Thereafter	427
Total lease payments	735	[1]
Less: Interest	(224)
Present value of lease liabilities	511
Operating Lease, Lease Not yet Commenced, Payments Due	$ 4,100
Maximum [Member]
Finance Leases, Future Minimum Payments
Operating Leases, Lease Not yet Commenced, Term of Contract	15 years

[1] Does not include approximately $4.1 billion of legally binding minimum payments primarily for vessel charters executed as of September 30, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years.

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Leases - Other Quantitative Information (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Operating Leases
Weighted-average remaining lease term		6 years		5 years 10 months 24 days
Weighted-average discount rate	[1]	4.50%		4.20%
Finance Leases
Weighted-average remaining lease term		9 years 10 months 24 days		10 years 7 months 6 days
Weighted-average discount rate	[1]	7.70%		7.80%
Operating cash flows from operating leases		$ 538	$ 524
Operating cash flows from finance leases		26	6
Payments of finance lease liabilities		20	1
Right-of-use assets obtained in exchange for operating lease liabilities		388	1,139
Right-of-use assets obtained in exchange for finance lease liabilities		$ 8	$ 23

[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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Leases - Subleases (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Lessor, Operating Lease, Description
Sublease Income, Fixed	$ 96	$ 122	$ 327	$ 188
Sublease Income, Variable	5	12	41	37
Sublease Income, Total	101	$ 134	368	$ 225
Operating Leases, Future Minimum Payments Receivable
2023	76		76
2024	120		120
Thereafter	0		0
Total sublease payments	$ 196		$ 196

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Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 4,025	$ 8,904	$ 15,171	$ 24,443
Net derivative gain (loss)	[1]	33	(186)	34	(325)
Other revenues	[2]	101	134	366	225
Total revenues		4,159	8,852	15,571	24,343
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		3,941	8,422	14,950	23,774
Total revenues		3,974	8,236	14,984	23,449
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		34	455	101	591
Total revenues		34	455	101	591
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		50	27	120	78
Total revenues		$ 151	$ 161	$ 486	$ 303

[1] See Note 6—Derivative Instruments for additional information about our derivatives.

[2] Includes revenues from LNG vessel subcharters. See Note 10—Leases for additional information about our subleases.

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Revenues - Termination Agreement with Chevron (Details) - Chevron U.S.A. Inc. - USD ($) $ in Millions	1 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2022
Revenue from External Customer [Line Items]
Contract Termination Fee	$ 765
Terminated commitments [Member]
Revenue from External Customer [Line Items]
Contract Termination Fee		$ 796
Regasification [Member]
Revenue from External Customer [Line Items]
Revenue Performance Obligation Fixed Consideration			$ 125

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Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 218	$ 186
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	320
Cash received but not yet recognized in revenue	345
Revenue recognized from prior period deferral	(320)
Deferred revenue, end of period	$ 345

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Revenues - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Sep. 30, 2023	Dec. 31, 2022
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 112.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 113.2
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 112.0
Weighted Average Recognition Timing	[1]		9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 112.5
Weighted Average Recognition Timing	[1]	9 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 0.8
Weighted Average Recognition Timing	[1]		4 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 0.7
Weighted Average Recognition Timing	[1]	3 years

[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.

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Revenues - Remaining Performance Obligation, Variable Consideration (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
LNG [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	63.00%	76.00%	71.00%	72.00%
Regasification [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	7.00%	1.00%	7.00%	2.00%

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Related Party Transaction [Line Items]
Revenues		$ 4,159	$ 8,852	$ 15,571	$ 24,343
Cost of sales		556	11,073	(71)	24,161
Operating and maintenance expense		445	419	1,376	1,227
Trade and other receivables, net of current expected credit losses		811		811		$ 1,944
Accrued liabilities		1,433		1,433		2,679
Related Party
Related Party Transaction [Line Items]
Trade and other receivables, net of current expected credit losses		2		2		1
Accrued liabilities		6		6		$ 1
LNG [Member]
Related Party Transaction [Line Items]
Revenues		3,974	8,236	14,984	23,449
Other [Member]
Related Party Transaction [Line Items]
Revenues		151	161	486	303
Natural Gas Transportation and Storage Agreements [Member] | Midship Pipeline
Related Party Transaction [Line Items]
Operating and maintenance expense	[1]	5	0	9	0
Natural Gas Transportation and Storage Agreements [Member] | Related Party through Brookfield Ownership
Related Party Transaction [Line Items]
Cost of sales	[2]	0	0	0	1
Operating and maintenance expense	[2]	14	18	44	45
Natural Gas Transportation and Storage Agreements [Member] | LNG [Member] | Related Party through Brookfield Ownership
Related Party Transaction [Line Items]
Revenues	[2]	0	0	0	4
Operation and Maintenance Agreement [Member] | Other [Member] | Midship Pipeline
Related Party Transaction [Line Items]
Revenues	[1]	$ 2	$ 3	$ 7	$ 5

[1] 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		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Income Tax Disclosure [Abstract]
Income tax provision (benefit)	$ 440	$ (752)	$ 2,119	$ (762)
Effective Income Tax Rate	17.40%	22.10%	17.20%	23.30%
Income Tax Rate, Corporate Alternative Minimum Tax			15.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			21.00%
Average Three Year Adjusted Financial Statement Income Threshold For Applicable Corporation			$ 1,000

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Net Income (Loss) Per Share Attributable to Common Stockholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended						9 Months Ended
		Oct. 30, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2023	Sep. 30, 2022
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net loss attributable to common stockholders			$ 1,701	$ 1,369	$ 5,434	$ (2,385)	$ 741	$ (865)	$ 8,504	$ (2,509)
Weighted average number of common shares outstanding, basic			240.2			249.9			242.1	252.5
Dilutive Unvested Stock			1.8			0.0			1.8	0.0
Weighted Average Number of Shares Outstanding, Diluted			242.0			249.9			243.9	252.5
Net income (loss) per share attributable to common stockholders—basic (1)	[1]		$ 7.08			$ (9.54)			$ 35.12	$ (9.94)
Net income (loss) per share attributable to common stockholders—diluted (1)	[1]		7.03			(9.54)			34.87	(9.94)
Common Stock, Dividends, Per Share, Declared			$ 0.395			$ 0.33			$ 1.185	$ 0.99
Antidilutive securities excluded from computation of earnings per share			0.0			2.5			0.0	2.5
Cheniere [Member] | 2045 Cheniere Convertible Senior Notes [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.25%						4.25%
Subsequent Event [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Common Stock, Dividends, Per Share, Declared		$ 0.435
Unvested stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	[2]		0.0			2.5			0.0	2.3
2045 Cheniere Convertible Senior Notes [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	[3]		0.0			0.0			0.0	0.2

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

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

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

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Share Repurchase Programs - Narrative (Details) - USD ($) $ in Millions		9 Months Ended
	Oct. 01, 2022	Sep. 30, 2021	Sep. 30, 2023
Share Repurchases [Line Items]
Stock Repurchase Program, Authorized Amount		$ 1,000
Stock Repurchase Program, Period in Force		3 years
Stock Repurchase Program, Remaining Authorized Repurchase Amount			$ 2,500
Subsequent Board Approved Increase [Member]
Share Repurchases [Line Items]
Stock Repurchase Program, Period in Force	3 years
Stock Repurchase Program, Increased in Authorized Amount	$ 4,000

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Share Repurchase Programs - Schedule of Share Repurchases (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Equity [Abstract]
Total shares repurchased		2,210	600	7,570	4,970
Weighted average price paid per share		$ 161.98	$ 125.34	$ 151.29	$ 128.73
Total cost of repurchases	[1]	$ 357	$ 75	$ 1,145	$ 640

[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	9 Months Ended	12 Months Ended
	Sep. 30, 2022	Sep. 30, 2023	Dec. 31, 2022
Customer A [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		16.00%
Customer B [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		12.00%	0.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized	$ 906	$ 891
Cash paid for income taxes, net	85	28
Unpaid purchases of property, plant and equipment, net	204	217
Share-based compensation capitalized to property, plant and equipment	3	3
Non-cash conveyance of property, plant and equipment	0	17
Commitments due to equity method investments	14	0
Contribution of other non-current assets in exchange for equity method investment	30	0
Unpaid dividends declared on unvested common stock	3	5
Unpaid repurchases of treasury stock inclusive of excise taxes	$ 22	$ 0