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, 2022

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 31, 2022, the issuer had 248,659,406 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	10
	Note 4—Inventory	10
	Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation	10
	Note 6—Derivative Instruments	11
	Note 7—Non-Controlling Interest and Variable Interest Entity	17
	Note 8—Accrued Liabilities	17
	Note 9—Debt	18
	Note 10—Leases	21
	Note 11—Revenues	23
	Note 12—Related Party Transactions	25
	Note 13—Income Taxes	26
	Note 14—Net Loss per Share Attributable to Common Stockholders	27
	Note 15—Stock Repurchase Programs	27
	Note 16—Customer Concentration	28
	Note 17—Supplemental Cash Flow Information	28
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	43
Item 4.	Controls and Procedures	44
Part II. Other Information
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6.	Exhibits	47
	Signatures	48

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
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, 2022, 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.

In June 2022, as part of the internal restructuring of Cheniere’s subsidiaries, Cheniere contributed its equity interest in Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”), formerly a wholly owned direct subsidiary of Cheniere, to CCH, and CCL Stage III was subsequently merged with and into CCL, the surviving entity of the merger and a wholly owned subsidiary of CCH.

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,
	2022		2021		2022		2021
Revenues
LNG revenues	$	8,236	$	3,078	$	23,449	$	8,990
Regasification revenues	455		68		591		202
Other revenues	161		54		303		115
Total revenues	8,852		3,200		24,343		9,307
Operating costs and expenses
Cost of sales (excluding items shown separately below)	11,073		4,868		24,161		8,408
Operating and maintenance expense	419		350		1,227		1,057
Development expense	4		2		12		5
Selling, general and administrative expense	92		70		265		224
Depreciation and amortization expense	280		259		827		753
Other	—		1		3		—
Total operating costs and expenses	11,868		5,550		26,495		10,447
Loss from operations	(3,016)		(2,350)		(2,152)		(1,140)
Other income (expense)
Interest expense, net of capitalized interest	(354)		(364)		(1,060)		(1,088)
Gain (loss) on modification or extinguishment of debt	3		(36)		(43)		(95)
Derivative gain (loss), net	—		(2)		2		(3)
Other expense, net	(29)		(24)		(21)		(14)
Total other expense	(380)		(426)		(1,122)		(1,200)
Loss before income taxes and non-controlling interest	(3,396)		(2,776)		(3,274)		(2,340)
Less: income tax benefit	(752)		(1,860)		(762)		(1,864)
Net loss	(2,644)		(916)		(2,512)		(476)
Less: net income (loss) attributable to non-controlling interest	(259)		168		(3)		544
Net loss attributable to common stockholders	$	(2,385)	$	(1,084)	$	(2,509)	$	(1,020)
Net loss per share attributable to common stockholders—basic and diluted (1)	$	(9.54)	$	(4.27)	$	(9.94)	$	(4.03)
Weighted average number of common shares outstanding—basic	249.9		253.6		252.5		253.3
Weighted average number of common shares outstanding—diluted	249.9		253.6		252.5		253.3

(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,
	2022		2021
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	2,504	$	1,404
Restricted cash and cash equivalents	834		413
Trade and other receivables, net of current expected credit losses	1,834		1,506
Inventory	1,129		706
Current derivative assets	131		55
Margin deposits	267		765
Contract assets	392		5
Other current assets	115		202
Total current assets	7,206		5,056
Property, plant and equipment, net of accumulated depreciation	30,904		30,288
Operating lease assets	2,795		2,102
Derivative assets	46		69
Goodwill	77		77
Deferred tax assets	2,100		1,204
Other non-current assets, net	514		462
Total assets	$	43,642	$	39,258
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities
Accounts payable	$	405	$	155
Accrued liabilities	3,108		2,299
Current debt, net of discount and debt issuance costs	1,717		366
Deferred revenue	211		155
Current operating lease liabilities	669		535
Current derivative liabilities	3,215		1,089
Other current liabilities	50		94
Total current liabilities	9,375		4,693
Long-term debt, net of premium, discount and debt issuance costs	25,325		29,449
Operating lease liabilities	2,082		1,541
Finance lease liabilities	75		57
Derivative liabilities	10,954		3,501
Other non-current liabilities	161		50
Stockholders’ 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; 276.7 million shares and 275.2 million shares issued at September 30, 2022 and December 31, 2021, respectively	1		1
Treasury stock: 26.8 million shares and 21.6 million shares at September 30, 2022 and December 31, 2021, respectively, at cost	(1,609)		(928)
Additional paid-in-capital	4,309		4,377
Accumulated deficit	(8,880)		(6,021)
Total Cheniere stockholders’ deficit	(6,179)		(2,571)
Non-controlling interest	1,849		2,538
Total stockholders’ deficit	(4,330)		(33)
Total liabilities and stockholders’ deficit	$	43,642	$	39,258

(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, 2022, total assets and liabilities of CQP were $19.9 billion and $24.3 billion, respectively, including $1.0 billion of cash and cash equivalents and $0.2 billion 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, 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 (see Note 1)	—	—		—	—		(153)		4		—		(149)
Net income attributable to non-controlling interest	—	—		—	—		—		—		84		84
Distributions to non-controlling interest	—	—		—	—		—		—		(171)		(171)
Dividends declared and paid ($0.33 per common share)	—	—		—	—		—		(85)		—		(85)
Net loss	—	—		—	—		—		(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 and paid ($0.33 per common share)	—	—		—	—		—		(85)		—		(85)
Net income	—	—		—	—		—		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 and paid ($0.33 per common share)	—	—		—	—		—		(81)		—		(81)
Dividends declared and accrued ($0.395 per common share)	—	—		—	—		—		(103)		—		(103)
Net loss	—	—		—	—		—		(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.

5

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)—CONTINUED

(in millions)

(unaudited)

Three and Nine Months Ended September 30, 2021
	Total Stockholders’ Equity
	Common Stock			Treasury Stock			Additional Paid-in Capital		Accumulated Deficit		Non-controlling Interest		Total Equity
	Shares	Par Value Amount		Shares	Amount
Balance at December 31, 2020	252.3	$	1	20.8	$	(872)	$	4,273	$	(3,593)	$	2,409	$	2,218
Vesting of share-based compensation awards	1.8	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		33		—		—		33
Issued shares withheld from employees related to share-based compensation, at cost	(0.6)	—		0.6	(42)		—		—		—		(42)
Net income attributable to non-controlling interest	—	—		—	—		—		—		178		178
Distributions to non-controlling interest	—	—		—	—		—		—		(160)		(160)
Net income	—	—		—	—		—		393		—		393
Balance at March 31, 2021	253.5	1		21.4	(914)		4,306		(3,200)		2,427		2,620
Vesting of share-based compensation awards	0.1	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		31		—		—		31
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	(1)		—		—		—		(1)
Net income attributable to non-controlling interest	—	—		—	—		—		—		198		198
Distributions to non-controlling interest	—	—		—	—		—		—		(162)		(162)
Net loss	—	—		—	—		—		(329)		—		(329)
Balance at June 30, 2021	253.6	1		21.4	(915)		4,337		(3,529)		2,463		2,357
Vesting of share-based compensation awards	0.1	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		28		—		—		28
Issued shares withheld from employees related to share-based compensation, at cost	(0.1)	—		0.1	(3)		(1)		—		—		(4)
Shares repurchased, at cost	(0.1)	—		0.1	(6)		—		—		—		(6)
Net income attributable to non-controlling interest	—	—		—	—		—		—		168		168
Distributions to non-controlling interest	—	—		—	—		—		—		(161)		(161)
Dividends declared and accrued ($0.33 per common share)	—	—		—	—		—		(85)		—		(85)
Net loss	—	—		—	—		—		(1,084)		—		(1,084)
Balance at September 30, 2021	253.5	$	1	21.6	$	(924)	$	4,364	$	(4,698)	$	2,470	$	1,213

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,
	2022		2021
Cash flows from operating activities
Net loss	$	(2,512)	$	(476)
Adjustments to reconcile net loss to net cash provided by operating activities:
Unrealized foreign currency exchange gain, net	(10)		—
Depreciation and amortization expense	827		753
Share-based compensation expense	115		91
Non-cash interest expense	14		16
Amortization of debt issuance costs, premium and discount	43		57
Reduction of right-of-use assets	444		269
Loss on modification or extinguishment of debt	43		95
Total losses on derivative instruments, net	10,228		4,230
Net cash used for settlement of derivative instruments	(702)		(486)
Loss on equity method investments	55		16
Deferred taxes	(856)		(1,872)
Repayment of paid-in-kind interest related to repurchase of convertible notes	(13)		(190)
Other, net	10		3
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	(389)		(338)
Inventory	(426)		(174)
Margin deposits	498		(311)
Contract assets	(387)		(4)
Other current assets	57		(88)
Accounts payable and accrued liabilities	938		612
Total deferred revenue	91		58
Total operating lease liabilities	(460)		(285)
Other, net	(37)		81
Net cash provided by operating activities	7,571		2,057
Cash flows from investing activities
Property, plant and equipment	(1,339)		(761)
Proceeds from sale of fixed assets	1		68
Investment in equity method investment	(10)		—
Other, net	—		(14)
Net cash used in investing activities	(1,348)		(707)
Cash flows from financing activities
Proceeds from issuances of debt	1,015		4,104
Redemptions and repayments of debt	(4,005)		(4,276)
Debt issuance and other financing costs	(44)		(38)
Debt modification or extinguishment costs	(33)		(67)
Distributions to non-controlling interest	(686)		(483)
Payments related to tax withholdings for share-based compensation	(62)		(47)
Repurchase of common stock	(640)		(6)
Dividends to shareholders	(251)		—
Payments of finance lease liabilities	(1)		—
Other, net	—		8
Net cash used in financing activities	(4,707)		(805)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	5		—
Net increase in cash, cash equivalents and restricted cash and cash equivalents	1,521		545
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	1,817		2,077
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	3,338	$	2,622

Balances per Consolidated Balance Sheet:

	September 30, 2022
Cash and cash equivalents	$	2,504
Restricted cash and cash equivalents	834
Total cash, cash equivalents and restricted cash and cash equivalents	$	3,338

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, with Train 6 having achieved substantial completion on February 4, 2022, 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, with the third berth having achieved substantial completion on October 27, 2022. CQP also owns a 94-mile pipeline that interconnects the Sabine Pass LNG Terminal with a number of large interstate and intrastate pipelines through its subsidiary, CTPL. As of September 30, 2022, 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 up to seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. CCL Stage III, CCL and CCP received approval from FERC in November 2019 to site, construct and operate the Corpus Christi Stage 3 Project. In March 2022, CCL Stage III issued limited notice to proceed to Bechtel Energy Inc. (“Bechtel”) to commence early engineering, procurement and site works. In June 2022, our board of directors (our “Board”) made a positive FID with respect to the investment in the construction and operation of the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel effective June 16, 2022. In connection with the positive FID, CCL Stage III, through which we were developing and constructing the Corpus Christi Stage 3 Project, was contributed to CCH and subsequently merged with and into CCL, the surviving entity of the merger and a wholly owned subsidiary of CCH. 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 existing operational Trains, midscale Trains, storage tanks and marine berths, 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 August 2022, certain of our subsidiaries initiated the pre-filing review process with the FERC under the National Environmental Policy 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. 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, 2021.

Results of operations for the three and nine months ended September 30, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.

Recent Accounting Standards

ASU 2020-06

In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. This guidance simplifies the accounting for convertible instruments primarily by eliminating the existing cash conversion and beneficial conversion models within Subtopic 470-20, which will result in fewer

8

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

embedded conversion options being accounted for separately from the debt host. The guidance also amends and simplifies the calculation of earnings per share relating to convertible instruments. This guidance is effective for annual periods beginning after December 15, 2021, including interim periods within that reporting period, with earlier adoption permitted for fiscal years beginning after December 15, 2020, including interim periods within that reporting period, using either a full or modified retrospective approach. We adopted this guidance on January 1, 2022 using the modified retrospective approach. The adoption of ASU 2020-06 primarily resulted in the reclassification of the previously bifurcated equity component associated with the 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) to debt as a result of the elimination of the cash conversion model. As of January 1, 2022, the reclassification resulted in: (1) a $194 million reduction of the equity component recorded in additional paid-in capital, before offsetting tax effect of $41 million, (2) a $189 million increase in the carrying value of our 2045 Cheniere Convertible Senior Notes and (3) a $5 million decrease in accumulated deficit, before offsetting tax effect of $1 million. In December 2021, we issued a notice of redemption for all $625 million aggregate principal amount outstanding of our 2045 Cheniere Convertible Senior Notes, which were redeemed on January 5, 2022. See Note 9—Debt for further discussion of the 2045 Cheniere Convertible Senior Notes.

The adoption of ASU 2020-06 also impacted the calculation of the dilutive effect of our 2045 Cheniere Convertible Senior Notes on our net loss per share for the three and nine months ended September 30, 2022, as further discussed in Note 14—Net Loss per Share Attributable to Common Stockholders.

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 expected to arise from the market transition from LIBOR to alternative reference rates. The standard is effective from March 12, 2020 to December 31, 2022.

We have various credit facilities indexed to LIBOR, as further described in Note 9—Debt. To date, we have amended certain of our credit facilities to incorporate a replacement rate or a fallback replacement rate indexed to SOFR as a result of the expected LIBOR transition. We elected to apply the optional expedients as applicable to certain modified facilities; however the impact of applying the optional expedients was not material, and we do not expect the transition to SOFR or other replacement rate indexes to have a material impact on our future cash flows. We intend to apply the optional expedients to qualifying contract modifications in the future; however, we do not expect the impact of such application to be material.

NOTE 2—RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. Restricted cash and cash equivalents consisted of the following (in millions):

	September 30,		December 31,
	2022		2021
Restricted cash and cash equivalents
SPL Project	$	195	$	98
CCL Project	202		44
Cash held by our subsidiaries that is restricted to Cheniere	437		271
Total restricted cash and cash equivalents	$	834	$	413

Pursuant to the accounts agreements entered into with the collateral trustees for the benefit of SPL’s debt holders and CCH’s debt holders, SPL and CCH are required to deposit all cash received into reserve accounts controlled by the collateral trustees.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. The majority of the cash held by our subsidiaries that is restricted to Cheniere relates to advance funding for operation and construction needs of the Liquefaction Projects.

9

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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,
	2022		2021
Trade receivables
SPL and CCL	$	1,070	$	802
Cheniere Marketing	619		640
Other receivables	145		64
Total trade and other receivables, net of current expected credit losses	$	1,834	$	1,506

NOTE 4—INVENTORY

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2022		2021
LNG in-transit	$	652	$	312
LNG	230		153
Materials	189		174
Natural gas	55		64
Other	3		3
Total inventory	$	1,129	$	706

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,
	2022		2021
LNG terminal
Terminal and interconnecting pipeline facilities	$	33,186	$	30,660
Site and related costs	447		441
Construction-in-process	1,868		2,995
Accumulated depreciation	(4,715)		(3,912)
Total LNG terminal, net of accumulated depreciation	30,786		30,184
Fixed assets and other
Computer and office equipment	31		25
Furniture and fixtures	19		20
Computer software	123		120
Leasehold improvements	46		45
Land	1		1
Other	19		19
Accumulated depreciation	(191)		(176)
Total fixed assets and other, net of accumulated depreciation	48		54
Assets under finance lease
Tug vessels	83		60
Accumulated depreciation	(13)		(10)
Total assets under finance lease, net of accumulated depreciation	70		50
Property, plant and equipment, net of accumulated depreciation	$	30,904	$	30,288

10

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Depreciation expense	$	278	$	257	$	822	$	749
Offsets to LNG terminal costs (1)	—		—		204		227

(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:

•interest rate swaps (“Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on CCH’s amended and restated term loan credit facility (the “CCH Credit Facility”), with the last of our Interest Rate Derivatives expiring in May 2022;

•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 (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”);

•physical LNG derivatives in which we have contractual net settlement (“Physical LNG Trading Derivatives”) 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”); 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 (in millions):

	Fair Value Measurements as of
	September 30, 2022								December 31, 2021
	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
Interest Rate Derivatives liability	$	—	$	—	$	—	$	—	$	—	$	(40)	$	—	$	(40)
Liquefaction Supply Derivatives asset (liability)	(106)		(5)		(13,805)		(13,916)		7		(9)		(4,036)		(4,038)
LNG Trading Derivatives liability	(14)		(113)		—		(127)		(22)		(378)		—		(400)
FX Derivatives asset	—		51		—		51		—		12		—		12

We value our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our LNG Trading Derivatives and our Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, using 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.

11

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The fair value of our Physical 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 Physical 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 would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and volatility.

The Level 3 fair value measurements of our Physical LNG Trading Derivatives and the natural gas positions within our Physical 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 Physical Liquefaction Supply Derivatives as of September 30, 2022:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(13,805)	Market approach incorporating present value techniques	Henry Hub basis spread	$(2.495) - $0.677 / $(0.090)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	89% - 943% / 197%

(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 Physical LNG Trading Derivatives and our Physical Liquefaction Supply Derivatives.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021 (1)		2022		2021 (1)
Balance, beginning of period	$	(8,462)	$	(389)	$	(4,036)	$	241
Realized and mark-to-market losses:
Included in cost of sales	(5,668)		(2,982)		(8,825)		(2,898)
Purchases and settlements:
Purchases	4		5		(1,390)		(657)
Settlements	322		75		446		23
Transfers out of Level 3 (2)	(1)		—		—		—
Balance, end of period	$	(13,805)	$	(3,291)	$	(13,805)	$	(3,291)
Change in unrealized losses relating to instruments still held at end of period	$	(5,668)	$	(2,982)	$	(8,825)	$	(2,898)

(1)Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 12—Related Party Transactions.

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

Except for Interest Rate Derivatives, all 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

12

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

Interest Rate Derivatives

CCH previously entered into the following Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility, which expired in May 2022:

	Notional Amounts
	September 30, 2022	December 31, 2021	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives	$—	$4.5 billion	2.30%	One-month LIBOR

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021
Interest Rate Derivatives	Derivative gain (loss), net	$	—	$	(2)	$	2	$	(3)

Commodity Derivatives

SPL and CCL hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The remaining minimum terms of the Physical Liquefaction Supply Derivatives range up to approximately 25 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.

Commencing in the first quarter of 2021, Cheniere Marketing entered into physical LNG transactions that provide for contractual net settlement. Such transactions are accounted for as LNG Trading Derivatives, and are designed to economically hedge exposure to the commodity markets in which we sell LNG. We have historically entered into, and may from time to time enter into, financial LNG Trading Derivatives in the form of swaps, forwards, options or futures. The terms of LNG Trading Derivatives range up to approximately two years.

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

	September 30, 2022		December 31, 2021
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,357	64	11,238	33

(1)Excludes notional amounts associated with extension options that were uncertain to be taken as of September 30, 2022.

13

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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,
		2022		2021		2022		2021
LNG Trading Derivatives	LNG revenues	$	(237)	$	(1,098)	$	(454)	$	(1,539)
LNG Trading Derivatives	Cost of sales	(4)		55		103		136
Liquefaction Supply Derivatives (2)	LNG revenues	(3)		(4)		8		(3)
Liquefaction Supply Derivatives (2)	Cost of sales (3)	(5,508)		(2,444)		(10,008)		(2,848)

(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 derivative instruments that settle through physical delivery.

(3)Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 12—Related Party Transactions.

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 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 $597 million and $762 million as of September 30, 2022 and December 31, 2021, 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,
		2022		2021		2022		2021
FX Derivatives	LNG revenues	$	54	$	11	$	121	$	27

14

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, 2022
	Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	50	$	25	$	56	$	131
Derivative assets	—		46		—		—		46
Total derivative assets	—		96		25		56		177
Current derivative liabilities	—		(3,058)		(152)		(5)		(3,215)
Derivative liabilities	—		(10,954)		—		—		(10,954)
Total derivative liabilities	—		(14,012)		(152)		(5)		(14,169)
Derivative asset (liability), net	$	—	$	(13,916)	$	(127)	$	51	$	(13,992)
	December 31, 2021
	Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	38	$	2	$	15	$	55
Derivative assets	—		69		—		—		69
Total derivative assets	—		107		2		15		124
Current derivative liabilities	(40)		(644)		(402)		(3)		(1,089)
Derivative liabilities	—		(3,501)		—		—		(3,501)
Total derivative liabilities	(40)		(4,145)		(402)		(3)		(4,590)
Derivative asset (liability), net	$	(40)	$	(4,038)	$	(400)	$	12	$	(4,466)

(1)Does not include collateral posted with counterparties by us of $152 million and $20 million as of September 30, 2022 and December 31, 2021, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $115 million and $745 million, as of September 30, 2022 and December 31, 2021, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

15

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, 2022
Gross assets	$	108	$	35	$	57
Offsetting amounts	(12)		(10)		(1)
Net assets	$	96	$	25	$	56
Gross liabilities	$	(14,507)	$	(165)	$	(5)
Offsetting amounts	495		13		—
Net liabilities	$	(14,012)	$	(152)	$	(5)
As of December 31, 2021
Gross assets	$	155	$	10	$	48
Offsetting amounts	(48)		(8)		(33)
Net assets	$	107	$	2	$	15
Gross liabilities	$	(4,382)	$	(551)	$	(10)
Offsetting amounts	237		149		7
Net liabilities	$	(4,145)	$	(402)	$	(3)

16

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 7—NON-CONTROLLING INTEREST AND VARIABLE INTEREST ENTITY

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. CQP is accounted for as a consolidated VIE.

The following table presents the summarized 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,
	2022		2021
ASSETS
Current assets
Cash and cash equivalents	$	988	$	876
Restricted cash and cash equivalents	195		98
Trade and other receivables, net of current expected credit losses	805		580
Contract assets	387		—
Other current assets	401		285
Total current assets	2,776		1,839
Property, plant and equipment, net of accumulated depreciation	16,827		16,830
Other non-current assets, net	300		316
Total assets	$	19,903	$	18,985
LIABILITIES
Current liabilities
Accrued liabilities	$	1,665	$	1,077
Current debt, net of discount and debt issuance costs	1,498		—
Other current liabilities	1,363		200
Total current liabilities	4,526		1,277
Long-term debt, net of premium, discount and debt issuance costs	15,699		17,177
Other non-current liabilities	4,081		100
Total liabilities	$	24,306	$	18,554

NOTE 8—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2022		2021
Natural gas purchases	$	2,112	$	1,323
Derivative settlements	98		329
Interest costs and related debt fees	345		214
LNG terminals and related pipeline costs	254		144
Compensation and benefits	109		180
LNG inventory	8		34
Accrued dividends	101		—
Other accrued liabilities	81		75
Total accrued liabilities	$	3,108	$	2,299

17

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,
	2022		2021
SPL:
Senior Secured Notes:
5.625% due 2023 (the “2023 SPL Senior Notes”) (1)	$	1,500	$	1,500
5.75% due 2024	2,000		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
4.27% weighted average rate due 2037	1,282		1,282
Total SPL Senior Secured Notes	13,132		13,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Total debt - SPL	13,132		13,132
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
Total CQP Senior Notes	4,200		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Total debt - CQP	4,200		4,200
CCH:
Senior Secured Notes:
7.000% due 2024	1,250		1,250
5.875% due 2025	1,500		1,500
5.125% due 2027 (2)	1,500		1,500
3.700% due 2029 (2)	1,492		1,500
3.72% weighted average rate due 2039 (2)	2,699		2,721
Total CCH Senior Secured Notes	8,441		8,471
CCH Credit Facility	—		1,728
Working capital facility (the “CCH Working Capital Facility”) (3)	—		250
Total debt - CCH	8,441		10,449
Cheniere:
4.625% Senior Secured Notes due 2028	1,500		2,000
2045 Cheniere Convertible Senior Notes (4)	—		625
Revolving credit facility (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		2,625
Cheniere Marketing: trade finance facilities and letter of credit facility (3)	—		—
Total debt	27,273		30,406
Current portion of long-term debt	(219)		(117)
Short-term debt	(1,498)		(250)
Unamortized premium, discount and debt issuance costs, net	(231)		(590)
Total long-term debt, net of premium, discount and debt issuance costs	$	25,325	$	29,449

(1)In October 2022, $300 million of the 2023 SPL Senior Notes were redeemed. As of September 30, 2022, the entire amount of the 2023 SPL Senior Notes was classified as short-term debt.

(2)Subsequent to September 30, 2022 and through October 31, 2022, we executed bond repurchases totaling $221 million, inclusive of CCH’s Senior Secured Notes due 2027, 2029 and 2039 on the open market, which are classified as current portion of long-term debt as of September 30, 2022 net of discount and debt issuance costs of $2 million.

(3)These debt instruments are classified as short-term debt.

(4)The redemption of these notes was financed with borrowings under the Cheniere Revolving Credit Facility, which is a long-term debt instrument. Therefore, the 2045 Cheniere Convertible Senior Notes were classified as long-term debt as of December 31, 2021. See Convertible Notes section below for further discussion of the redemption.

18

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, 2022 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities		CCH Credit Facility (1)		CCH Working Capital Facility (1)		Cheniere Revolving Credit Facility
Total facility size	$	1,200	$	750	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	363		—		—		218		—
Available commitment	$	837	$	750	$	3,260	$	1,282	$	1,250
Priority ranking	Senior secured		Senior secured		Senior secured		Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%		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 applicable margin		LIBOR plus 1.250% - 2.375% or base rate plus 0.250% - 1.375% (2)
Commitment fees on undrawn balance	0.15%		0.49%		0.53%		0.18%		0.25%
Maturity date	March 19, 2025		May 29, 2024		(3)		June 15, 2027		October 28, 2026

(1)In June 2022, CCH amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.

(2)This facility was amended in 2021 to establish a SOFR-indexed replacement rate for LIBOR.

(3)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.

Convertible Notes

On December 6, 2021, we issued a notice of redemption for all $625 million aggregate principal amount outstanding of the 2045 Cheniere Convertible Senior Notes. The notice of redemption allowed holders to elect to convert their notes at any time prior to a specified deadline on December 31, 2021, with settlement of such converted notes in cash, as elected by us, on January 5, 2022. The impact of holders electing conversion was immaterial to the Consolidated Financial Statements. The 2045 Cheniere Convertible Senior Notes not converted were redeemed on January 5, 2022 with borrowings under the Cheniere Revolving Credit Facility. We recognized $16 million of debt extinguishment costs related to the early redemption of these convertible notes.

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, CQP and CCH are restricted from making distributions under agreements governing their respective indebtedness generally until, among other requirements, deposits are made into any required debt service reserve accounts 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, 2022, each of our issuers was in compliance with all covenants related to their respective debt agreements.

19

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Interest Expense

Total interest expense, net of capitalized interest, including interest expense related to our convertible notes, consisted of the following (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Interest cost on convertible notes:
Interest per contractual rate	$	—	$	6	$	—	$	29
Amortization of debt discount and debt issuance costs	—		1		—		9
Total interest cost related to convertible notes	—		7		—		38
Interest cost on debt and finance leases excluding convertible notes	376		391		1,118		1,178
Total interest cost	376		398		1,118		1,216
Capitalized interest	(22)		(34)		(58)		(128)
Total interest expense, net of capitalized interest	$	354	$	364	$	1,060	$	1,088

Fair Value Disclosures

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

	September 30, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	24,020	$	22,461	$	24,550	$	26,725
Senior notes — Level 3 (2)	3,253		2,916		3,253		3,693
2045 Cheniere Convertible Senior Notes — Level 1 (3)	—		—		625		526

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 

(3)The Level 1 estimated fair value was based on unadjusted quoted prices in active markets for identical liabilities that we had the ability to access at the measurement date.

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.

20

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—LEASES

Our leased assets consist primarily of LNG vessel 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 tug vessels, 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	2022		2021
Right-of-use assets—Operating	Operating lease assets	$	2,795	$	2,102
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	70		50
Total right-of-use assets		$	2,865	$	2,152
Current operating lease liabilities	Current operating lease liabilities	$	669	$	535
Current finance lease liabilities	Other current liabilities	6		2
Non-current operating lease liabilities	Operating lease liabilities	2,082		1,541
Non-current finance lease liabilities	Finance lease liabilities	75		57
Total lease liabilities		$	2,832	$	2,135

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,
		2022		2021		2022		2021
Operating lease cost (a)	Operating costs and expenses (1)	$	213	$	145	$	604	$	441
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	1		—		3		2
Interest on lease liabilities	Interest expense, net of capitalized interest	2		2		7		7
Total lease cost		$	216	$	147	$	614	$	450
(a) Included in operating lease cost:
Short-term lease costs		$	16	$	22	$	80	$	103
Variable lease costs		7		7		16		20

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

21

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Future annual minimum lease payments for operating and finance leases as of September 30, 2022 are as follows (in millions): 

Years Ending December 31,	Operating Leases (1)		Finance Leases
2022	$	193	$	4
2023	736		15
2024	651		15
2025	474		15
2026	341		15
Thereafter	763		122
Total lease payments	3,158		186
Less: Interest	(407)		(105)
Present value of lease liabilities	$	2,751	$	81

(1)Does not include approximately $2.9 billion of legally binding minimum payments primarily for vessel charters contracted for as of September 30, 2022 which will commence in future periods with fixed minimum lease terms of up to 10 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, 2022		December 31, 2021
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.1	13.2	5.6	16.7
Weighted-average discount rate (1)	4.0%	14.6%	3.6%	16.2%

(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,
	2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	524	$	331
Operating cash flows from finance leases	6		7
Right-of-use assets obtained in exchange for operating lease liabilities	1,139		1,575
Right-of-use assets obtained in exchange for finance lease liabilities	23		—

LNG Vessel Subcharters

From time to time, we sublease certain LNG vessels under charter to third parties while retaining our existing obligation to the original lessor. As of September 30, 2022 and December 31, 2021, we had $534 million and $15 million future minimum sublease payments to be received from LNG vessel subcharters. 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,
	2022		2021		2022		2021
Fixed income	$	122	$	17	$	188	$	28
Variable income	12		15		37		21
Total sublease income	$	134	$	32	$	225	$	49

22

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—REVENUES

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Revenues from contracts with customers
LNG revenues	$	8,422	$	4,170	$	23,774	$	10,505
Regasification revenues	455		68		591		202
Other revenues	27		22		78		66
Total revenues from contracts with customers	8,904		4,260		24,443		10,773
Net derivative loss (1)	(186)		(1,092)		(325)		(1,515)
Other (2)	134		32		225		49
Total revenues	$	8,852	$	3,200	$	24,343	$	9,307

(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 and Liabilities

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

	September 30,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	553	$	140

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, 2022
Deferred revenue, beginning of period	$	194
Cash received but not yet recognized in revenue	284
Revenue recognized from prior year end deferral	(194)
Deferred revenue, end of period	$	284

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, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	113.5	9	$	107.1	9
Regasification revenues	1.6		2	1.9		4
Total revenues	$	115.1		$	109.0

(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.

23

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 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 contracts where there is uncertainty that one or both of the parties will achieve certain milestones. Approximately 76% and 61% of our LNG revenues from contracts included in the table above during the three months ended September 30, 2022 and 2021, respectively, and approximately 72% and 56% of our LNG revenues from contracts included in the table above during the nine months ended September 30, 2022 and 2021, respectively, were related to variable consideration received from customers. During the three and nine months ended September 30, 2022, approximately 1% and 2%, respectively, of our regasification revenues were related to variable consideration received from customers and during each of the three and nine months ended September 30, 2021, approximately 5% of our regasification revenues were related to variable consideration received from customers.

We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. Inc. (“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 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, will terminate upon the later of SPLNG’s receipt of the Termination Fee or December 31, 2022. The termination agreement became effective on July 6, 2022. We have allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which we are recognizing ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations, and an offsetting $31 million in cash outflows allocable to the extinguishment of other remaining obligations we have to Chevron, which will be recognized upon receipt of the Termination Fee as a loss on extinguishment of debt on our Consolidated Statements of Operations. As of September 30, 2022, we recorded contract assets of $387 million related to the termination of the TUA.

24

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 12—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
LNG Revenues
Natural Gas Transportation and Storage Agreements	$	—	$	—	$	4	$	—
Other revenues
Operation and Maintenance Services Agreements	3		2		5		5
Cost of sales
Natural Gas Supply Agreements (a) (1)	—		53		—		124
Natural Gas Transportation and Storage Agreements	—		—		1		1
Total cost of sales	—		53		1		125
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements	18		14		45		41
(a) Included in cost of sales:
Liquefaction Supply Derivative gain (1)	—		6		—		13

(1)Includes amounts recorded related to natural gas supply contracts that SPL and CCL had with related parties. These agreements ceased to be considered related party agreements during 2021, as discussed below.

Natural Gas Supply Agreement

CCL Natural Gas Supply Agreement

CCL was party to a natural gas supply agreement with a related party in the ordinary course of business to obtain a fixed minimum daily volume of feed gas for the operation of the CCL Project. The related party entity was acquired by a non-related party on November 1, 2021, therefore, as of such date, this agreement ceased to be considered a related party agreement.

Natural Gas Transportation and Storage Agreements

SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the SPL Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by Brookfield Asset Management, Inc., who indirectly acquired a portion of CQP’s limited partner interests in September 2020. We recorded accrued liabilities of $8 million and $4 million as of September 30, 2022 and December 31, 2021, respectively, with this related party.

CCL is party to natural gas transportation agreements with Midship Pipeline Company, LLC (“Midship Pipeline”) in the ordinary course of business for the operation of the CCL Project, for a period of 10 years which began in May 2020. We recorded accrued liabilities of $1 million as of both September 30, 2022 and December 31, 2021 with this related party. We account for our investment in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline, as an equity method investment. During the three months ended September 30, 2022, we recognized other-than-temporary impairment losses of $67 million related to our investment in Midship Holdings primarily related to increased forecast construction-related and operating costs, which are presented in other income (expense), net. Our investment in Midship Holdings, net of impairment losses, was $11 million as of September 30, 2022, which was measured using an income approach that utilized level 3 fair value inputs such as projected earnings and discount rates.

CCL is party to a natural gas transportation agreement with ADCC Pipeline, LLC and its wholly owned subsidiary (collectively, “ADCC Pipeline”) in the ordinary course of business for the operation of the CCL Project, with an initial term of 20 years with extension rights. We have a 30% equity interest in ADCC Pipeline, as further described below.

25

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Operation and Maintenance Service Agreements

Cheniere LNG O&M Services, LLC (“O&M Services”), our wholly owned subsidiary, provides the development, construction, operation and maintenance services to Midship Pipeline pursuant to agreements in which O&M Services receives an agreed upon fee and reimbursement of costs incurred. O&M Services recorded $1 million and $2 million of other receivables as of September 30, 2022 and December 31, 2021, respectively, for services provided to Midship Pipeline under these agreements.

Share Purchase Agreement

In June 2022, we entered into a purchase agreement to purchase approximately $350 million of Cheniere’s common shares beneficially owned by Icahn Capital LP and certain affiliates of Icahn Capital LP (the “Icahn Group”) pursuant to which we purchased an aggregate of approximately 2.68 million shares of our common stock at a price per share of $130.52, the closing price on our common shares on the date of execution of the purchase agreement. Pursuant to the Nomination and Standstill Agreement entered into on August 21, 2015 by Cheniere and the Icahn Group, the Icahn Group’s remaining director designee to our Board, Andrew Teno, resigned from our Board and all committees of our Board effective June 21, 2022. Additionally, as of such date, the Icahn Group ceased to be considered a related party.

Interest in ADCC Pipeline, LLC

In June 2022, Cheniere, through its wholly owned subsidiary Cheniere ADCC Investments, LLC, acquired a 30% equity interest in ADCC Pipeline. ADCC Pipeline will develop, construct and operate an approximately 42-mile natural gas pipeline project connecting the Agua Dulce natural gas hub to the CCL Project. We currently have a future commitment of up to approximately $93 million to fund our equity interest, which commitment is subject to a condition precedent that has not yet been satisfied.

NOTE 13—INCOME TAXES

We recorded an income tax benefit of $752 million and $762 million during the three and nine months ended September 30, 2022, respectively, and an income tax benefit of $1,860 million and $1,864 million during the three and nine months ended September 30, 2021, respectively.

We have historically calculated our provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate to year-to-date ordinary income or loss (“annual effective tax rate method”). Because of significant sensitivities in the annual effective tax rate as a result of variability in our earnings due to pre-tax derivative losses arising from changes in fair value from our IPM agreements and the portion of our earnings attributable to non-controlling interest, a relatively small change in estimated ordinary income or loss would result in significant changes in the estimated annual effective tax rate such that we are unable to make a reliable estimate of the annual effective tax rate for the three and nine months ended September 30, 2022. Accordingly, we have applied a discrete-period method to calculate income taxes for the three and nine months ended September 30, 2022 based on the year-to-date effective tax rate (“year-to-date effective tax rate method”). The year-to-date effective tax rate method treats the year-to-date period as if it was the annual period and determines the income tax expense or benefit on that basis.

Utilizing the year-to-date effective tax rate method, our effective tax rate for the three and nine months ended September 30, 2022 was 22.1% and 23.3%, respectively. The effective tax rate for the three and nine months ended September 30, 2022 represents a tax benefit on pre-tax loss and was higher than the statutory rate primarily due to our projected foreign derived intangible income (“FDII”) deduction, which results in income from our sales to foreign customers being taxed at a lower effective tax rate.

We used the annual effective tax rate method to calculate our income tax benefit for the three and nine months ended September 30, 2021, which was 67.0% and 79.7%, respectively, as it was determined that the annual effective tax rate method would produce a reliable estimate. The effective tax rate for the three and nine months ended September 30, 2021 did not bear a customary relationship to the statutory income tax rate due to variability in our earnings due to pre-tax derivative losses arising from changes in fair value from our IPM agreements and the portion of our earnings attributable to non-controlling interest.

26

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 14—NET 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,
	2022		2021		2022		2021
Net loss attributable to common stockholders	$	(2,385)	$	(1,084)	$	(2,509)	$	(1,020)
Weighted average common shares outstanding:
Basic	249.9		253.6		252.5		253.3
Dilutive unvested stock	—		—		—		—
Diluted	249.9		253.6		252.5		253.3
Net loss per share attributable to common stockholders—basic and diluted	$	(9.54)	$	(4.27)	$	(9.94)	$	(4.03)
Dividends paid per common share	$	0.33	$	—	$	0.99	$	—

On September 12, 2022, we declared a quarterly dividend of $0.395 per share of common stock that is payable on November 16, 2022 to shareholders of record as of November 8, 2022.

Potentially dilutive securities that were not included in the diluted net 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,
	2022	2021	2022	2021
Unvested stock (1)	2.5	1.8	2.3	1.6
2045 Cheniere Convertible Senior Notes (2)	—	4.5	0.2	4.5
Total potentially dilutive common shares	2.5	6.3	2.5	6.1

(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 dates.

(2)As described in Note 9—Debt, 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 shareholders during the 2022 period. See Note 1—Nature of Operations and Basis of Presentation for further discussion of our adoption of ASU 2020-06.

NOTE 15—STOCK REPURCHASE PROGRAMS

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Aggregate common stock repurchased	0.60		0.08		4.97		0.08
Weighted average price paid per share	$	125.34	$	83.97	$	128.73	$	83.97
Total amount paid	$	75	$	6	$	640	$	6

As of September 30, 2022, we had $358 million remaining under our share repurchase program, which increased to approximately $4.4 billion as of October 1, 2022.

27

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 16—CUSTOMER CONCENTRATION

The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	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,
	2022	2021	2022	2021	2022	2021
Customer A	*	12%	*	14%	*	10%
Customer B	*	15%	*	13%	*	*
Customer C	*	11%	*	11%	*	*
Customer D	*	11%	*	*	*	*
Customer E	*	*	*	*	16%	—

* 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,
	2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	891	$	902
Cash paid for income taxes, net of refunds	28		2
Non-cash investing activity:
Transfers of property, plant and equipment in exchange for other non-current assets	17		—
Non-cash financing activity:
Declared and accrued dividends on common stock	103		85

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities was $354 million and $234 million as of September 30, 2022 and 2021, respectively.

28

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

29

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, 2021. 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 and other industrial uses. 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 own and operate the 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, 2022, 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, with Train 6 having achieved substantial completion on February 4, 2022, for a total operational production capacity of approximately 30 mtpa of LNG (the “SPL Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks with aggregate capacity of approximately 17 Bcfe, three marine berths, with the third berth having achieved substantial completion on October 27, 2022, 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, and vaporizers with regasification capacity of approximately 4 Bcf/d. CQP also owns a 94-mile pipeline through its subsidiary, CTPL, that interconnects the Sabine Pass LNG Terminal with a number of large interstate and intrastate pipelines.

30

We also own and operate the 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 up to seven midscale Trains with an expected total production capacity over 10 mtpa of LNG. CCL Stage III, CCL and CCP received approval from FERC in November 2019 to site, construct and operate the Corpus Christi Stage 3 Project. In March 2022, CCL Stage III issued limited notice to proceed to Bechtel Energy Inc. (“Bechtel”) to commence early engineering, procurement and site works. In June 2022, our board of directors (our “Board”) made a positive FID with respect to the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel effective June 16, 2022. In connection with the positive FID, CCL Stage III, through which we are developing and constructing the Corpus Christi Stage 3 Project, was contributed to CCH and subsequently merged with and into CCL, with CCL the surviving entity of the merger and a wholly owned subsidiary of CCH. 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 existing operational Trains, midscale Trains, storage tanks and marine berths, the “CCL Project”).

We are the largest producer of LNG in the United States and the second largest LNG producer globally, based on the total production capacity of our operating asset platforms of approximately 45 mtpa as of September 30, 2022.

Our customer arrangements provide us with significant, stable and long-term cash flows. We contract 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, inclusive of contracts executed to support additional liquefaction capacity at the Corpus Christi LNG Terminal beyond the Corpus Christi Stage 3 Project. Excluding contracts with terms less than 10 years and contracts executed to support additional liquefaction capacity at the Corpus Christi LNG Terminal beyond the Corpus Christi Stage 3 Project, our SPAs and IPM agreements had approximately 17 years of weighted average remaining life as of September 30, 2022. We also market and sell LNG produced by the Liquefaction Projects that is not required for other customers through our integrated marketing function. In March 2022, the DOE authorized the export of an additional 152.64 Bcf/yr and 108.16 Bcf/yr of domestically produced LNG by vessel from the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, respectively, through December 31, 2050 to non-FTA countries, that were previously authorized for FTA countries only. For further discussion of the contracted future cash flows under our revenue arrangements, see the liquidity and capital resources disclosures in our annual report on Form 10-K for the fiscal year ended December 31, 2021.

We remain focused on 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 August 2022, certain of our subsidiaries initiated the pre-filing review process with the FERC under the National Environmental Policy 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. 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.

Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. In June 2022, we published our 2021 Corporate Responsibility (“CR”) report, which details our approach and progress on ESG issues, including our collaboration with natural gas midstream companies, methane detection technology providers and leading academic institutions to implement quantification, monitoring, reporting and verification of greenhouse gas (“GHG”) emissions at natural gas gathering, processing, transmission and storage systems specific to our supply chain, as well as our contributions to energy security during a critical time in history. Additionally, we commenced providing Cargo Emissions Tags (“CE Tags”) to our long-term customers in June 2022. The CE Tags provide customers with estimated GHG emissions data associated with each LNG cargo produced at the Liquefaction Projects and are provided for both free-on-board (“FOB”) and delivered ex-ship (“DES”) LNG cargoes. We also joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s

31

(“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative in October 2022. OGMP 2.0 is a comprehensive, measurement-based reporting framework intended to improve the accuracy and transparency of methane emissions reporting in the oil and gas sector. Our CR report is available at cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Quarterly Report on Form 10-Q.

Overview of Significant Events

Our significant events since January 1, 2022 and through the filing date of this Form 10-Q include the following:

Strategic

•On October 3, 2022, our Board appointed Mr. Brian E. Edwards to serve as a member of our Board. Mr. Edwards was appointed to the Audit Committee and the Compensation Committee of our Board.

•In September 2022, we announced the appointment of Corey Grindal, currently Executive Vice President, Worldwide Trading, as Executive Vice President and Chief Operating Officer of the Company, effective January 2, 2023.

•On June 15, 2022, our Board made a positive FID with respect to the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel effective June 16, 2022. In connection with the positive FID, CCL Stage III was contributed to CCH and subsequently merged with and into CCL, with CCL the surviving company of the merger and a wholly owned subsidiary of CCH. In connection with the merger, contracts held by CCL Stage III were transferred to CCL.

•In March 2022, CCL Stage III entered into an EPC contract with Bechtel for the Corpus Christi Stage 3 Project for a contract price of approximately $5.5 billion, subject to adjustment only by change order. As described above, CCL Stage III issued a full notice to proceed with construction to Bechtel in June 2022, which followed the issuance of a limited notice to proceed to commence early engineering, procurement and site works in March 2022.

•We entered into, or amended, the following agreements:

◦We entered into new and amended long-term SPAs aggregating approximately 140 million tonnes of LNG to be delivered between 2026 and 2050, inclusive of long-term SPAs with Engie SA, Equinor ASA, Chevron U.S.A. Inc. (“Chevron”), POSCO International Corporation, PetroChina International Company Limited and PTT Global LNG Company Limited, approximately 50 million tonnes of which is subject to Cheniere making a final investment decision to construct additional liquefaction capacity at the Corpus Christi LNG Terminal beyond the seven-train Corpus Christi Stage 3 Project or us unilaterally waiving that requirement.

◦In May 2022, CCL Stage III entered into an IPM agreement with ARC Resources U.S. Corp, a subsidiary of ARC Resources, Ltd., to purchase 140,000 MMBtu per day of natural gas at a price based on Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years commencing with commercial operations of Train 7 of the Corpus Christi Stage 3 Project.

◦In February 2022, CCL Stage III amended the IPM agreement previously entered into with EOG Resources, Inc. (“EOG”), increasing the volume and term of natural gas supply from 140,000 MMBtu per day for 10 years, to 420,000 MMBtu per day for 15 years, with pricing continuing to be based on JKM. Under the amended IPM agreement, supply is targeted to commence upon completion of Trains 1, 4 and 5 of the Corpus Christi Stage 3 Project. In addition, the previously executed gas supply agreement, under which EOG sells 300,000 MMBtu per day to CCL Stage III at a price indexed to Henry Hub, has been extended by 5 years, resulting in a 15 year term that is expected to commence upon start-up of the amended IPM agreement.

Operational

•As of October 31, 2022, approximately 2,450 cumulative LNG cargoes totaling over 165 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

•On October 27, 2022, substantial completion of the third berth at the Sabine Pass Terminal was achieved.

•On February 4, 2022, substantial completion of Train 6 of the SPL Project was achieved (the “Train 6 Completion”).

32

Financial

•In September 2022, Moody’s Corporation upgraded its issuer credit ratings of Cheniere, CQP and SPL from Ba3, Ba2 and Baa3, respectively, to Ba1, Ba1 and Baa2, respectively, with a stable outlook. Additionally in September 2022, Fitch Ratings upgraded its issuer credit ratings of CQP and SPL from BB+ and BBB-, respectively, to BBB- and BBB, respectively, with a stable outlook.

•In September 2022, our Board approved a revised comprehensive, long-term capital allocation plan which included:

◦increasing the share repurchase authorization by $4.0 billion for an additional 3 years, beginning on October 1, 2022;

◦lowering the Company’s consolidated long-term leverage target to approximately 4x;

◦increasing the Company’s dividend by 20% commencing with a declared distribution of $0.395 per common share in September 2022 (payable in November 2022), and targeting an approximate 10% annual dividend growth rate through Corpus Christi Stage 3 Project construction; and

◦continuing to invest in accretive organic growth.

•In June 2022, CCH amended and restated its term loan credit facility (the “CCH Credit Facility”) and its working capital facility (the “CCH Working Capital Facility”) to, among other things, (1) increase the commitments to approximately $4.0 billion and $1.5 billion for the CCH Credit Facility and the CCH Working Capital Facility, respectively, which are intended to fund a portion of the cost of developing, constructing and operating the Corpus Christi Stage 3 Project, (2) extend the maturity of the CCH Credit Facility to the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project and extend the maturity of the CCH Working Capital Facility to June 15, 2027, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.

•During the three and nine months ended September 30, 2022, we used $1.3 billion and $3.5 billion, respectively, of available cash to reduce our outstanding indebtedness, of which $1.3 billion and $3.2 billion, respectively, was the redemption or prepayment of indebtedness pursuant to our capital allocation plan.

•Also pursuant to our capital allocation priorities:

◦During the three and nine months ended September 30, 2022, we repurchased approximately 0.6 million and 5.0 million shares of our common stock as part of our share repurchase program for approximately $75 million and $640 million, respectively. The shares repurchased during the nine months ended September 30, 2022 include approximately 2.7 million shares of our common stock beneficially owned by Icahn Capital LP and certain affiliates of Icahn Capital LP (the “Icahn Group”) that we repurchased for approximately $350 million;

◦In October 2022, SPL redeemed $300 million of outstanding borrowings under its 5.625% Senior Secured Notes due 2023 pursuant to a notice of redemption issued in September 2022;

◦Additionally, we paid aggregate dividends of $0.99 per share of common stock during the nine months ended September 30, 2022.

33

Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Projects during the nine months ended September 30, 2022 and 2021:

The following table summarizes the volumes of operational and commissioning LNG cargoes that were loaded from the Liquefaction Projects, which were recognized on our Consolidated Financial Statements:

	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
(in TBtu)	Operational	Commissioning	Operational	Commissioning
Volumes loaded during the current period	559	—	1,695	13
Volumes loaded during the prior period but recognized during the current period	34	—	49	1
Less: volumes loaded during the current period and in transit at the end of the period	(37)	—	(37)	—
Total volumes recognized in the current period	556	—	1,707	14

Net loss attributable to common stockholders

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share data)	2022		2021		Variance		2022		2021		Variance
Net loss attributable to common stockholders	$	(2,385)	$	(1,084)	$	(1,301)	$	(2,509)	$	(1,020)	$	(1,489)
Net loss per share attributable to common stockholders—basic and diluted	(9.54)		(4.27)		(5.27)		(9.94)		(4.03)		(5.91)

The $1.3 billion and $1.5 billion increase in net loss during the three and nine months ended September 30, 2022, respectively, from the comparable 2021 periods were primarily due to an increase in derivative losses from changes in fair value and settlements of $2.2 billion and $6.0 billion (before tax and the impact of non-controlling interest), respectively, between the periods, as further described below. The unfavorable variance was partially offset by increased gross margin per MMBtu on LNG delivered primarily due to higher margins on sales indexed to or derived from international gas prices as a result of increases in the associated indices and sales indexed to Henry Hub, generally at 115%. Also contributing to the increase in gross margin, to a lesser extent, was an increase in volume delivered during the three and nine months ended September 30, 2022 from the comparable periods in 2021, in part due to substantial completion and commencement of operations of Train 3 of the CCL Project on March 26, 2021 (the “Train 3 Completion”) and the Train 6 Completion. Additionally offsetting the increases in net loss during the periods was the recognition of increased regasification revenues from Chevron, as further described below.

Substantially all derivative losses relate to the use of commodity derivative instruments indexed to international LNG prices, primarily related to our IPM agreements. While operationally we utilize commodity derivatives to mitigate price

34

volatility for commodities procured or sold over a period of time, as a result of significant appreciation in forward international LNG commodity curves during the three and nine months ended September 30, 2022, we recognized $5.0 billion and $9.2 billion, respectively, of non-cash unfavorable changes in fair value attributed to positions indexed to such prices (before tax and the impact of non-controlling interest).

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, including those entered into during the nine months ended September 30, 2022 as described further in Overview of Significant Events, 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, notwithstanding the operational intent to mitigate risk exposure over time.

In June 2022, Chevron entered into an agreement with SPLNG providing for the early termination of the TUA and an associated terminal marine services agreement between the parties and their affiliates 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, will terminate upon the later of SPLNG’s receipt of the Termination Fee or December 31, 2022. The termination agreement became effective on July 6, 2022. We have allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which we are recognizing ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations, and an offsetting $31 million in cash outflows allocable to the extinguishment of other remaining obligations we have to Chevron, which will be recognized upon receipt of the Termination Fee as a loss on extinguishment of debt on our Consolidated Statements of Operations.

As described in Overview of Significant Events, during the nine months ended September 30, 2022, we entered into SPAs with various counterparties for approximately 140 million tonnes of LNG to be delivered between 2026 and 2050. We expect our net income or loss in the future to be impacted by the revenues and associated expenses related to the commencement of these agreements.

Revenues

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2022		2021		Variance		2022		2021		Variance
LNG revenues	$	8,236	$	3,078	$	5,158	$	23,449	$	8,990	$	14,459
Regasification revenues	455		68		387		591		202		389
Other revenues	161		54		107		303		115		188
Total revenues	$	8,852	$	3,200	$	5,652	$	24,343	$	9,307	$	15,036

Total revenues increased during the three and nine months ended September 30, 2022 from the comparable periods in 2021, primarily as a result of increased pricing due to appreciation in underlying indices as described in Net loss attributable to common stockholders above. To a lesser extent, revenues increased as a result of higher volumes of LNG delivered between the periods due to additional production capacity aggregating to approximately 10 mtpa arising from the Train 3 Completion and the Train 6 Completion.

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 and 2021, we realized offsets to LNG terminal costs of $204 million and $227 million, corresponding to 15 TBtu and 31 TBtu, respectively, that were related to the sale of commissioning cargoes from the Liquefaction Projects. We did not realize any offsets to LNG terminal costs during the three months ended September 30, 2022 and 2021.

LNG revenues include gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized offsets to revenues of $186 million and

35

$1,092 million during the three months ended September 30, 2022 and 2021, respectively, and $325 million and $1,515 million during the nine months ended September 30, 2022 and 2021, respectively, related to the gains and losses from derivative instruments primarily due to shifts in forward commodity curves. Also included in LNG revenues are sales of certain unutilized natural gas procured for the liquefaction process and other revenues, which was $26 million and $93 million during the three months ended September 30, 2022 and 2021, respectively, and $148 million and $240 million during the nine months ended September 30, 2022 and 2021.

Regasification revenues increased by $387 million and $389 million during the three and nine months ended September 30, 2022 from the comparable periods in 2021, respectively, primarily due to the recognition of increased regasification revenues from Chevron, as described in Net loss attributable to common stockholders above.

Other revenues increased by $107 million and $188 million during the three and nine months ended September 30, 2022 from the comparable periods in 2021, respectively, primarily due to an increase in sublease income from LNG vessel subcharters primarily as a result of higher rates and an increase in the number of days subchartered due to extra charter vessel capacity available during the periods.

The following table presents the components of LNG revenues and the corresponding LNG volumes delivered:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	$	6,084	$	2,887	$	15,652	$	7,688
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	2,139		1,075		7,408		2,277
LNG procured from third parties	173		115		566		300
Net derivative losses	(186)		(1,092)		(325)		(1,515)
Other revenues	26		93		148		240
Total LNG revenues	$	8,236	$	3,078	$	23,449	$	8,990
Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	484		386		1,441		1,170
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	72		103		266		269
LNG procured from third parties	4		10		19		38
Total volumes delivered as LNG revenues	560		499		1,726		1,477

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

Operating costs and expenses

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2022		2021		Variance		2022		2021		Variance
Cost of sales	$	11,073	$	4,868	$	6,205	$	24,161	$	8,408	$	15,753
Operating and maintenance expense	419		350		69		1,227		1,057		170
Development expense	4		2		2		12		5		7
Selling, general and administrative expense	92		70		22		265		224		41
Depreciation and amortization expense	280		259		21		827		753		74
Other	—		1		(1)		3		—		3
Total operating costs and expenses	$	11,868	$	5,550	$	6,318	$	26,495	$	10,447	$	16,048

Our total operating costs and expenses increased by $6.3 billion and $16.0 billion during the three and nine months ended September 30, 2022 from the comparable periods in 2021, respectively. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Projects, to the extent those costs are not utilized for the commissioning process. Cost of sales also includes change in fair value of commodity derivatives to secure natural gas feedstock for the Liquefaction Projects, costs associated with the sale of certain unutilized natural gas procured for the

36

liquefaction process, variable transportation and storage costs, port and canal fees and other costs to convert natural gas into LNG. Substantially all of the increase in operating costs and expenses in both comparable periods was attributed to cost of sales, which increased by $6.2 billion and $15.8 billion during the three and nine months ended September 30, 2022, respectively, as a result of increased pricing of natural gas feedstock due to higher U.S. natural gas prices and, to a lesser extent, from increased volume of LNG delivered. Additionally, the increase in cost of sales was due to unfavorable changes in our commodity derivatives to secure natural gas feedstock for the Liquefaction Projects, as discussed in Net loss attributable to common stockholders above.

Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Projects. Operating and maintenance expense also includes service and maintenance, payroll and benefit costs, insurance, regulatory costs and other operating costs. During the three and nine months ended September 30, 2022, operating and maintenance expense increased from the comparable periods in 2021, primarily due to increased natural gas transportation and storage capacity demand charges following the Train 6 Completion and the Train 3 Completion as well as third party service and maintenance contract costs.

Depreciation and amortization expense increased during the three and nine months ended September 30, 2022 from the comparable period in 2021 primarily as a result of the Train 6 Completion and, to a lesser extent during the nine months ended September 30, 2022, the Train 3 Completion.

Other expense (income)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2022		2021		Variance		2022		2021		Variance
Interest expense, net of capitalized interest	$	354	$	364	$	(10)	$	1,060	$	1,088	$	(28)
Loss (gain) on modification or extinguishment of debt	(3)		36		(39)		43		95		(52)
Derivative loss (gain), net	—		2		(2)		(2)		3		(5)
Other expense, net	29		24		5		21		14		7
Total other expense	$	380	$	426	$	(46)	$	1,122	$	1,200	$	(78)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Total interest cost	$	376	$	398	$	1,118	$	1,216
Capitalized interest	(22)		(34)		(58)		(128)
Total interest expense, net of capitalized interest	$	354	$	364	$	1,060	$	1,088

Interest expense, net of capitalized interest, decreased during the three and nine months ended September 30, 2022 from the comparable 2021 periods as a result of lower interest costs due to refinancing higher cost debt and repayment of debt in accordance with our capital allocation plan, which was offset by a lower portion of total interest costs eligible for capitalization related to the Corpus Christi Stage 3 Project in 2022 as compared to Train 3 of the CCL Project and Train 6 of the SPL Project in 2021.

We had favorable variances on our loss (gain) on modification or extinguishment of debt during the three and nine months ended September 30, 2022 from the comparable periods in 2021, respectively, primarily due to the pricing of debt that was repurchased or repaid and the amount of debt that was paid down prior to their scheduled maturities, as further described in Liquidity and Capital Resources—Sources and Uses of Cash—Financing Cash Flows.

Other expense, net increased during the three and nine months ended September 30, 2022 from the comparable 2021 periods primarily due to increased other-than-temporary impairment losses related to our investment in Midship Holdings that was recognized between the periods, which was partially offset by higher interest income earned on cash and cash equivalents from higher interest rates in 2022.

37

Income tax benefit

	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions)	2022			2021			Variance			2022			2021			Variance
Loss before income taxes and non-controlling interest	$	(3,396)		$	(2,776)		$	(620)		$	(3,274)		$	(2,340)		$	(934)
Income tax benefit	(752)			(1,860)			1,108			(762)			(1,864)			1,102
Effective tax rate	22.1		%	67.0		%	(44.9)		%	23.3		%	79.7		%	(56.4)		%

Utilizing the year-to-date effective tax rate method, our effective tax rate for the three and nine months ended September 30, 2022 was 22.1% and 23.3%, respectively. The effective tax rate for the three and nine months ended September 30, 2022 represents a tax benefit on pre-tax loss and was higher than the statutory rate primarily due to our projected foreign derived intangible income (“FDII”) deduction, which results in income from our sales to foreign customers being taxed at a lower effective tax rate.

We used the annual effective tax rate method to calculate our income tax benefit for the three and nine months ended September 30, 2021, which was 67.0% and 79.7%, respectively, as it was determined that the annual effective tax rate method would produce a reliable estimate. The effective tax rate for the three and nine months ended September 30, 2021 did not bear a customary relationship to the statutory income tax rate due to variability in our earnings due to pre-tax derivative losses arising from changes in fair value from our IPM agreements and the portion of our earnings attributable to non-controlling interest.

Our effective tax rate is subject to variation prospectively due to variability in our pre-tax and taxable earnings and the proportion of such earnings attributable to non-controlling interests.

Net income (loss) attributable to non-controlling interest

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2022		2021		Variance		2022		2021		Variance
Net income (loss) attributable to non-controlling interest	$	(259)	$	168	$	(427)	$	(3)	$	544	$	(547)

Net loss attributable to non-controlling interest was $259 million and $3 million during the three and nine months ended September 30, 2022, respectively, compared to net income of $168 million and $544 million during the three and nine months ended September 30, 2021, respectively. The changes in both the three and nine month comparable periods were primarily due to a decrease in consolidated net income recognized by CQP, which recognized net income of $381 million and $1,123 million in the three and nine months ended September 30, 2021, respectively, compared to net loss of $514 million and $13 million in the three and nine months ended September 30, 2022, respectively.

During the nine months ended September 30, 2022, in fulfillment of a prior commitment to collateralize financing for Train 6 of the SPL Project, Cheniere provided to SPL certain SPAs aggregating approximately 21 million tonnes of LNG to be delivered between 2023 and 2035 and an IPM agreement to purchase 140,000 MMBtu per day of natural gas for a term of approximately 15 years beginning in early 2023. Additionally, during the nine months ended September 30, 2022, SPL executed an SPA with a counterparty aggregating approximately 1.0 mtpa of LNG to be delivered between 2026 and 2042. As a result, net income attributable to non-controlling interest will be impacted in future periods as volumes are delivered under the aforementioned contracts and by gains and losses from changes in the fair value of the IPM agreement, which is accounted for as a derivative.

38

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. In the long term, we expect to meet our cash requirements 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).

	September 30, 2022
Cash and cash equivalents (1)	$	2,504
Restricted cash and cash equivalents designated for the following purposes:
SPL Project	195
CCL Project	202
Cash held by our subsidiaries that is restricted to Cheniere	437
Total restricted cash and cash equivalents	834
Available commitments under our credit facilities (2):
SPL’s Working capital revolving credit and letter of credit reimbursement agreement	837
CQP’s Credit facilities	750
CCH Credit Facility	3,260
CCH Working Capital Facility	1,282
Revolving Credit Facility (the “Cheniere Revolving Credit Facility”)	1,250
Total available commitments under our credit facilities	7,379
Total available liquidity	$	10,717

(1)Amounts presented include balances held by our consolidated variable interest entity, CQP, as discussed in Note 7—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of September 30, 2022, assets of CQP, which are included in our Consolidated Balance Sheets, included $1.0 billion of 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, 2022. 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, 2022 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.

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. The majority of the cash held by SPL and CCH that is restricted to Cheniere relates to advance funding 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 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.

39

•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, CQP 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.

Notwithstanding 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.

Revised Capital Allocation Plan

As described in Overview of Significant Events, in September 2022, our Board approved a revised comprehensive long-term capital allocation plan. Pursuant to the revised capital allocation plan, on September 12, 2022 our Board authorized an increase in the existing share repurchase program by $4.0 billion for an additional three years, beginning on October 1, 2022. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by management based on market conditions and other factors.

A further aspect of our revised capital allocation plan is to lower our long-term leverage target through debt paydown, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of our indebtedness, including senior notes of SPL, CQP, CCH and Cheniere. The timing and amount of any paydown of our indebtedness will be determined by management based on market conditions and other factors.

The revised capital allocation plan also includes a targeted annual dividend growth rate of approximately 10% through Corpus Christi Stage 3 Project construction. On September 12, 2022, we declared a quarterly dividend of $0.395 per common share, which represented a 20% increase from the previous quarterly dividend.

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, 2022:

Overall project completion percentage	12.2%
Completion percentage of:
Engineering	24.1%
Procurement	18.6%
Subcontract work	10.8%
Construction	0.8%
Date of expected substantial completion	2H 2025 - 1H 2027

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,
	2022		2021
Net cash provided by operating activities	$	7,571	$	2,057
Net cash used in investing activities	(1,348)		(707)
Net cash used in financing activities	(4,707)		(805)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	5		—
Net increase in cash, cash equivalents and restricted cash and cash equivalents	$	1,521	$	545

40

Operating Cash Flows

Our operating cash net inflows during the nine months ended September 30, 2022 and 2021 were $7.6 billion and $2.1 billion, respectively. The $5.5 billion increase was primarily related to increased cash receipts from the sale of LNG cargoes due to higher revenue per MMBtu and to a lesser extent higher volume of LNG delivered. Partially offsetting these operating cash inflows were higher operating cash outflows primarily due to higher natural gas feedstock costs and lower contribution from certain portfolio optimization activities.

On August 16, 2022, President Biden signed H.R. 5376 (P.L. 117-169), commonly referred to as the Inflation Reduction Act, into law, which includes the implementation of a new 15% corporate alternative minimum tax (the “CAMT”) effective in 2023 on the adjusted financial statement income of certain large corporations, among other provisions. The CAMT may 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.

Investing Cash Flows

Our investing cash net outflows in both years primarily was for the construction costs for the Liquefaction Projects. The $641 million increase in 2022 compared to 2021 was primarily due to spend during the nine months ended September 30, 2022 related to construction work performed by Bechtel for the Corpus Christi Stage 3 Project, partially offset by a decrease in spend due to the completion of Train 6 of the SPL Project in February 2022, which was under construction throughout 2021. We expect our capital expenditures to increase in future periods as construction work progresses on the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 2022.

Financing Cash Flows

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

	Nine Months Ended September 30,
	2022		2021
Proceeds from issuances of debt	$	1,015	$	4,104
Redemptions and repayments of debt	(4,005)		(4,276)
Distributions to non-controlling interest	(686)		(483)
Repurchase of common stock	(640)		(6)
Dividends to shareholders	(251)		—
Other, net	(140)		(144)
Net cash used in financing activities	$	(4,707)	$	(805)

Debt Issuances and Related Financing Costs

The following table shows the issuances of debt, including intra-quarter borrowings (in millions):

	Nine Months Ended September 30,
	2022		2021
CQP:
4.000% Senior Notes due 2031	$	—	$	1,500
3.25% Senior Notes due 2032	—		1,200
CCH:
2.742% Senior Notes due 2029	—		750
CCH Credit Facility	440		—
Cheniere:
Cheniere Revolving Credit Facility	575		434
Cheniere’s term loan facility (the “Cheniere Term Loan Facility”)	—		220
Total debt issuances	$	1,015	$	4,104

41

During the nine months ended September 30, 2022 and 2021, we paid debt issuance costs and other financing costs of $44 million and $38 million, respectively, included in other in the Financing Cash Flows table above, related to the debt issuances above and amendment of credit facilities during the respective periods.

Debt Redemptions, Repayments and Repurchases and Related Modification or Extinguishment Costs

During the nine months ended September 30, 2022, we paid down a total of $4.0 billion of outstanding indebtedness, which included $530 million of debt repurchases on the open market and the remaining associated with redemptions of our outstanding notes or paydown of our credit facilities. During the nine months ended September 30, 2021, we redeemed or repurchased a total of $4.3 billion outstanding indebtedness, entirely associated with redemptions of our outstanding notes or paydown of our credit facilities.

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

	Nine Months Ended September 30,
	2022		2021
CQP:
5.250% Senior Notes due 2025	$	—	$	(1,500)
5.625% Senior Notes due 2026	—		(672)
CCH:
CCH Credit Facility	(2,169)		—
CCH Working Capital Facility	(250)		(1,006)
3.700% Senior Notes due 2029	(8)		—
3.72% weighted average Senior Notes rate due 2039	(17)		—
Cheniere:
4.875% Cheniere Convertible Senior Notes due 2021	—		(296)
4.25% Convertible Senior Notes due 2045	(500)		—
Cheniere Revolving Credit Facility	(575)		(434)
4.625% Senior Secured Notes due 2028	(486)		—
Cheniere Term Loan Facility	—		(368)
Total debt redemptions, repayments and repurchases	$	(4,005)	$	(4,276)

During the nine months ended September 30, 2022 and 2021, we paid debt modification or extinguishment costs of $33 million and $67 million, respectively, included in other, net in the Financing Cash Flows table above, related to these redemptions and repayments.

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 $686 million and $483 million during the nine months ended September 30, 2022 and 2021, respectively, to non-controlling interests.

Repurchase of Common Stock

The following table presents information with respect to repurchases of common stock (in millions, except per share data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Aggregate common stock repurchased	0.60		0.08		4.97		0.08
Weighted average price paid per share	$	125.34	$	83.97	$	128.73	$	83.97
Total amount paid	$	75	$	6	$	640	$	6

As of September 30, 2022, we had $358 million remaining under our share repurchase program, which increased to approximately $4.4 billion as of October 1, 2022.

42

Cash Dividends to Shareholders

During the nine months ended September 30, 2022, we paid aggregate dividends of $0.99 per share of common stock, for a total of $251 million paid to common shareholders. We did not pay dividends during the nine months ended September 30, 2021.

On September 12, 2022, we declared a quarterly dividend of $0.395 per share of common stock that is payable on November 16, 2022 to shareholders of record as of November 8, 2022.

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, 2021.

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 entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project (“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, 2022				December 31, 2021
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(13,916)	$	2,625	$	(4,038)	$	903
LNG Trading Derivatives	(127)		44		(400)		38

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, 2022				December 31, 2021
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
FX Derivatives	$	51	$	5	$	12	$	2

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

43

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. 

44

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. Other than discussed below, 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, 2021.

Louisiana Department of Environmental Quality (“LDEQ”) Matter

Certain of our subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG Terminal and the commissioning of the SPL Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of our subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of our subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.

Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Matter

In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG Terminal (the “2018 SPL tank incident”). These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to SPL alleging violations of federal pipeline safety regulations relating to the 2018 SPL tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200. On October 12, 2021, SPL responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. PHMSA notified SPL in a letter dated November 9, 2021 that the case was considered “closed.” On March 9, 2022, PHMSA and FERC issued conditional approval to return one of the two tanks to service. SPL continues to coordinate with PHMSA and FERC to address the matters relating to the 2018 SPL tank incident, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.

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, 2021.

45

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, 2022:

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 (3)
July 1 - 31, 2022	638,816	$125.72	602,347	$357,655,508
August 1 - 31, 2022	—	$—	—	$357,655,508
September 1 - 30, 2022	—	$—	—	$357,655,508
Total	638,816		602,347

(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.

(3)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. For additional information, see Note 15—Stock Repurchase Programs.

46

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 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00067 Performance and Attendance Bonus (“PAB”) Provisional Sum Closure, dated August 18, 2022, (ii) the Change Order CO-00068 Performance and Attendance Bonus (“PAB”) Provisional Sum Closure (Reconciliation to CO-00067), dated August 18, 2022, and (iii) the Change Order CO-00069 COVID-19 Impacts 1Q2022 and 2Q2022, dated August 29, 2022
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 Stage III and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00004 Currency Conversion, dated June 27, 2022, (ii) the Change Order CO-00005 Fuel Adjustment, dated July 15, 2022, (iii) the Change Order CO-00006 Removal of Laydown Yard Scope Option, dated August 2, 2022, (iv) the Change Order CO-00007 Removal of Air Bridges Scope Option, dated August 22, 2022, (v) the Change Order CO-00008 Acid Gas Flare K/O Drum, dated August 16, 2022, and (vi) the Change Order CO-00009 Package 7A (Without Site Work), dated August 16, 2022 (Portions of this exhibit have been omitted.)
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.

47

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 2, 2022	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 2, 2022	By:	/s/ David Slack
			David Slack
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

48

EX-10.1

Exhibit 10.1

CHANGE ORDER

PERFORMANCE AND ATTENDANCE BONUS ("PAB”) PROVISIONAL SUM CLOSURE

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00067 DATE OF CHANGE ORDER: August 18, 2022

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

1.In accordance with Section 2.2 Performance and Attendance Bonus Provisional Sum of Schedule EE-2 of the Agreement, this Change Order amends Section 2.2 Performance and Attendance Bonus Provisional Sum to reflect actual and final costs incurred by Contractor.

2.    Performance and Attendance Bonus Provisional Sums

a.Per Section 2.2 of Schedule EE-2 of Attachment EE of the Agreement, the extant provisional sums for Performance and Attendance Bonus are:

i.Subproject 6(a): U.S. $37,000,000; and

ii.Subproject 6(b): U.S. $5,000,000.

b.In accordance with previous Change Order CO-00031, Schedule EE-4 of Attachment EE of the Agreement was merged into Schedule EE-2 of Attachment EE of the Agreement.

3.The Performance and Attendance Bonus Provisional Sum in Section 2.2 of Schedule EE-2 of Attachment EE is hereby decreased by Twenty Million, Four Hundred and Fifty-Seven Thousand, One Hundred and Sixteen U.S. Dollars (U.S. $20,457,116); and therefore, the final Performance and Attendance Bonus Provisional Sum as amended by this Change Order shall be Twenty-One Million, Five Hundred and Forty-Two Thousand, Eight Hundred and Eighty-Four U.S. Dollars (U.S. $21,542,884).

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

5.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)	$	21,155,105
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,038,047,678
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,038,047,678

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, 62-66)	$	7,031,570

9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	464,727,570
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
11. The Provisional Sum Applicable to Subproject 6(b) will be changed by this Change Order	$	(20,457,116)
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	444,270,454

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)	$	2,502,775,248
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	(20,457,116)
16. The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,482,318,132

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

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

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

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: _KM_ Contractor _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/ Kane MacIntosh
Owner	Owner
David Craft	Kane MacIntosh
Name	Name
SVP E&C	Senior Project Manager, PVP
Title	Title
August 30, 2022	26 August 2022
Date of Signing	Date of Signing

CHANGE ORDER

PERFORMANCE AND ATTENDANCE BONUS ("PAB”) PROVISIONAL SUM CLOSURE

(RECONCILIATION TO CO-00067)

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00068 DATE OF CHANGE ORDER: August 18, 2022

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

1.This Change Order revises and supersedes CO-00067 in its entirety, as follows:

a.Allocation of PAB per Subproject 6(a) and Subproject 6(b) is adjusted; and

b.Exhibit “A” is revised to reflect allocation of PAB per Subproject 6(a) and Subproject 6(b)

2.    Performance and Attendance Bonus Provisional Sums

a.Per Section 2.2 of Schedule EE-2 of Attachment EE of the Agreement, the extant provisional sums for Performance and Attendance Bonus for Subproject 6(a) is U.S. $42,000,000.

b.In accordance with previous Change Order CO-00031, Schedule EE-4 of Attachment EE of the Agreement was merged into Schedule EE-2 of Attachment EE of the Agreement.

3.The Performance and Attendance Bonus Provisional Sum in Section 2.2 of Schedule EE-2 of Attachment EE is hereby decreased by Twenty Million, Four Hundred and Fifty-Seven Thousand, One Hundred and Eighteen U.S. Dollars (U.S. $20,457,118); and therefore, the final Performance and Attendance Bonus Provisional Sum as amended by this Change Order shall be Twenty-One Million, Five Hundred and Forty-Two Thousand, Eight Hundred and Eighty-Two U.S. Dollars (U.S. $21,542,882).

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

5.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)	$	21,155,105
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,038,047,678
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
5. The Provisional Sum Applicable to Subproject 6(a) will be changed by this Change Order in the amount of	$	(20,457,118)
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,017,590,560

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)	$	(13,425,546)
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	444,270,454
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—

11. The Provisional Sum Applicable to Subproject 6(b) will be changed by this Change Order	$	20,457,116
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	464,727,570

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)	$	2,482,318,132
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	(2)
16. The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,482,318,130

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: _KM_ Contractor _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/ Kane MacIntosh
Owner	Owner
David Craft	Kane MacIntosh
Name	Name
SVP E&C	Senior Project Manager, PVP
Title	Title
September 14, 2022	9 September 2022
Date of Signing	Date of Signing

CHANGE ORDER

COVID-19 Impacts 1Q2022 and 2Q2022

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00069 DATE OF CHANGE ORDER: August 29, 2022

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

1.    Pursuant to Article 6.2 of the Agreement (Change Orders Requested by Contractor), Parties agree this Change Order includes Contractor’s costs for the first and second quarters of 2022 (actuals January 2022 through June 2022), in response to the novel coronavirus (COVID-19) outbreak event.

This Change Order is based on the following assumptions and qualifications:

i.Notwithstanding this Change Order contemplates the first and second quarters of 2022, by mutual agreement there is nil cost component for 2Q2022.

ii.Contractor’s Houston home office personnel have worked and shall continue working effectively remotely or in the Houston home office.

iii.Contractor has been able to keep the Jobsite open throughout the event and shall continue doing so, to the extent reasonably possible, to advance the Work at the current rate of progress (or better if possible), with no shutdowns in 1Q2022 or 2Q2022.

iv.Contractor shall continue to put forth diligent mitigation efforts to minimize impacts caused by the event to the extent reasonably practical, including but not limited to: increased craft professional hours for additional cleaning, disinfecting, etc.; increased bussing services to support social distancing; additional cleaning stations, waste management services, etc.; quarantine requirements for supplier technical support (international and others); continued COVID-19 testing costs and hours (excluding quarantine time); increased professional staff for contact tracing efforts; and additional safety PPE, communication materials (e.g., posters, signs, etc.).

v.No major COVID-19 infection outbreak on the Jobsite resulting in: (i) Site shutdown of all or critical scopes of the Work; or (ii) absenteeism at or above the twenty percent (20%) level for a sustained duration of more than four (4) Weeks. Should either of these triggers occur, the Parties shall jointly collaborate on mitigation actions and plans for shutdown accordingly.

vi.Existing government (local, state and/or federal) guidelines, executive orders, actions or directives as of 9 March 2021 shall remain unchanged through the end of 2Q2022. New government orders shall be subject to separate notices and Change Orders, if applicable.

vii.Owner’s operations and other professional staff personnel shall continue to support the Contractor’s activities for the Project in support of the Work.

viii.Subcontractors and Suppliers shall continue to provide uninterrupted support for construction activities either at Site or remotely if possible.

ix.Any changes in the above assumptions and qualifications and additional costs beyond 1Q & 2Q are excluded from this Change Order; and may be part of a separate Change Order in accordance with Article 6.2 of the Agreement.

2.    Contractor has not experienced schedule impacts on the critical path of the CPM Schedule through 30 June 2022. In the event of the occurrence of any impacts to the critical path of the CPM Schedule, Contractor shall notify Owner in accordance with Article 6.5 of the Agreement.

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

4.    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)	$	697,987
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,017,590,560
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,017,590,560
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, 62-68)	$	7,031,570
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	464,727,570
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$
11. The Provisional Sum Applicable to Subproject 6(b) will be changed by this Change Order	$	546,880
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	465,274,450
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)	$	2,482,318,130
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	546,880
16. The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,482,865,010

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

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

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

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: _KM_ Contractor _DC_ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of thechange reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractorfully 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/ Kane MacIntosh
Owner	Owner
David Craft	Kane MacIntosh
Name	Name
SVP E&C	Senior Project Manager, PVP
Title	Title
September 14, 2022	9 September 2022
Date of Signing	Date of Signing

EX-10.2

Exhibit 10.2

CHANGE ORDER

CURRENCY CONVERSION

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. DATE OF AGREEMENT: March 1, 2022 CHANGE ORDER NUMBER: CO-00004 DATE OF CHANGE ORDER: June 27, 2022

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

1.Pursuant to Section 7.10 of the Agreement (Currency Conversion), the Parties agree to adjust the Contract Price to an upward or downward adjustment by this Change Order on a date that is two (2) Business Days after Owner’s issuance of NTP (June 16, 2022) for currency fluctuations.

2.The Value of Foreign Currency in Section 7.10 of the Agreement was Two Hundred Sixty-Five Million, Seven Hundred Fifty-Two Thousand, Nine Hundred Fifty-One Euros (€ 265,752,951). Based on the Bechtel Treasury Secured Hedge Rate determined by taking a weighted average of the forward contracts entered into by Contractor and any spot contracts entered into by Contractor during the period between LNTP and NTP, the Contract Price is hereby decreased by Thirteen Million, Forty Thousand, Four Hundred Ninety-Seven U.S. Dollars (U.S. $13,040,497).

3.Exhibit 1 of this Change Order illustrates the calculation of the Currency Conversion.

4.Exhibit 3 of this Change Order includes the detailed spot and forward trades used to calculate the Bechtel Treasury Secured Hedge Rate.

5.    Schedule C-3 Aggregate Equipment Price Milestone Payment Schedule of Attachment C of the Agreement shall be amended by including the milestone(s) listed in Exhibit 2 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 (#00001 - #00003)	$	25,000,000
3. The Contract Price prior to this Change Order was	$	5,509,000,000
4. The Aggregate Equipment Price will be (decreased) by this Change Order in the amount of	[***]
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of	[***]
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	$	5,495,959,503

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 2 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): Yes; to be adjusted 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: ___ Contractor 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/ Steven Smith
Name:	Steven Smith
Title:	Senior Project Manager

CHANGE ORDER

FUEL ADJUSTMENT

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. DATE OF AGREEMENT: March 1, 2022 CHANGE ORDER NUMBER: CO-00005 DATE OF CHANGE ORDER: July 15, 2022

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

1.Pursuant to Section 7.11 of the Agreement (Fuel Adjustment), the Parties agree to adjust the Contract Price to an upward or downward adjustment by this Change Order on the date Owner issues NTP (June 16, 2022) for each of the following fuel types: (a) gasoline and (b) road diesel for any change in the index value, at the nearest weekly datum, as published by the US Energy Information Administration (EIA) for the Gulf Coast Region for each specific fuel type.

2.The Fuel Adjustment Basis in Section 7.11 of the Agreement was Twenty Million, Thirty-Seven Thousand, Five Hundred Twenty-Three U.S. Dollars (U.S. $20,037,523). Based on the NTP index value of June 13, 2022, the Contract Price is hereby increased by Fourteen Million, Two Hundred Fifty-One Thousand, One Hundred Fifty-Two U.S. Dollars (U.S. $14,251,152).

3.The Parties agree to amend Article 7.11 of the Agreement to replace the reference date of the selected indices from “February 5, 2022” to “on or around September 20, 2021”. For the avoidance of doubt, the baseline index values in the Agreement are the basis of the value in estimate in the Contract Price.

4.Exhibit 1 of this Change Order illustrates the calculation of the final fuel adjustment.

5.Schedule C-1 Aggregate Labor and Skills Price Milestone Payment Schedule of Attachment C of the Agreement shall be amended by including the milestone(s) listed in Exhibit 2 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 (#00001 - #00004)	$	11,959,503
3. The Contract Price prior to this Change Order was	$	5,495,959,503
4. The Aggregate Equipment Price will be (unchanged) 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	$	5,510,210,655

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 2 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): 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: SS Contractor 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/ Smith, Steven
Name:	Steve Smith
Title:	Senior Project Manager

CHANGE ORDER FORM

REMOVAL OF LAYDOWN YARD SCOPE OPTION

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. DATE OF AGREEMENT: March 1, 2022 CHANGE ORDER NUMBER: CO-00006 DATE OF CHANGE ORDER: August 2, 2022

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

1.Pursuant to Article 6.1 of the Agreement (Owner’s Right to Change Order), Section 2 of Attachment NN of the Agreement (Scoping Adjustments), and Owner Letter No. CCLIQ3-BE-C22-009, dated March 15, 2022, Parties agree this Change Order removes the laydown yard scope option (150 acres) from Contractor’s Scope of Work as further described in Attachment NN and Schedule NN-1 of the Agreement.

2.The original Laydown Yard Scope Option Contract Price in Attachment NN of the Agreement was Fifty-Six Million U.S. Dollars (U.S. $56,000,000). The Parties have agreed to reduce the Contract Price for the Laydown Yard Scope Option by Fifty-Six Million U.S. Dollars (U.S. $56,000,000).

3.Exhibit 3 illustrates the original Project laydown areas per Attachment NN-1 of the Agreement.

4.Exhibit 4 illustrates the planned final Project laydown areas and improvements as of 5 July 2022.

5.The cost summary and detailed costs for this Change Order is provided in Exhibit 1 of this Change Order.

6.Schedule C-1 (Aggregate Labor and Skills Price Milestone Payment Schedule) and Schedule C-2 (Aggregate Labor and Skills Price Monthly Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 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-00005)	$	26,210,655
3. The Contract Price prior to this Change Order was	$	5,510,210,655
4. The Aggregate Equipment Price will be (decreased) by this Change Order in the amount of	[***]
5. The Aggregate Labor and Skills Price will be (decreased) 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	$	5,454,210,655

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 2 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: SS Contractor 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.

CORPUS CHRISTI LIQUEFACTION, LLC

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

BECHTEL ENERGY INC.

By:	/s/ Smith, Steven
Name:	Steve Smith
Title:	Senior Project Manager

CHANGE ORDER FORM

REMOVAL OF AIR BRIDGES SCOPE OPTION

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc DATE OF AGREEMENT: March 1, 2022 CHANGE ORDER NUMBER: CO-00007 DATE OF CHANGE ORDER: August 22, 2022

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

1.Pursuant to Article 6.1 of the Agreement (Owner’s Right to Change Order), Section 3 of Attachment NN of the Agreement (Scoping Adjustments), and Owner Letter No. CCLIQ3-BE-C22-008, dated March 15, 2022, Parties agree this Change Order removes the air bridges from Contractor’s Scope of Work as further described in Attachment NN and Schedule NN-1 of the Agreement.

2.Owner furnished Contractor the Pipeline Corridor Crossing Evaluation Reports 1 and 2 (No. 058-2201 Final 022-005 R, Version: Final Revised, dated, May 10, 2022) and (No. 058-2201 22-009 Final, Version: Final, dated, May 10, 2022) from Owner’s Third-Party consultant (RSI Pipeline Solutions, LLC. “RSI”), confirming air bridges will not be required to satisfy FERC Condition 29; however, the RSI analyses confirmed pipeline crossing mitigations are necessary to comply with FERC Condition 29, which were performed by Contractor in lieu of air bridges. Contractor shall utilize the reports and findings as Rely Upon Information as defined in the Agreement.

3.The original Air Bridges Scope Option Contract Price in Attachment NN of the Agreement was Thirty-Four Million U.S. Dollars (U.S. $34,000,000). The Parties have agreed to reduce the Contract Price for the Air Bridges Scope Option by Thirty-Three Million, Five Hundred Twenty-Seven Thousand, Six Hundred U.S. Dollars (U.S. $33,527,600), which accounts for Contractor’s actual costs related to establishing pipeline mitigations required per Pipeline Corridor Crossing Evaluation Reports 1 and 2, as well as monitoring and maintenance for the duration of the Project at locations: P1A, P1B, P3G, P3F and Area 3 Berm as shown in Exhibit 3 of this Change Order.

4.The cost summary and detailed costs for this Change Order is provided in Exhibit 1 of this Change Order.

5.Schedule C-1 (Aggregate Labor and Skills Price Milestone Payment Schedule) and Schedule C-2 (Aggregate Labor and Skills Price Monthly Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 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-00006)	$	(29,789,345)
3. The Contract Price prior to this Change Order was	$	5,454,210,655
4. The Aggregate Equipment Price will be (decreased) by this Change Order in the amount of	[***]
5. The Aggregate Labor and Skills Price will be (decreased) 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	$	5,420,683,055

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 2 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: SS Contractor 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.

CORPUS CHRISTI LIQUEFACTION, LLC

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

BECHTEL ENERGY INC.

By:	/s/ Steven Smith
Name:	Steven Smith
Title:	Senior Project Manager

CHANGE ORDER FORM

ACID GAS FLARE K/O DRUM

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. DATE OF AGREEMENT: March 1, 2022 CHANGE ORDER NUMBER: CO-00008 DATE OF CHANGE ORDER: August 16, 2022

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

1.Pursuant to Article 6.1 of the Agreement (Owner’s Right to Change Order), Section 4 of Attachment NN of the Agreement (Scoping Adjustments), and Owner Letter No. CCLIQ3-BE-C22-020, dated June 28, 2022, Parties agree this Change Order adds the Acid Gas Flare K/O Drum Option to Contractor’s Scope of Work.

2.The Acid Gas Flare K/O Drum Option in Attachment NN of the Agreement is Fourteen Million, Nine Hundred Fifty-Three Thousand U.S. Dollars (U.S. $14,953,000).

3.The cost summary for this Change Order is provided in Exhibit 1 of this Change Order.

4.Schedule C-1 (Aggregate Labor and Skills Price Milestone Payment Schedule) and Schedule C-2 (Aggregate Labor and Skills Price Monthly Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 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-00007)	$	(63,316,945)
3. The Contract Price prior to this Change Order was	$	5,420,683,055
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	$	5,435,636,055

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 2 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: SS Contractor 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.

CORPUS CHRISTI LIQUEFACTION, LLC

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

BECHTEL ENERGY INC.

By:	/s/ Steven Smith
Name:	Steven Smith
Title:	Senior Project Manager

CHANGE ORDER

PACKAGE 7A (WITHOUT SITE WORK)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. DATE OF AGREEMENT: March 1, 2022 CHANGE ORDER NUMBER: CO-00009 DATE OF CHANGE ORDER: August 16, 2022

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

1.Pursuant to Article 6.1 of the Agreement (Owner’s Right to Change Order), Section 7 of Attachment NN of the Agreement (Scoping Adjustments), the Parties agree this Change Order adds the balance of Package 7A (without Site Work) to Contractor’s Scope of Work.

2.Change Order CO-00002, dated April 29, 2022, increased the Contract Price by Twenty Million U.S. Dollars (U.S.$20,000,000) for Package 7A (without Site Work) during Limited Notice to Proceed (LNTP No. 1).

3.This Change Order increases the Contract Price by Forty-Three Million U.S. Dollars (U.S. $43,000,000) for the balance of Package 7A (without Site Work) in accordance with the Agreement.

4.Schedule C-1 (Aggregate Labor and Skills Price Milestone Payment Schedule) and Schedule C-3 (Aggregate Equipment Price Milestone Payment Schedule) 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-00008)	$	(48,363,945)
3. The Contract Price prior to this Change Order was	$	5,435,636,055
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	$	5,478,636,055

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: SSContractor 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.

CORPUS CHRISTI LIQUEFACTION, LLC

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

BECHTEL ENERGY INC.

By:	/s/ Steven Smith
Name:	Steven Smith
Title:	Senior Project Manager

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 2, 2022 

/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 2, 2022

/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, 2022, 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 2, 2022 

/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, 2022, 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 2, 2022 

/s/ Zach Davis

Zach Davis
Chief Financial Officer of

Cheniere Energy, Inc.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2022	Oct. 31, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2022
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		248,659,406
Entity Central Index Key	0000003570
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q3

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Revenues
Revenues		$ 8,852	$ 3,200	$ 24,343	$ 9,307
Revenues from contracts with customers		8,904	4,260	24,443	10,773
Operating costs and expenses
Cost of sales (excluding items shown separately below)		11,073	4,868	24,161	8,408
Operating and maintenance expense		419	350	1,227	1,057
Development expense		4	2	12	5
Selling, general and administrative expense		92	70	265	224
Depreciation and amortization expense		280	259	827	753
Other		0	1	3	0
Total operating costs and expenses		11,868	5,550	26,495	10,447
Loss from operations		(3,016)	(2,350)	(2,152)	(1,140)
Other income (expense)
Interest expense, net of capitalized interest		(354)	(364)	(1,060)	(1,088)
Gain (loss) on modification or extinguishment of debt		3	(36)	(43)	(95)
Derivative gain (loss), net		0	(2)	2	(3)
Other expense, net		(29)	(24)	(21)	(14)
Total other expense		(380)	(426)	(1,122)	(1,200)
Loss before income taxes and non-controlling interest		(3,396)	(2,776)	(3,274)	(2,340)
Less: income tax benefit		(752)	(1,860)	(762)	(1,864)
Net loss		(2,644)	(916)	(2,512)	(476)
Less: net income (loss) attributable to non-controlling interest		(259)	168	(3)	544
Net loss attributable to common stockholders		$ (2,385)	$ (1,084)	$ (2,509)	$ (1,020)
Net loss per share attributable to common stockholders—basic	[1]	$ (9.54)	$ (4.27)	$ (9.94)	$ (4.03)
Net loss per share attributable to common stockholders—diluted	[1]	$ (9.54)	$ (4.27)	$ (9.94)	$ (4.03)
Weighted average number of common shares outstanding—basic		249.9	253.6	252.5	253.3
Weighted average number of common shares outstanding—diluted		249.9	253.6	252.5	253.3
LNG [Member]
Revenues
Revenues		$ 8,236	$ 3,078	$ 23,449	$ 8,990
Revenues from contracts with customers		8,422	4,170	23,774	10,505
Regasification [Member]
Revenues
Revenues from contracts with customers		455	68	591	202
Other [Member]
Revenues
Revenues		161	54	303	115
Revenues from contracts with customers		$ 27	$ 22	$ 78	$ 66

[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, 2022		Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 2,504	[1]	$ 1,404
Restricted cash and cash equivalents	834	[1]	413
Trade and other receivables, net of current expected credit losses	1,834		1,506
Inventory	1,129		706
Current derivative assets	131		55
Margin deposits	267		765
Contract assets	392		5
Other current assets	115		202
Total current assets	7,206		5,056
Property, plant and equipment, net of accumulated depreciation	30,904		30,288
Operating lease assets	2,795		2,102
Derivative assets	46		69
Goodwill	77		77
Deferred tax assets	2,100		1,204
Other non-current assets, net	514		462
Total assets	43,642	[1]	39,258
Current liabilities
Accounts payable	405		155
Accrued liabilities	3,108		2,299
Current debt, net of discount and debt issuance costs	1,717		366
Deferred revenue	211		155
Current operating lease liabilities	669		535
Current derivative liabilities	3,215		1,089
Other current liabilities	50		94
Total current liabilities	9,375		4,693
Long-term debt, net of premium, discount and debt issuance costs	25,325		29,449
Operating lease liabilities	2,082		1,541
Finance lease liabilities	75		57
Derivative liabilities	10,954		3,501
Other non-current liabilities	161		50
Stockholders’ 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; 276.7 million shares and 275.2 million shares issued at September 30, 2022 and December 31, 2021, respectively	1		1
Treasury stock: 26.8 million shares and 21.6 million shares at September 30, 2022 and December 31, 2021, respectively, at cost	(1,609)		(928)
Additional paid-in-capital	4,309		4,377
Accumulated deficit	(8,880)		(6,021)
Total Cheniere stockholders’ deficit	(6,179)		(2,571)
Non-controlling interest	1,849		2,538
Total stockholders’ deficit	(4,330)		(33)
Total liabilities and stockholders’ deficit	$ 43,642	[1]	$ 39,258

[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, 2022, total assets and liabilities of CQP were $19.9 billion and $24.3 billion, respectively, including $1.0 billion of cash and cash equivalents and $0.2 billion of restricted cash and cash equivalents.

XML

Consolidated Balance Sheets Parentheticals - USD ($) $ in Millions	Sep. 30, 2022		Dec. 31, 2021
Assets	$ 43,642	[1]	$ 39,258
Cash and cash equivalents	$ 2,504	[1]	$ 1,404
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	276,700,000		275,200,000
Treasury Stock, Shares	26,800,000		21,600,000
CQP [Member]
Assets	$ 19,903		$ 18,985
Liabilities	24,306		18,554
Cash and cash equivalents	988		$ 876
Restricted cash and cash equivalents	$ 200

[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, 2022, total assets and liabilities of CQP were $19.9 billion and $24.3 billion, respectively, including $1.0 billion of cash and cash equivalents and $0.2 billion of restricted cash and cash equivalents.

XML

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Accumulated Deficit	Non-controlling Interest
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2020	252,300
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2020	20,800
Stockholders' Equity, Beginning of Period at Dec. 31, 2020	$ 2,218	$ 1	$ (872)	$ 4,273	$ (3,593)	$ 2,409
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of restricted stock units and performance stock units, shares		1,800	0
Vesting of restricted stock units and performance stock units	0	$ 0	$ 0	0	0	0
Share-based compensation	33	$ 0	$ 0	33	0	0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock		(600)
Shares withheld from employees related to share-based compensation, at cost, shares, treasury shares			600
Shares withheld from employees related to share-based compensation, at cost	(42)	$ 0	$ (42)	0	0	0
Net income (loss) attributable to non-controlling interest	178	0	0	0	0	178
Distributions to non-controlling interest	(160)	0	0	0	0	(160)
Net income (loss)	$ 393	0	0	0	393	0
Common Stock, Shares, Outstanding, End of Period at Mar. 31, 2021	253,500
Treasury Stock, Shares, End of Period at Mar. 31, 2021	21,400
Stockholders' Equity, End of Period at Mar. 31, 2021	$ 2,620	1	(914)	4,306	(3,200)	2,427
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2020	252,300
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2020	20,800
Stockholders' Equity, Beginning of Period at Dec. 31, 2020	$ 2,218	1	(872)	4,273	(3,593)	2,409
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares repurchased, at cost, shares	80
Net income (loss) attributable to non-controlling interest	$ 544
Net income (loss)	$ (1,020)
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2021	253,500
Treasury Stock, Shares, End of Period at Sep. 30, 2021	21,600
Stockholders' Equity, End of Period at Sep. 30, 2021	$ 1,213	1	(924)	4,364	(4,698)	2,470
Common Stock, Shares, Outstanding, Beginning of Period at Mar. 31, 2021	253,500
Treasury Stock, Shares, Beginning of Period at Mar. 31, 2021	21,400
Stockholders' Equity, Beginning of Period at Mar. 31, 2021	$ 2,620	$ 1	$ (914)	4,306	(3,200)	2,427
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of restricted stock units and performance stock units, shares		100	0
Vesting of restricted stock units and performance stock units	0	$ 0	$ 0	0	0	0
Share-based compensation	31	$ 0	$ 0	31	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	$ (1)	0	0	0
Net income (loss) attributable to non-controlling interest	198	0	0	0	0	198
Distributions to non-controlling interest	(162)	0	0	0	0	(162)
Net income (loss)	$ (329)	0	0	0	(329)	0
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2021	253,600
Treasury Stock, Shares, End of Period at Jun. 30, 2021	21,400
Stockholders' Equity, End of Period at Jun. 30, 2021	$ 2,357	$ 1	$ (915)	4,337	(3,529)	2,463
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of restricted stock units and performance stock units, shares		100	0
Vesting of restricted stock units and performance stock units	0	$ 0	$ 0	0	0	0
Share-based compensation	28	$ 0	$ 0	28	0	0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock		(100)
Shares withheld from employees related to share-based compensation, at cost, shares, treasury shares			100
Shares withheld from employees related to share-based compensation, at cost	$ (4)	$ 0	$ (3)	(1)	0	0
Shares repurchased, at cost, shares	80	(100)	100
Shares repurchased, at cost	$ (6)	$ 0	$ (6)	0	0	0
Net income (loss) attributable to non-controlling interest	168	0	0	0	0	168
Distributions to non-controlling interest	(161)	0	0	0	0	(161)
Dividends declared and accrued ($0.33 per common share)	(85)	0	0	0	(85)	0
Net income (loss)	$ (1,084)	0	0	0	(1,084)	0
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2021	253,500
Treasury Stock, Shares, End of Period at Sep. 30, 2021	21,600
Stockholders' Equity, End of Period at Sep. 30, 2021	$ 1,213	1	(924)	4,364	(4,698)	2,470
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 restricted stock units and performance stock units, shares		1,300	0
Vesting of restricted stock units and performance stock units	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 (loss) attributable to non-controlling interest	84	0	0	0	0	84
Distributions to non-controlling interest	(171)	0	0	0	0	(171)
Dividends declared and paid ($0.33 per common share)	(85)	0	0	0	(85)	0
Net income (loss)	$ (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
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 (loss) attributable to non-controlling interest	$ (3)
Net income (loss)	$ (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
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 restricted stock units and performance stock units, shares		100	0
Vesting of restricted stock units and performance stock units	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 (loss) attributable to non-controlling interest	172	0	0	0	0	172
Distributions to non-controlling interest	(256)	0	0	0	0	(256)
Dividends declared and paid ($0.33 per common share)	(85)	0	0	0	(85)	0
Net income (loss)	$ 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]
Vesting of restricted stock units and performance stock units, shares		100	0
Vesting of restricted stock units and performance stock units	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 (loss) attributable to non-controlling interest	(259)	0	0	0	0	(259)
Distributions to non-controlling interest	(259)	0	0	0	0	(259)
Dividends declared and paid ($0.33 per common share)	(81)	0	0	0	(81)	0
Dividends declared and accrued ($0.33 per common share)	(103)	0	0	0	(103)	0
Net income (loss)	$ (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

XML

Consolidated Statements of Stockholders' Equity Parentheticals - $ / shares	3 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2021
Common Stock, Dividends, Per Share, Declared	$ 0.33			$ 0
Common Stock, Dividends, Per Share, Declared, Accrued	0.395
Common Stock
Common Stock, Dividends, Per Share, Declared	$ 0.33	$ 0.33	$ 0.33
Common Stock, Dividends, Per Share, Declared, Accrued				$ 0.33

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021
Cash flows from operating activities
Net loss	$ (2,512)	$ (476)
Adjustments to reconcile net loss to net cash provided by operating activities:
Unrealized foreign currency exchange gain, net	(10)	0
Depreciation and amortization expense	827	753
Share-based compensation expense	115	91
Non-cash interest expense	14	16
Amortization of debt discount and debt issuance costs	43	57
Reduction of right-of-use assets	444	269
Loss on modification or extinguishment of debt	43	95
Total losses on derivative instruments, net	10,228	4,230
Net cash used for settlement of derivative instruments	(702)	(486)
Loss on equity method investments	55	16
Deferred taxes	(856)	(1,872)
Repayment of paid-in-kind interest related to repurchase of convertible notes	(13)	(190)
Other, net	10	3
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	(389)	(338)
Inventory	(426)	(174)
Margin deposits	498	(311)
Contract assets	(387)	(4)
Other current assets	57	(88)
Accounts payable and accrued liabilities	938	612
Total deferred revenue	91	58
Total operating lease liabilities	(460)	(285)
Other, net	(37)	81
Net cash provided by operating activities	7,571	2,057
Cash flows from investing activities
Property, plant and equipment	(1,339)	(761)
Proceeds from sale of fixed assets	1	68
Investment in equity method investment	(10)	0
Other, net	0	(14)
Net cash used in investing activities	(1,348)	(707)
Cash flows from financing activities
Proceeds from issuances of debt	1,015	4,104
Redemptions and repayments of debt	(4,005)	(4,276)
Debt issuance and other financing costs	(44)	(38)
Debt modification or extinguishment costs	(33)	(67)
Distributions to non-controlling interest	(686)	(483)
Payments related to tax withholdings for share-based compensation	(62)	(47)
Repurchase of common stock	(640)	(6)
Dividends to shareholders	(251)	0
Payments of finance lease liabilities	(1)	0
Other, net	0	8
Net cash used in financing activities	(4,707)	(805)
Effect of Exchange Rate on Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents, Continuing Operations	5	0
Net increase in cash, cash equivalents and restricted cash and cash equivalents	1,521	545
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	1,817	2,077
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$ 3,338	$ 2,622

XML

Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2022		Dec. 31, 2021	Sep. 30, 2021	Dec. 31, 2020
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 2,504	[1]	$ 1,404
Restricted cash and cash equivalents	834	[1]	413
Total cash, cash equivalents and restricted cash and cash equivalents	$ 3,338		$ 1,817	$ 2,622	$ 2,077

[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, 2022, total assets and liabilities of CQP were $19.9 billion and $24.3 billion, respectively, including $1.0 billion of cash and cash equivalents and $0.2 billion of restricted cash and cash equivalents.

XML

Nature of Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2022

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, with Train 6 having achieved substantial completion on February 4, 2022, 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, with the third berth having achieved substantial completion on October 27, 2022. CQP also owns a 94-mile pipeline that interconnects the Sabine Pass LNG Terminal with a number of large interstate and intrastate pipelines through its subsidiary, CTPL. As of September 30, 2022, 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 up to seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. CCL Stage III, CCL and CCP received approval from FERC in November 2019 to site, construct and operate the Corpus Christi Stage 3 Project. In March 2022, CCL Stage III issued limited notice to proceed to Bechtel Energy Inc. (“Bechtel”) to commence early engineering, procurement and site works. In June 2022, our board of directors (our “Board”) made a positive FID with respect to the investment in the construction and operation of the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel effective June 16, 2022. In connection with the positive FID, CCL Stage III, through which we were developing and constructing the Corpus Christi Stage 3 Project, was contributed to CCH and subsequently merged with and into CCL, the surviving entity of the merger and a wholly owned subsidiary of CCH. 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 existing operational Trains, midscale Trains, storage tanks and marine berths, 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 August 2022, certain of our subsidiaries initiated the pre-filing review process with the FERC under the National Environmental Policy 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. 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, 2021.

Results of operations for the three and nine months ended September 30, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.

Recent Accounting Standards

ASU 2020-06

In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. This guidance simplifies the accounting for convertible instruments primarily by eliminating the existing cash conversion and beneficial conversion models within Subtopic 470-20, which will result in fewer

embedded conversion options being accounted for separately from the debt host. The guidance also amends and simplifies the calculation of earnings per share relating to convertible instruments. This guidance is effective for annual periods beginning after December 15, 2021, including interim periods within that reporting period, with earlier adoption permitted for fiscal years beginning after December 15, 2020, including interim periods within that reporting period, using either a full or modified retrospective approach. We adopted this guidance on January 1, 2022 using the modified retrospective approach. The adoption of ASU 2020-06 primarily resulted in the reclassification of the previously bifurcated equity component associated with the 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) to debt as a result of the elimination of the cash conversion model. As of January 1, 2022, the reclassification resulted in: (1) a $194 million reduction of the equity component recorded in additional paid-in capital, before offsetting tax effect of $41 million, (2) a $189 million increase in the carrying value of our 2045 Cheniere Convertible Senior Notes and (3) a $5 million decrease in accumulated deficit, before offsetting tax effect of $1 million. In December 2021, we issued a notice of redemption for all $625 million aggregate principal amount outstanding of our 2045 Cheniere Convertible Senior Notes, which were redeemed on January 5, 2022. See Note 9—Debt for further discussion of the 2045 Cheniere Convertible Senior Notes.

The adoption of ASU 2020-06 also impacted the calculation of the dilutive effect of our 2045 Cheniere Convertible Senior Notes on our net loss per share for the three and nine months ended September 30, 2022, as further discussed in Note 14—Net Loss per Share Attributable to Common Stockholders.

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 expected to arise from the market transition from LIBOR to alternative reference rates. The standard is effective from March 12, 2020 to December 31, 2022.

We have various credit facilities indexed to LIBOR, as further described in Note 9—Debt. To date, we have amended certain of our credit facilities to incorporate a replacement rate or a fallback replacement rate indexed to SOFR as a result of the expected LIBOR transition. We elected to apply the optional expedients as applicable to certain modified facilities; however the impact of applying the optional expedients was not material, and we do not expect the transition to SOFR or other replacement rate indexes to have a material impact on our future cash flows. We intend to apply the optional expedients to qualifying contract modifications in the future; however, we do not expect the impact of such application to be material.

XML

Restricted Cash and Cash Equivalents

9 Months Ended

Sep. 30, 2022

Restricted Cash and Cash Equivalents [Abstract]

Restricted Cash and Cash Equivalents

RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. Restricted cash and cash equivalents consisted of the following (in millions):

	September 30,		December 31,
	2022		2021
Restricted cash and cash equivalents
SPL Project	$	195	$	98
CCL Project	202		44
Cash held by our subsidiaries that is restricted to Cheniere	437		271
Total restricted cash and cash equivalents	$	834	$	413

Pursuant to the accounts agreements entered into with the collateral trustees for the benefit of SPL’s debt holders and CCH’s debt holders, SPL and CCH are required to deposit all cash received into reserve accounts controlled by the collateral trustees.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. The majority of the cash held by our subsidiaries that is restricted to Cheniere relates to advance funding for operation and construction needs of the Liquefaction Projects.

XML

Trade and Other Receivables, Net of Current Expected Credit Losses

9 Months Ended

Sep. 30, 2022

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,
	2022		2021
Trade receivables
SPL and CCL	$	1,070	$	802
Cheniere Marketing	619		640
Other receivables	145		64
Total trade and other receivables, net of current expected credit losses	$	1,834	$	1,506

XML

Inventory

9 Months Ended

Sep. 30, 2022

Inventory Disclosure [Abstract]

Inventory

INVENTORY

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2022		2021
LNG in-transit	$	652	$	312
LNG	230		153
Materials	189		174
Natural gas	55		64
Other	3		3
Total inventory	$	1,129	$	706

XML

Property, Plant and Equipment, Net of Accumulated Depreciation

9 Months Ended

Sep. 30, 2022

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,
	2022		2021
LNG terminal
Terminal and interconnecting pipeline facilities	$	33,186	$	30,660
Site and related costs	447		441
Construction-in-process	1,868		2,995
Accumulated depreciation	(4,715)		(3,912)
Total LNG terminal, net of accumulated depreciation	30,786		30,184
Fixed assets and other
Computer and office equipment	31		25
Furniture and fixtures	19		20
Computer software	123		120
Leasehold improvements	46		45
Land	1		1
Other	19		19
Accumulated depreciation	(191)		(176)
Total fixed assets and other, net of accumulated depreciation	48		54
Assets under finance lease
Tug vessels	83		60
Accumulated depreciation	(13)		(10)
Total assets under finance lease, net of accumulated depreciation	70		50
Property, plant and equipment, net of accumulated depreciation	$	30,904	$	30,288

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Depreciation expense	$	278	$	257	$	822	$	749
Offsets to LNG terminal costs (1)	—		—		204		227

(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.

XML

Derivative Instruments

9 Months Ended

Sep. 30, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments:

•interest rate swaps (“Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on CCH’s amended and restated term loan credit facility (the “CCH Credit Facility”), with the last of our Interest Rate Derivatives expiring in May 2022;

•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 (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”);

•physical LNG derivatives in which we have contractual net settlement (“Physical LNG Trading Derivatives”) 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”); 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 (in millions):

	Fair Value Measurements as of
	September 30, 2022								December 31, 2021
	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
Interest Rate Derivatives liability	$	—	$	—	$	—	$	—	$	—	$	(40)	$	—	$	(40)
Liquefaction Supply Derivatives asset (liability)	(106)		(5)		(13,805)		(13,916)		7		(9)		(4,036)		(4,038)
LNG Trading Derivatives liability	(14)		(113)		—		(127)		(22)		(378)		—		(400)
FX Derivatives asset	—		51		—		51		—		12		—		12

We value our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our LNG Trading Derivatives and our Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, using 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 Physical 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 Physical 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 would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and volatility.

The Level 3 fair value measurements of our Physical LNG Trading Derivatives and the natural gas positions within our Physical 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 Physical Liquefaction Supply Derivatives as of September 30, 2022:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(13,805)	Market approach incorporating present value techniques	Henry Hub basis spread	$(2.495) - $0.677 / $(0.090)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	89% - 943% / 197%

(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 Physical LNG Trading Derivatives and our Physical Liquefaction Supply Derivatives.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021 (1)		2022		2021 (1)
Balance, beginning of period	$	(8,462)	$	(389)	$	(4,036)	$	241
Realized and mark-to-market losses:
Included in cost of sales	(5,668)		(2,982)		(8,825)		(2,898)
Purchases and settlements:
Purchases	4		5		(1,390)		(657)
Settlements	322		75		446		23
Transfers out of Level 3 (2)	(1)		—		—		—
Balance, end of period	$	(13,805)	$	(3,291)	$	(13,805)	$	(3,291)
Change in unrealized losses relating to instruments still held at end of period	$	(5,668)	$	(2,982)	$	(8,825)	$	(2,898)

(1)Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 12—Related Party Transactions.

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

Except for Interest Rate Derivatives, all 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.

Interest Rate Derivatives

CCH previously entered into the following Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility, which expired in May 2022:

	Notional Amounts
	September 30, 2022	December 31, 2021	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives	$—	$4.5 billion	2.30%	One-month LIBOR

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021
Interest Rate Derivatives	Derivative gain (loss), net	$	—	$	(2)	$	2	$	(3)

Commodity Derivatives

SPL and CCL hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The remaining minimum terms of the Physical Liquefaction Supply Derivatives range up to approximately 25 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.

Commencing in the first quarter of 2021, Cheniere Marketing entered into physical LNG transactions that provide for contractual net settlement. Such transactions are accounted for as LNG Trading Derivatives, and are designed to economically hedge exposure to the commodity markets in which we sell LNG. We have historically entered into, and may from time to time enter into, financial LNG Trading Derivatives in the form of swaps, forwards, options or futures. The terms of LNG Trading Derivatives range up to approximately two years.

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

	September 30, 2022		December 31, 2021
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,357	64	11,238	33

(1)Excludes notional amounts associated with extension options that were uncertain to be taken as of September 30, 2022.

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,
		2022		2021		2022		2021
LNG Trading Derivatives	LNG revenues	$	(237)	$	(1,098)	$	(454)	$	(1,539)
LNG Trading Derivatives	Cost of sales	(4)		55		103		136
Liquefaction Supply Derivatives (2)	LNG revenues	(3)		(4)		8		(3)
Liquefaction Supply Derivatives (2)	Cost of sales (3)	(5,508)		(2,444)		(10,008)		(2,848)

(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 derivative instruments that settle through physical delivery.

(3)Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 12—Related Party Transactions.

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 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 $597 million and $762 million as of September 30, 2022 and December 31, 2021, 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,
		2022		2021		2022		2021
FX Derivatives	LNG revenues	$	54	$	11	$	121	$	27

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, 2022
	Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	50	$	25	$	56	$	131
Derivative assets	—		46		—		—		46
Total derivative assets	—		96		25		56		177
Current derivative liabilities	—		(3,058)		(152)		(5)		(3,215)
Derivative liabilities	—		(10,954)		—		—		(10,954)
Total derivative liabilities	—		(14,012)		(152)		(5)		(14,169)
Derivative asset (liability), net	$	—	$	(13,916)	$	(127)	$	51	$	(13,992)
	December 31, 2021
	Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	38	$	2	$	15	$	55
Derivative assets	—		69		—		—		69
Total derivative assets	—		107		2		15		124
Current derivative liabilities	(40)		(644)		(402)		(3)		(1,089)
Derivative liabilities	—		(3,501)		—		—		(3,501)
Total derivative liabilities	(40)		(4,145)		(402)		(3)		(4,590)
Derivative asset (liability), net	$	(40)	$	(4,038)	$	(400)	$	12	$	(4,466)

(1)Does not include collateral posted with counterparties by us of $152 million and $20 million as of September 30, 2022 and December 31, 2021, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $115 million and $745 million, as of September 30, 2022 and December 31, 2021, respectively, which are included in margin deposits in 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, 2022
Gross assets	$	108	$	35	$	57
Offsetting amounts	(12)		(10)		(1)
Net assets	$	96	$	25	$	56
Gross liabilities	$	(14,507)	$	(165)	$	(5)
Offsetting amounts	495		13		—
Net liabilities	$	(14,012)	$	(152)	$	(5)
As of December 31, 2021
Gross assets	$	155	$	10	$	48
Offsetting amounts	(48)		(8)		(33)
Net assets	$	107	$	2	$	15
Gross liabilities	$	(4,382)	$	(551)	$	(10)
Offsetting amounts	237		149		7
Net liabilities	$	(4,145)	$	(402)	$	(3)

XML

Non-Controlling Interest and Variable Interest Entity

9 Months Ended

Sep. 30, 2022

Noncontrolling Interest and Variable Interest Entity [Abstract]

Non-Controlling Interest and Variable Interest Entity

NON-CONTROLLING INTEREST AND VARIABLE INTEREST ENTITY 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. CQP is accounted for as a consolidated VIE.

The following table presents the summarized 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,
	2022		2021
ASSETS
Current assets
Cash and cash equivalents	$	988	$	876
Restricted cash and cash equivalents	195		98
Trade and other receivables, net of current expected credit losses	805		580
Contract assets	387		—
Other current assets	401		285
Total current assets	2,776		1,839
Property, plant and equipment, net of accumulated depreciation	16,827		16,830
Other non-current assets, net	300		316
Total assets	$	19,903	$	18,985
LIABILITIES
Current liabilities
Accrued liabilities	$	1,665	$	1,077
Current debt, net of discount and debt issuance costs	1,498		—
Other current liabilities	1,363		200
Total current liabilities	4,526		1,277
Long-term debt, net of premium, discount and debt issuance costs	15,699		17,177
Other non-current liabilities	4,081		100
Total liabilities	$	24,306	$	18,554

XML

Accrued Liabilities

9 Months Ended

Sep. 30, 2022

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2022		2021
Natural gas purchases	$	2,112	$	1,323
Derivative settlements	98		329
Interest costs and related debt fees	345		214
LNG terminals and related pipeline costs	254		144
Compensation and benefits	109		180
LNG inventory	8		34
Accrued dividends	101		—
Other accrued liabilities	81		75
Total accrued liabilities	$	3,108	$	2,299

XML

Debt

9 Months Ended

Sep. 30, 2022

Debt Disclosure [Abstract]

Debt

DEBT

Debt consisted of the following (in millions): 

	September 30,		December 31,
	2022		2021
SPL:
Senior Secured Notes:
5.625% due 2023 (the “2023 SPL Senior Notes”) (1)	$	1,500	$	1,500
5.75% due 2024	2,000		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
4.27% weighted average rate due 2037	1,282		1,282
Total SPL Senior Secured Notes	13,132		13,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Total debt - SPL	13,132		13,132
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
Total CQP Senior Notes	4,200		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Total debt - CQP	4,200		4,200
CCH:
Senior Secured Notes:
7.000% due 2024	1,250		1,250
5.875% due 2025	1,500		1,500
5.125% due 2027 (2)	1,500		1,500
3.700% due 2029 (2)	1,492		1,500
3.72% weighted average rate due 2039 (2)	2,699		2,721
Total CCH Senior Secured Notes	8,441		8,471
CCH Credit Facility	—		1,728
Working capital facility (the “CCH Working Capital Facility”) (3)	—		250
Total debt - CCH	8,441		10,449
Cheniere:
4.625% Senior Secured Notes due 2028	1,500		2,000
2045 Cheniere Convertible Senior Notes (4)	—		625
Revolving credit facility (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		2,625
Cheniere Marketing: trade finance facilities and letter of credit facility (3)	—		—
Total debt	27,273		30,406
Current portion of long-term debt	(219)		(117)
Short-term debt	(1,498)		(250)
Unamortized premium, discount and debt issuance costs, net	(231)		(590)
Total long-term debt, net of premium, discount and debt issuance costs	$	25,325	$	29,449

(1)In October 2022, $300 million of the 2023 SPL Senior Notes were redeemed. As of September 30, 2022, the entire amount of the 2023 SPL Senior Notes was classified as short-term debt.

(2)Subsequent to September 30, 2022 and through October 31, 2022, we executed bond repurchases totaling $221 million, inclusive of CCH’s Senior Secured Notes due 2027, 2029 and 2039 on the open market, which are classified as current portion of long-term debt as of September 30, 2022 net of discount and debt issuance costs of $2 million.

(3)These debt instruments are classified as short-term debt.

(4)The redemption of these notes was financed with borrowings under the Cheniere Revolving Credit Facility, which is a long-term debt instrument. Therefore, the 2045 Cheniere Convertible Senior Notes were classified as long-term debt as of December 31, 2021. See Convertible Notes section below for further discussion of the redemption.

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of September 30, 2022 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities		CCH Credit Facility (1)		CCH Working Capital Facility (1)		Cheniere Revolving Credit Facility
Total facility size	$	1,200	$	750	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	363		—		—		218		—
Available commitment	$	837	$	750	$	3,260	$	1,282	$	1,250
Priority ranking	Senior secured		Senior secured		Senior secured		Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%		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 applicable margin		LIBOR plus 1.250% - 2.375% or base rate plus 0.250% - 1.375% (2)
Commitment fees on undrawn balance	0.15%		0.49%		0.53%		0.18%		0.25%
Maturity date	March 19, 2025		May 29, 2024		(3)		June 15, 2027		October 28, 2026

(1)In June 2022, CCH amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.

(2)This facility was amended in 2021 to establish a SOFR-indexed replacement rate for LIBOR.

(3)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.

Convertible Notes

On December 6, 2021, we issued a notice of redemption for all $625 million aggregate principal amount outstanding of the 2045 Cheniere Convertible Senior Notes. The notice of redemption allowed holders to elect to convert their notes at any time prior to a specified deadline on December 31, 2021, with settlement of such converted notes in cash, as elected by us, on January 5, 2022. The impact of holders electing conversion was immaterial to the Consolidated Financial Statements. The 2045 Cheniere Convertible Senior Notes not converted were redeemed on January 5, 2022 with borrowings under the Cheniere Revolving Credit Facility. We recognized $16 million of debt extinguishment costs related to the early redemption of these convertible notes.

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, CQP and CCH are restricted from making distributions under agreements governing their respective indebtedness generally until, among other requirements, deposits are made into any required debt service reserve accounts 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, 2022, 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, including interest expense related to our convertible notes, consisted of the following (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Interest cost on convertible notes:
Interest per contractual rate	$	—	$	6	$	—	$	29
Amortization of debt discount and debt issuance costs	—		1		—		9
Total interest cost related to convertible notes	—		7		—		38
Interest cost on debt and finance leases excluding convertible notes	376		391		1,118		1,178
Total interest cost	376		398		1,118		1,216
Capitalized interest	(22)		(34)		(58)		(128)
Total interest expense, net of capitalized interest	$	354	$	364	$	1,060	$	1,088

Fair Value Disclosures

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

	September 30, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	24,020	$	22,461	$	24,550	$	26,725
Senior notes — Level 3 (2)	3,253		2,916		3,253		3,693
2045 Cheniere Convertible Senior Notes — Level 1 (3)	—		—		625		526

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 

(3)The Level 1 estimated fair value was based on unadjusted quoted prices in active markets for identical liabilities that we had the ability to access at the measurement date.

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.

XML

Leases

9 Months Ended

Sep. 30, 2022

Leases [Abstract]

Leases

LEASES

Our leased assets consist primarily of LNG vessel 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 tug vessels, 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	2022		2021
Right-of-use assets—Operating	Operating lease assets	$	2,795	$	2,102
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	70		50
Total right-of-use assets		$	2,865	$	2,152
Current operating lease liabilities	Current operating lease liabilities	$	669	$	535
Current finance lease liabilities	Other current liabilities	6		2
Non-current operating lease liabilities	Operating lease liabilities	2,082		1,541
Non-current finance lease liabilities	Finance lease liabilities	75		57
Total lease liabilities		$	2,832	$	2,135

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,
		2022		2021		2022		2021
Operating lease cost (a)	Operating costs and expenses (1)	$	213	$	145	$	604	$	441
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	1		—		3		2
Interest on lease liabilities	Interest expense, net of capitalized interest	2		2		7		7
Total lease cost		$	216	$	147	$	614	$	450
(a) Included in operating lease cost:
Short-term lease costs		$	16	$	22	$	80	$	103
Variable lease costs		7		7		16		20

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

Future annual minimum lease payments for operating and finance leases as of September 30, 2022 are as follows (in millions): 

Years Ending December 31,	Operating Leases (1)		Finance Leases
2022	$	193	$	4
2023	736		15
2024	651		15
2025	474		15
2026	341		15
Thereafter	763		122
Total lease payments	3,158		186
Less: Interest	(407)		(105)
Present value of lease liabilities	$	2,751	$	81

(1)Does not include approximately $2.9 billion of legally binding minimum payments primarily for vessel charters contracted for as of September 30, 2022 which will commence in future periods with fixed minimum lease terms of up to 10 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, 2022		December 31, 2021
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.1	13.2	5.6	16.7
Weighted-average discount rate (1)	4.0%	14.6%	3.6%	16.2%

(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,
	2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	524	$	331
Operating cash flows from finance leases	6		7
Right-of-use assets obtained in exchange for operating lease liabilities	1,139		1,575
Right-of-use assets obtained in exchange for finance lease liabilities	23		—

LNG Vessel Subcharters

From time to time, we sublease certain LNG vessels under charter to third parties while retaining our existing obligation to the original lessor. As of September 30, 2022 and December 31, 2021, we had $534 million and $15 million future minimum sublease payments to be received from LNG vessel subcharters. 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,
	2022		2021		2022		2021
Fixed income	$	122	$	17	$	188	$	28
Variable income	12		15		37		21
Total sublease income	$	134	$	32	$	225	$	49

XML

Revenues

9 Months Ended

Sep. 30, 2022

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,
	2022		2021		2022		2021
Revenues from contracts with customers
LNG revenues	$	8,422	$	4,170	$	23,774	$	10,505
Regasification revenues	455		68		591		202
Other revenues	27		22		78		66
Total revenues from contracts with customers	8,904		4,260		24,443		10,773
Net derivative loss (1)	(186)		(1,092)		(325)		(1,515)
Other (2)	134		32		225		49
Total revenues	$	8,852	$	3,200	$	24,343	$	9,307

(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 and Liabilities

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

	September 30,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	553	$	140

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, 2022
Deferred revenue, beginning of period	$	194
Cash received but not yet recognized in revenue	284
Revenue recognized from prior year end deferral	(194)
Deferred revenue, end of period	$	284

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, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	113.5	9	$	107.1	9
Regasification revenues	1.6		2	1.9		4
Total revenues	$	115.1		$	109.0

(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 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 contracts where there is uncertainty that one or both of the parties will achieve certain milestones. Approximately 76% and 61% of our LNG revenues from contracts included in the table above during the three months ended September 30, 2022 and 2021, respectively, and approximately 72% and 56% of our LNG revenues from contracts included in the table above during the nine months ended September 30, 2022 and 2021, respectively, were related to variable consideration received from customers. During the three and nine months ended September 30, 2022, approximately 1% and 2%, respectively, of our regasification revenues were related to variable consideration received from customers and during each of the three and nine months ended September 30, 2021, approximately 5% of our regasification revenues were related to variable consideration received from customers.

We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. Inc. (“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 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, will terminate upon the later of SPLNG’s receipt of the Termination Fee or December 31, 2022. The termination agreement became effective on July 6, 2022. We have allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which we are recognizing ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations, and an offsetting $31 million in cash outflows allocable to the extinguishment of other remaining obligations we have to Chevron, which will be recognized upon receipt of the Termination Fee as a loss on extinguishment of debt on our Consolidated Statements of Operations. As of September 30, 2022, we recorded contract assets of $387 million related to the termination of the TUA.

XML

Related Party Transactions

9 Months Ended

Sep. 30, 2022

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
LNG Revenues
Natural Gas Transportation and Storage Agreements	$	—	$	—	$	4	$	—
Other revenues
Operation and Maintenance Services Agreements	3		2		5		5
Cost of sales
Natural Gas Supply Agreements (a) (1)	—		53		—		124
Natural Gas Transportation and Storage Agreements	—		—		1		1
Total cost of sales	—		53		1		125
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements	18		14		45		41
(a) Included in cost of sales:
Liquefaction Supply Derivative gain (1)	—		6		—		13

(1)Includes amounts recorded related to natural gas supply contracts that SPL and CCL had with related parties. These agreements ceased to be considered related party agreements during 2021, as discussed below.

Natural Gas Supply Agreement

CCL Natural Gas Supply Agreement

CCL was party to a natural gas supply agreement with a related party in the ordinary course of business to obtain a fixed minimum daily volume of feed gas for the operation of the CCL Project. The related party entity was acquired by a non-related party on November 1, 2021, therefore, as of such date, this agreement ceased to be considered a related party agreement.

Natural Gas Transportation and Storage Agreements

SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the SPL Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by Brookfield Asset Management, Inc., who indirectly acquired a portion of CQP’s limited partner interests in September 2020. We recorded accrued liabilities of $8 million and $4 million as of September 30, 2022 and December 31, 2021, respectively, with this related party.

CCL is party to natural gas transportation agreements with Midship Pipeline Company, LLC (“Midship Pipeline”) in the ordinary course of business for the operation of the CCL Project, for a period of 10 years which began in May 2020. We recorded accrued liabilities of $1 million as of both September 30, 2022 and December 31, 2021 with this related party. We account for our investment in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline, as an equity method investment. During the three months ended September 30, 2022, we recognized other-than-temporary impairment losses of $67 million related to our investment in Midship Holdings primarily related to increased forecast construction-related and operating costs, which are presented in other income (expense), net. Our investment in Midship Holdings, net of impairment losses, was $11 million as of September 30, 2022, which was measured using an income approach that utilized level 3 fair value inputs such as projected earnings and discount rates.

CCL is party to a natural gas transportation agreement with ADCC Pipeline, LLC and its wholly owned subsidiary (collectively, “ADCC Pipeline”) in the ordinary course of business for the operation of the CCL Project, with an initial term of 20 years with extension rights. We have a 30% equity interest in ADCC Pipeline, as further described below.

Operation and Maintenance Service Agreements

Cheniere LNG O&M Services, LLC (“O&M Services”), our wholly owned subsidiary, provides the development, construction, operation and maintenance services to Midship Pipeline pursuant to agreements in which O&M Services receives an agreed upon fee and reimbursement of costs incurred. O&M Services recorded $1 million and $2 million of other receivables as of September 30, 2022 and December 31, 2021, respectively, for services provided to Midship Pipeline under these agreements.

Share Purchase Agreement

In June 2022, we entered into a purchase agreement to purchase approximately $350 million of Cheniere’s common shares beneficially owned by Icahn Capital LP and certain affiliates of Icahn Capital LP (the “Icahn Group”) pursuant to which we purchased an aggregate of approximately 2.68 million shares of our common stock at a price per share of $130.52, the closing price on our common shares on the date of execution of the purchase agreement. Pursuant to the Nomination and Standstill Agreement entered into on August 21, 2015 by Cheniere and the Icahn Group, the Icahn Group’s remaining director designee to our Board, Andrew Teno, resigned from our Board and all committees of our Board effective June 21, 2022. Additionally, as of such date, the Icahn Group ceased to be considered a related party.

Interest in ADCC Pipeline, LLCIn June 2022, Cheniere, through its wholly owned subsidiary Cheniere ADCC Investments, LLC, acquired a 30% equity interest in ADCC Pipeline. ADCC Pipeline will develop, construct and operate an approximately 42-mile natural gas pipeline project connecting the Agua Dulce natural gas hub to the CCL Project. We currently have a future commitment of up to approximately $93 million to fund our equity interest, which commitment is subject to a condition precedent that has not yet been satisfied.

XML

Income Taxes

9 Months Ended

Sep. 30, 2022

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

We recorded an income tax benefit of $752 million and $762 million during the three and nine months ended September 30, 2022, respectively, and an income tax benefit of $1,860 million and $1,864 million during the three and nine months ended September 30, 2021, respectively.

We have historically calculated our provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate to year-to-date ordinary income or loss (“annual effective tax rate method”). Because of significant sensitivities in the annual effective tax rate as a result of variability in our earnings due to pre-tax derivative losses arising from changes in fair value from our IPM agreements and the portion of our earnings attributable to non-controlling interest, a relatively small change in estimated ordinary income or loss would result in significant changes in the estimated annual effective tax rate such that we are unable to make a reliable estimate of the annual effective tax rate for the three and nine months ended September 30, 2022. Accordingly, we have applied a discrete-period method to calculate income taxes for the three and nine months ended September 30, 2022 based on the year-to-date effective tax rate (“year-to-date effective tax rate method”). The year-to-date effective tax rate method treats the year-to-date period as if it was the annual period and determines the income tax expense or benefit on that basis.

Utilizing the year-to-date effective tax rate method, our effective tax rate for the three and nine months ended September 30, 2022 was 22.1% and 23.3%, respectively. The effective tax rate for the three and nine months ended September 30, 2022 represents a tax benefit on pre-tax loss and was higher than the statutory rate primarily due to our projected foreign derived intangible income (“FDII”) deduction, which results in income from our sales to foreign customers being taxed at a lower effective tax rate.

We used the annual effective tax rate method to calculate our income tax benefit for the three and nine months ended September 30, 2021, which was 67.0% and 79.7%, respectively, as it was determined that the annual effective tax rate method would produce a reliable estimate. The effective tax rate for the three and nine months ended September 30, 2021 did not bear a customary relationship to the statutory income tax rate due to variability in our earnings due to pre-tax derivative losses arising from changes in fair value from our IPM agreements and the portion of our earnings attributable to non-controlling interest.

XML

Net Loss Per Share Attributable to Common Stockholders

9 Months Ended

Sep. 30, 2022

Earnings Per Share [Abstract]

Net Loss Per Share Attributable to Common Stockholders

NET 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,
	2022		2021		2022		2021
Net loss attributable to common stockholders	$	(2,385)	$	(1,084)	$	(2,509)	$	(1,020)
Weighted average common shares outstanding:
Basic	249.9		253.6		252.5		253.3
Dilutive unvested stock	—		—		—		—
Diluted	249.9		253.6		252.5		253.3
Net loss per share attributable to common stockholders—basic and diluted	$	(9.54)	$	(4.27)	$	(9.94)	$	(4.03)
Dividends paid per common share	$	0.33	$	—	$	0.99	$	—

On September 12, 2022, we declared a quarterly dividend of $0.395 per share of common stock that is payable on November 16, 2022 to shareholders of record as of November 8, 2022.

Potentially dilutive securities that were not included in the diluted net 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,
	2022	2021	2022	2021
Unvested stock (1)	2.5	1.8	2.3	1.6
2045 Cheniere Convertible Senior Notes (2)	—	4.5	0.2	4.5
Total potentially dilutive common shares	2.5	6.3	2.5	6.1

(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 dates.

(2)As described in Note 9—Debt, 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 shareholders during the 2022 period. See Note 1—Nature of Operations and Basis of Presentation for further discussion of our adoption of ASU 2020-06.

XML

Stock Repurchase Programs

9 Months Ended

Sep. 30, 2022

Equity [Abstract]

Stock Repurchase Programs

STOCK REPURCHASE PROGRAMS

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Aggregate common stock repurchased	0.60		0.08		4.97		0.08
Weighted average price paid per share	$	125.34	$	83.97	$	128.73	$	83.97
Total amount paid	$	75	$	6	$	640	$	6

As of September 30, 2022, we had $358 million remaining under our share repurchase program, which increased to approximately $4.4 billion as of October 1, 2022.

XML

Customer Concentration

9 Months Ended

Sep. 30, 2022

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	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,
	2022	2021	2022	2021	2022	2021
Customer A	*	12%	*	14%	*	10%
Customer B	*	15%	*	13%	*	*
Customer C	*	11%	*	11%	*	*
Customer D	*	11%	*	*	*	*
Customer E	*	*	*	*	16%	—

* Less than 10%

XML

Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2022

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,
	2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	891	$	902
Cash paid for income taxes, net of refunds	28		2
Non-cash investing activity:
Transfers of property, plant and equipment in exchange for other non-current assets	17		—
Non-cash financing activity:
Declared and accrued dividends on common stock	103		85

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities was $354 million and $234 million as of September 30, 2022 and 2021, respectively.

XML

Nature of Operations and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2022

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, 2021.

Results of operations for the three and nine months ended September 30, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.

Recent Accounting Standards

Recent Accounting Standards

ASU 2020-06

In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. This guidance simplifies the accounting for convertible instruments primarily by eliminating the existing cash conversion and beneficial conversion models within Subtopic 470-20, which will result in fewer

embedded conversion options being accounted for separately from the debt host. The guidance also amends and simplifies the calculation of earnings per share relating to convertible instruments. This guidance is effective for annual periods beginning after December 15, 2021, including interim periods within that reporting period, with earlier adoption permitted for fiscal years beginning after December 15, 2020, including interim periods within that reporting period, using either a full or modified retrospective approach. We adopted this guidance on January 1, 2022 using the modified retrospective approach. The adoption of ASU 2020-06 primarily resulted in the reclassification of the previously bifurcated equity component associated with the 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) to debt as a result of the elimination of the cash conversion model. As of January 1, 2022, the reclassification resulted in: (1) a $194 million reduction of the equity component recorded in additional paid-in capital, before offsetting tax effect of $41 million, (2) a $189 million increase in the carrying value of our 2045 Cheniere Convertible Senior Notes and (3) a $5 million decrease in accumulated deficit, before offsetting tax effect of $1 million. In December 2021, we issued a notice of redemption for all $625 million aggregate principal amount outstanding of our 2045 Cheniere Convertible Senior Notes, which were redeemed on January 5, 2022. See Note 9—Debt for further discussion of the 2045 Cheniere Convertible Senior Notes.

The adoption of ASU 2020-06 also impacted the calculation of the dilutive effect of our 2045 Cheniere Convertible Senior Notes on our net loss per share for the three and nine months ended September 30, 2022, as further discussed in Note 14—Net Loss per Share Attributable to Common Stockholders.

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 expected to arise from the market transition from LIBOR to alternative reference rates. The standard is effective from March 12, 2020 to December 31, 2022.

We have various credit facilities indexed to LIBOR, as further described in Note 9—Debt. To date, we have amended certain of our credit facilities to incorporate a replacement rate or a fallback replacement rate indexed to SOFR as a result of the expected LIBOR transition. We elected to apply the optional expedients as applicable to certain modified facilities; however the impact of applying the optional expedients was not material, and we do not expect the transition to SOFR or other replacement rate indexes to have a material impact on our future cash flows. We intend to apply the optional expedients to qualifying contract modifications in the future; however, we do not expect the impact of such application to be material.

XML

Restricted Cash and Cash Equivalents (Tables)

9 Months Ended

Sep. 30, 2022

Restricted Cash and Cash Equivalents [Abstract]

Schedule of Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consisted of the following (in millions):

	September 30,		December 31,
	2022		2021
Restricted cash and cash equivalents
SPL Project	$	195	$	98
CCL Project	202		44
Cash held by our subsidiaries that is restricted to Cheniere	437		271
Total restricted cash and cash equivalents	$	834	$	413

XML

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

9 Months Ended

Sep. 30, 2022

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,
	2022		2021
Trade receivables
SPL and CCL	$	1,070	$	802
Cheniere Marketing	619		640
Other receivables	145		64
Total trade and other receivables, net of current expected credit losses	$	1,834	$	1,506

XML

Inventory (Tables)

9 Months Ended

Sep. 30, 2022

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2022		2021
LNG in-transit	$	652	$	312
LNG	230		153
Materials	189		174
Natural gas	55		64
Other	3		3
Total inventory	$	1,129	$	706

XML

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

9 Months Ended

Sep. 30, 2022

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,
	2022		2021
LNG terminal
Terminal and interconnecting pipeline facilities	$	33,186	$	30,660
Site and related costs	447		441
Construction-in-process	1,868		2,995
Accumulated depreciation	(4,715)		(3,912)
Total LNG terminal, net of accumulated depreciation	30,786		30,184
Fixed assets and other
Computer and office equipment	31		25
Furniture and fixtures	19		20
Computer software	123		120
Leasehold improvements	46		45
Land	1		1
Other	19		19
Accumulated depreciation	(191)		(176)
Total fixed assets and other, net of accumulated depreciation	48		54
Assets under finance lease
Tug vessels	83		60
Accumulated depreciation	(13)		(10)
Total assets under finance lease, net of accumulated depreciation	70		50
Property, plant and equipment, net of accumulated depreciation	$	30,904	$	30,288

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,
	2022		2021		2022		2021
Depreciation expense	$	278	$	257	$	822	$	749
Offsets to LNG terminal costs (1)	—		—		204		227

(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.

XML

Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2022

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 (in millions):

	Fair Value Measurements as of
	September 30, 2022								December 31, 2021
	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
Interest Rate Derivatives liability	$	—	$	—	$	—	$	—	$	—	$	(40)	$	—	$	(40)
Liquefaction Supply Derivatives asset (liability)	(106)		(5)		(13,805)		(13,916)		7		(9)		(4,036)		(4,038)
LNG Trading Derivatives liability	(14)		(113)		—		(127)		(22)		(378)		—		(400)
FX Derivatives asset	—		51		—		51		—		12		—		12

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2022:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(13,805)	Market approach incorporating present value techniques	Henry Hub basis spread	$(2.495) - $0.677 / $(0.090)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	89% - 943% / 197%

(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 Physical LNG Trading Derivatives and Physical Liquefaction Supply Derivatives (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021 (1)		2022		2021 (1)
Balance, beginning of period	$	(8,462)	$	(389)	$	(4,036)	$	241
Realized and mark-to-market losses:
Included in cost of sales	(5,668)		(2,982)		(8,825)		(2,898)
Purchases and settlements:
Purchases	4		5		(1,390)		(657)
Settlements	322		75		446		23
Transfers out of Level 3 (2)	(1)		—		—		—
Balance, end of period	$	(13,805)	$	(3,291)	$	(13,805)	$	(3,291)
Change in unrealized losses relating to instruments still held at end of period	$	(5,668)	$	(2,982)	$	(8,825)	$	(2,898)

(1)Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 12—Related Party Transactions.

(2)Transferred out of Level 3 as a result of unobservable 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, 2022
	Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	50	$	25	$	56	$	131
Derivative assets	—		46		—		—		46
Total derivative assets	—		96		25		56		177
Current derivative liabilities	—		(3,058)		(152)		(5)		(3,215)
Derivative liabilities	—		(10,954)		—		—		(10,954)
Total derivative liabilities	—		(14,012)		(152)		(5)		(14,169)
Derivative asset (liability), net	$	—	$	(13,916)	$	(127)	$	51	$	(13,992)
	December 31, 2021
	Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	38	$	2	$	15	$	55
Derivative assets	—		69		—		—		69
Total derivative assets	—		107		2		15		124
Current derivative liabilities	(40)		(644)		(402)		(3)		(1,089)
Derivative liabilities	—		(3,501)		—		—		(3,501)
Total derivative liabilities	(40)		(4,145)		(402)		(3)		(4,590)
Derivative asset (liability), net	$	(40)	$	(4,038)	$	(400)	$	12	$	(4,466)

(1)Does not include collateral posted with counterparties by us of $152 million and $20 million as of September 30, 2022 and December 31, 2021, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $115 million and $745 million, as of September 30, 2022 and December 31, 2021, respectively, which are included in margin deposits in 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, 2022
Gross assets	$	108	$	35	$	57
Offsetting amounts	(12)		(10)		(1)
Net assets	$	96	$	25	$	56
Gross liabilities	$	(14,507)	$	(165)	$	(5)
Offsetting amounts	495		13		—
Net liabilities	$	(14,012)	$	(152)	$	(5)
As of December 31, 2021
Gross assets	$	155	$	10	$	48
Offsetting amounts	(48)		(8)		(33)
Net assets	$	107	$	2	$	15
Gross liabilities	$	(4,382)	$	(551)	$	(10)
Offsetting amounts	237		149		7
Net liabilities	$	(4,145)	$	(402)	$	(3)

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

CCH previously entered into the following Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility, which expired in May 2022:

	Notional Amounts
	September 30, 2022	December 31, 2021	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives	$—	$4.5 billion	2.30%	One-month LIBOR

Derivative Instruments, Gain (Loss)

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021
Interest Rate Derivatives	Derivative gain (loss), net	$	—	$	(2)	$	2	$	(3)

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, 2022		December 31, 2021
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	13,357	64	11,238	33

(1)Excludes notional amounts associated with extension options that were uncertain to be taken as of September 30, 2022.

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,
		2022		2021		2022		2021
LNG Trading Derivatives	LNG revenues	$	(237)	$	(1,098)	$	(454)	$	(1,539)
LNG Trading Derivatives	Cost of sales	(4)		55		103		136
Liquefaction Supply Derivatives (2)	LNG revenues	(3)		(4)		8		(3)
Liquefaction Supply Derivatives (2)	Cost of sales (3)	(5,508)		(2,444)		(10,008)		(2,848)

(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 derivative instruments that settle through physical delivery.

(3)Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 12—Related Party Transactions.

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,
		2022		2021		2022		2021
FX Derivatives	LNG revenues	$	54	$	11	$	121	$	27

XML

Non-Controlling Interest and Variable Interest Entity (Tables)

9 Months Ended

Sep. 30, 2022

CQP [Member]

Noncontrolling Interest and Variable Interest Entity [Line Items]

Condensed Balance Sheet of Cheniere Partners

The following table presents the summarized 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,
	2022		2021
ASSETS
Current assets
Cash and cash equivalents	$	988	$	876
Restricted cash and cash equivalents	195		98
Trade and other receivables, net of current expected credit losses	805		580
Contract assets	387		—
Other current assets	401		285
Total current assets	2,776		1,839
Property, plant and equipment, net of accumulated depreciation	16,827		16,830
Other non-current assets, net	300		316
Total assets	$	19,903	$	18,985
LIABILITIES
Current liabilities
Accrued liabilities	$	1,665	$	1,077
Current debt, net of discount and debt issuance costs	1,498		—
Other current liabilities	1,363		200
Total current liabilities	4,526		1,277
Long-term debt, net of premium, discount and debt issuance costs	15,699		17,177
Other non-current liabilities	4,081		100
Total liabilities	$	24,306	$	18,554

XML

Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2022

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2022		2021
Natural gas purchases	$	2,112	$	1,323
Derivative settlements	98		329
Interest costs and related debt fees	345		214
LNG terminals and related pipeline costs	254		144
Compensation and benefits	109		180
LNG inventory	8		34
Accrued dividends	101		—
Other accrued liabilities	81		75
Total accrued liabilities	$	3,108	$	2,299

XML

Debt (Tables)

9 Months Ended

Sep. 30, 2022

Debt Disclosure [Abstract]

Schedule of Debt Instruments

Debt consisted of the following (in millions): 

	September 30,		December 31,
	2022		2021
SPL:
Senior Secured Notes:
5.625% due 2023 (the “2023 SPL Senior Notes”) (1)	$	1,500	$	1,500
5.75% due 2024	2,000		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
4.27% weighted average rate due 2037	1,282		1,282
Total SPL Senior Secured Notes	13,132		13,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Total debt - SPL	13,132		13,132
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
Total CQP Senior Notes	4,200		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Total debt - CQP	4,200		4,200
CCH:
Senior Secured Notes:
7.000% due 2024	1,250		1,250
5.875% due 2025	1,500		1,500
5.125% due 2027 (2)	1,500		1,500
3.700% due 2029 (2)	1,492		1,500
3.72% weighted average rate due 2039 (2)	2,699		2,721
Total CCH Senior Secured Notes	8,441		8,471
CCH Credit Facility	—		1,728
Working capital facility (the “CCH Working Capital Facility”) (3)	—		250
Total debt - CCH	8,441		10,449
Cheniere:
4.625% Senior Secured Notes due 2028	1,500		2,000
2045 Cheniere Convertible Senior Notes (4)	—		625
Revolving credit facility (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		2,625
Cheniere Marketing: trade finance facilities and letter of credit facility (3)	—		—
Total debt	27,273		30,406
Current portion of long-term debt	(219)		(117)
Short-term debt	(1,498)		(250)
Unamortized premium, discount and debt issuance costs, net	(231)		(590)
Total long-term debt, net of premium, discount and debt issuance costs	$	25,325	$	29,449

(1)In October 2022, $300 million of the 2023 SPL Senior Notes were redeemed. As of September 30, 2022, the entire amount of the 2023 SPL Senior Notes was classified as short-term debt.

(2)Subsequent to September 30, 2022 and through October 31, 2022, we executed bond repurchases totaling $221 million, inclusive of CCH’s Senior Secured Notes due 2027, 2029 and 2039 on the open market, which are classified as current portion of long-term debt as of September 30, 2022 net of discount and debt issuance costs of $2 million.

(3)These debt instruments are classified as short-term debt.

(4)The redemption of these notes was financed with borrowings under the Cheniere Revolving Credit Facility, which is a long-term debt instrument. Therefore, the 2045 Cheniere Convertible Senior Notes were classified as long-term debt as of December 31, 2021. See Convertible Notes section below for further discussion of the redemption.

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, 2022 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities		CCH Credit Facility (1)		CCH Working Capital Facility (1)		Cheniere Revolving Credit Facility
Total facility size	$	1,200	$	750	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	363		—		—		218		—
Available commitment	$	837	$	750	$	3,260	$	1,282	$	1,250
Priority ranking	Senior secured		Senior secured		Senior secured		Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%		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 applicable margin		LIBOR plus 1.250% - 2.375% or base rate plus 0.250% - 1.375% (2)
Commitment fees on undrawn balance	0.15%		0.49%		0.53%		0.18%		0.25%
Maturity date	March 19, 2025		May 29, 2024		(3)		June 15, 2027		October 28, 2026

(1)In June 2022, CCH amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.

(2)This facility was amended in 2021 to establish a SOFR-indexed replacement rate for LIBOR.

(3)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, including interest expense related to our convertible notes, consisted of the following (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Interest cost on convertible notes:
Interest per contractual rate	$	—	$	6	$	—	$	29
Amortization of debt discount and debt issuance costs	—		1		—		9
Total interest cost related to convertible notes	—		7		—		38
Interest cost on debt and finance leases excluding convertible notes	376		391		1,118		1,178
Total interest cost	376		398		1,118		1,216
Capitalized interest	(22)		(34)		(58)		(128)
Total interest expense, net of capitalized interest	$	354	$	364	$	1,060	$	1,088

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	September 30, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	24,020	$	22,461	$	24,550	$	26,725
Senior notes — Level 3 (2)	3,253		2,916		3,253		3,693
2045 Cheniere Convertible Senior Notes — Level 1 (3)	—		—		625		526

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 

(3)The Level 1 estimated fair value was based on unadjusted quoted prices in active markets for identical liabilities that we had the ability to access at the measurement date.

XML

Leases (Tables)

9 Months Ended

Sep. 30, 2022

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	2022		2021
Right-of-use assets—Operating	Operating lease assets	$	2,795	$	2,102
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	70		50
Total right-of-use assets		$	2,865	$	2,152
Current operating lease liabilities	Current operating lease liabilities	$	669	$	535
Current finance lease liabilities	Other current liabilities	6		2
Non-current operating lease liabilities	Operating lease liabilities	2,082		1,541
Non-current finance lease liabilities	Finance lease liabilities	75		57
Total lease liabilities		$	2,832	$	2,135

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,
		2022		2021		2022		2021
Operating lease cost (a)	Operating costs and expenses (1)	$	213	$	145	$	604	$	441
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	1		—		3		2
Interest on lease liabilities	Interest expense, net of capitalized interest	2		2		7		7
Total lease cost		$	216	$	147	$	614	$	450
(a) Included in operating lease cost:
Short-term lease costs		$	16	$	22	$	80	$	103
Variable lease costs		7		7		16		20

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

Schedule of Maturity of Lease Liabilities

Future annual minimum lease payments for operating and finance leases as of September 30, 2022 are as follows (in millions): 

Years Ending December 31,	Operating Leases (1)		Finance Leases
2022	$	193	$	4
2023	736		15
2024	651		15
2025	474		15
2026	341		15
Thereafter	763		122
Total lease payments	3,158		186
Less: Interest	(407)		(105)
Present value of lease liabilities	$	2,751	$	81

(1)Does not include approximately $2.9 billion of legally binding minimum payments primarily for vessel charters contracted for as of September 30, 2022 which will commence in future periods with fixed minimum lease terms of up to 10 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, 2022		December 31, 2021
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.1	13.2	5.6	16.7
Weighted-average discount rate (1)	4.0%	14.6%	3.6%	16.2%

(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,
	2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	524	$	331
Operating cash flows from finance leases	6		7
Right-of-use assets obtained in exchange for operating lease liabilities	1,139		1,575
Right-of-use assets obtained in exchange for finance lease liabilities	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,
	2022		2021		2022		2021
Fixed income	$	122	$	17	$	188	$	28
Variable income	12		15		37		21
Total sublease income	$	134	$	32	$	225	$	49

XML

Revenues (Tables)

9 Months Ended

Sep. 30, 2022

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,
	2022		2021		2022		2021
Revenues from contracts with customers
LNG revenues	$	8,422	$	4,170	$	23,774	$	10,505
Regasification revenues	455		68		591		202
Other revenues	27		22		78		66
Total revenues from contracts with customers	8,904		4,260		24,443		10,773
Net derivative loss (1)	(186)		(1,092)		(325)		(1,515)
Other (2)	134		32		225		49
Total revenues	$	8,852	$	3,200	$	24,343	$	9,307

(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 contract assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	September 30,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	553	$	140

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, 2022
Deferred revenue, beginning of period	$	194
Cash received but not yet recognized in revenue	284
Revenue recognized from prior year end deferral	(194)
Deferred revenue, end of period	$	284

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, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	113.5	9	$	107.1	9
Regasification revenues	1.6		2	1.9		4
Total revenues	$	115.1		$	109.0

(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.

XML

Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2022

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
LNG Revenues
Natural Gas Transportation and Storage Agreements	$	—	$	—	$	4	$	—
Other revenues
Operation and Maintenance Services Agreements	3		2		5		5
Cost of sales
Natural Gas Supply Agreements (a) (1)	—		53		—		124
Natural Gas Transportation and Storage Agreements	—		—		1		1
Total cost of sales	—		53		1		125
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements	18		14		45		41
(a) Included in cost of sales:
Liquefaction Supply Derivative gain (1)	—		6		—		13

(1)Includes amounts recorded related to natural gas supply contracts that SPL and CCL had with related parties. These agreements ceased to be considered related party agreements during 2021, as discussed below.

XML

Net Loss Per Share Attributable to Common Stockholders (Tables)

9 Months Ended

Sep. 30, 2022

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,
	2022		2021		2022		2021
Net loss attributable to common stockholders	$	(2,385)	$	(1,084)	$	(2,509)	$	(1,020)
Weighted average common shares outstanding:
Basic	249.9		253.6		252.5		253.3
Dilutive unvested stock	—		—		—		—
Diluted	249.9		253.6		252.5		253.3
Net loss per share attributable to common stockholders—basic and diluted	$	(9.54)	$	(4.27)	$	(9.94)	$	(4.03)
Dividends paid per common share	$	0.33	$	—	$	0.99	$	—

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

Potentially dilutive securities that were not included in the diluted net 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,
	2022	2021	2022	2021
Unvested stock (1)	2.5	1.8	2.3	1.6
2045 Cheniere Convertible Senior Notes (2)	—	4.5	0.2	4.5
Total potentially dilutive common shares	2.5	6.3	2.5	6.1

(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 dates.

(2)As described in Note 9—Debt, 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 shareholders during the 2022 period. See Note 1—Nature of Operations and Basis of Presentation for further discussion of our adoption of ASU 2020-06.

XML

Stock Repurchase Programs (Tables)

9 Months Ended

Sep. 30, 2022

Equity [Abstract]

Schedule of Share Repurchases Under the Share Repurchase Program

The following table presents information with respect to repurchases of common stock (in millions, except per share data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Aggregate common stock repurchased	0.60		0.08		4.97		0.08
Weighted average price paid per share	$	125.34	$	83.97	$	128.73	$	83.97
Total amount paid	$	75	$	6	$	640	$	6

XML

Customer Concentration (Tables)

9 Months Ended

Sep. 30, 2022

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	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,
	2022	2021	2022	2021	2022	2021
Customer A	*	12%	*	14%	*	10%
Customer B	*	15%	*	13%	*	*
Customer C	*	11%	*	11%	*	*
Customer D	*	11%	*	*	*	*
Customer E	*	*	*	*	16%	—

* Less than 10%

XML

Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2022

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,
	2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	891	$	902
Cash paid for income taxes, net of refunds	28		2
Non-cash investing activity:
Transfers of property, plant and equipment in exchange for other non-current assets	17		—
Non-cash financing activity:
Declared and accrued dividends on common stock	103		85

XML

Nature of Operations and Basis of Presentation (Details) $ in Millions			9 Months Ended
	Jan. 05, 2022 USD ($)	Jan. 01, 2022 USD ($)	Sep. 30, 2022 USD ($) milliontonnes / yr item mi unit trains	Dec. 31, 2021 USD ($)
Nature of Operations and Basis of Presentation [Line Items]
Number Of Natural Gas Liquefaction And Export Facilities | unit			2
Accumulated deficit			$ (8,880)	$ (6,021)
2045 Cheniere Convertible Senior Notes [Member]
Nature of Operations and Basis of Presentation [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.25%
Repayments of Debt	$ 625
Accounting Standards Update 2020-06 | 2045 Cheniere Convertible Senior Notes [Member] | Cumulative Effect, Period of Adoption, Adjustment
Nature of Operations and Basis of Presentation [Line Items]
Equity component of convertible notes		$ 194
Convertible Notes Payable		189
Accumulated deficit		5
Accounting Standards Update 2020-06 | 2045 Cheniere Convertible Senior Notes [Member] | Additional Paid-in Capital | Cumulative Effect, Period of Adoption, Adjustment
Nature of Operations and Basis of Presentation [Line Items]
Tax effect of ASU 2020-06 adoption		41
Accounting Standards Update 2020-06 | 2045 Cheniere Convertible Senior Notes [Member] | Accumulated Deficit | Cumulative Effect, Period of Adoption, Adjustment
Nature of Operations and Basis of Presentation [Line Items]
Tax effect of ASU 2020-06 adoption		$ 1
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains Operating | trains			6
Total Production Capability | milliontonnes / yr			30
Number of LNG Storage Tanks | unit			5
Number of Marine Berths Operating | item			3
Creole Trail Pipeline [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length of Natural Gas Pipeline | mi			94
Corpus Christi LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains Operating | trains			3
Total Production Capability | milliontonnes / yr			15
Number of LNG Storage Tanks | unit			3
Number of Marine Berths Operating | item			2
Corpus Christi Stage 3 Project | Maximum [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains			7
Corpus Christi Stage 3 Project | Minimum [Member]
Nature of Operations and Basis of Presentation [Line Items]
Total Production Capability | milliontonnes / yr			10
Corpus Christi Pipeline [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length of Natural Gas Pipeline | mi			21.5
Corpus Christi LNG Terminal Expansion [Member]
Nature of Operations and Basis of Presentation [Line Items]
Total Production Capability | milliontonnes / yr			3
Number of Liquefaction LNG Trains | trains			2
CQP [Member]
Nature of Operations and Basis of Presentation [Line Items]
General Partner ownership percentage			100.00%
Limited Partner ownership percentage			48.60%

XML

Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Sep. 30, 2022		Dec. 31, 2021
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 834	[1]	$ 413
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	195		98
CCL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	202		44
Cash held by our subsidiaries restricted to Cheniere [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 437		$ 271

[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, 2022, total assets and liabilities of CQP were $19.9 billion and $24.3 billion, respectively, including $1.0 billion of cash and cash equivalents and $0.2 billion of restricted cash and cash equivalents.

XML

Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Accounts and Other Receivables [Line Items]
Other receivables	$ 145	$ 64
Total trade and other receivables, net of current expected credit losses	1,834	1,506
SPL and CCL
Accounts and Other Receivables [Line Items]
Trade receivables	1,070	802
Cheniere Marketing
Accounts and Other Receivables [Line Items]
Trade receivables	$ 619	$ 640

XML

Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Inventory [Line Items]
Inventory	$ 1,129	$ 706
LNG in-transit [Member]
Inventory [Line Items]
Inventory	652	312
LNG [Member]
Inventory [Line Items]
Inventory	230	153
Materials [Member]
Inventory [Line Items]
Inventory	189	174
Natural gas [Member]
Inventory [Line Items]
Inventory	55	64
Other [Member]
Inventory [Line Items]
Inventory	$ 3	$ 3

XML

Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 30,904	$ 30,288
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(4,715)	(3,912)
Property, plant and equipment, net of accumulated depreciation	30,786	30,184
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	33,186	30,660
LNG site and related costs [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	447	441
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,868	2,995
Fixed assets and other [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(191)	(176)
Property, plant and equipment, net of accumulated depreciation	48	54
Computer and office equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	31	25
Furniture and fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19	20
Computer software [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	123	120
Leasehold improvements [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	46	45
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1	1
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19	19
Tug vessels under finance lease [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	83	60
Accumulated depreciation	(13)	(10)
Property, plant and equipment, net of accumulated depreciation	$ 70	$ 50

XML

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, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 278	$ 257	$ 822	$ 749
Offsets to LNG terminal costs	[1]	$ 0	$ 0	$ 204	$ 227

[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.

XML

Derivative Instruments - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2022	Dec. 31, 2021
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	25 years
Financial Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	3 years
LNG Trading Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	2 years
FX Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount	$ 597	$ 762
FX Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	1 year

XML

Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ (40)
Interest Rate 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
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	(40)
Interest Rate 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
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(13,916)	(4,038)
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	(106)	7
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	(5)	(9)
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	(13,805)	(4,036)
LNG Trading Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(127)	(400)
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	(14)	(22)
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	(113)	(378)
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	51	12
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	51	12
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

XML

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	9 Months Ended
	Sep. 30, 2022 USD ($)
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Net Fair Value Liabilities	$ (13,805,000,000)
Valuation, Market Approach [Member] | Minimum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	(2.495)	[1]
Valuation, Market Approach [Member] | Maximum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	0.677	[1]
Valuation, Market Approach [Member] | Weighted Average [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	$ (0.090)	[1]
Valuation Technique, Option Pricing Model [Member] | Minimum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	89.00%	[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	943.00%	[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	197.00%	[1],[2]

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

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

XML

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, 2022	Sep. 30, 2021	[1]	Sep. 30, 2022	Sep. 30, 2021	[1]
Fair Value, Assets (Liabilities) Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (8,462)	$ (389)		$ (4,036)	$ 241
Realized and mark-to-market losses:
Included in cost of sales		(5,668)	(2,982)		(8,825)	(2,898)
Purchases and settlements:
Purchases		4	5		(1,390)	(657)
Settlements		322	75		446	23
Transfers out of Level 3	[2]	(1)	0		0	0
Balance, end of period		(13,805)	(3,291)		(13,805)	(3,291)
Change in unrealized losses relating to instruments still held at end of period		$ (5,668)	$ (2,982)		$ (8,825)	$ (2,898)

[1] Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 12—Related Party Transactions.

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

XML

Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) $ in Billions	Sep. 30, 2022 USD ($) tbtu		Dec. 31, 2021 USD ($) tbtu
Interest Rate Derivatives [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	$ 0.0		$ 4.5
Weighted Average Fixed Interest Rate Paid	2.30%
Liquefaction Supply Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	13,357	[1]	11,238
LNG Trading Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	64		33

[1] Excludes notional amounts associated with extension options that were uncertain to be taken as of September 30, 2022.

XML

Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Interest Rate Derivatives [Member] | Interest rate derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 0	$ (2)	$ 2	$ (3)
LNG Trading Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	(237)	(1,098)	(454)	(1,539)
LNG Trading Derivatives [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	(4)	55	103	136
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	(3)	(4)	8	(3)
Liquefaction Supply Derivatives [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2],[3]	(5,508)	(2,444)	(10,008)	(2,848)
FX Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 54	$ 11	$ 121	$ 27

[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 derivative instruments that settle through physical delivery.

[3] Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 12—Related Party Transactions.

XML

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Sep. 30, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Current derivative assets		$ 131	$ 55
Derivative assets		46	69
Total derivative assets		177	124
Current derivative liabilities		(3,215)	(1,089)
Derivative liabilities		(10,954)	(3,501)
Total derivative liabilities		(14,169)	(4,590)
Derivative asset (liability), net		(13,992)	(4,466)
Current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets		131	55
Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		46	69
Current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities		(3,215)	(1,089)
Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(10,954)	(3,501)
Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		0	0
Total derivative liabilities		0	(40)
Derivative asset (liability), net		0	(40)
Interest Rate Derivatives [Member] | Current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets		0	0
Interest Rate Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		0	0
Interest Rate Derivatives [Member] | Current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities		0	(40)
Interest Rate Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		0	0
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[1]	96	107
Total derivative liabilities	[1]	(14,012)	(4,145)
Derivative asset (liability), net	[1]	(13,916)	(4,038)
Derivative, collateral posted by us		152	20
Liquefaction Supply Derivatives [Member] | Current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[1]	50	38
Liquefaction Supply Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	46	69
Liquefaction Supply Derivatives [Member] | Current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities	[1]	(3,058)	(644)
Liquefaction Supply Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(10,954)	(3,501)
LNG Trading Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[2]	25	2
Total derivative liabilities	[2]	(152)	(402)
Derivative asset (liability), net	[2]	(127)	(400)
Derivative, collateral posted by us		115	745
LNG Trading Derivatives [Member] | Current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[2]	25	2
LNG Trading Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[2]	0	0
LNG Trading Derivatives [Member] | Current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities	[2]	(152)	(402)
LNG Trading Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[2]	0	0
FX Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		56	15
Total derivative liabilities		(5)	(3)
Derivative asset (liability), net		51	12
FX Derivatives [Member] | Current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets		56	15
FX Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		0	0
FX Derivatives [Member] | Current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities		(5)	(3)
FX Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		$ 0	$ 0

[1] Does not include collateral posted with counterparties by us of $152 million and $20 million as of September 30, 2022 and December 31, 2021, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

[2] Does not include collateral posted with counterparties by us of $115 million and $745 million, as of September 30, 2022 and December 31, 2021, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

XML

Derivative Instruments - Derivative Net Presentation on Consolidated Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 108	$ 155
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(12)	(48)
Derivative Assets (Liabilities), at Fair Value, Net	96	107
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(14,507)	(4,382)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	495	237
Derivative Assets (Liabilities), at Fair Value, Net	(14,012)	(4,145)
LNG Trading Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	35	10
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(10)	(8)
Derivative Assets (Liabilities), at Fair Value, Net	25	2
LNG Trading Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(165)	(551)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	13	149
Derivative Assets (Liabilities), at Fair Value, Net	(152)	(402)
FX Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	57	48
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(1)	(33)
Derivative Assets (Liabilities), at Fair Value, Net	56	15
FX Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(5)	(10)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	0	7
Derivative Assets (Liabilities), at Fair Value, Net	$ (5)	$ (3)

XML

Non-Controlling Interest and Variable Interest Entity (Details) - USD ($) shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2022		Dec. 31, 2021
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 2,504	[1]	$ 1,404
Trade and other receivables, net of current expected credit losses	1,834		1,506
Contract assets	392		5
Other current assets	115		202
Total current assets	7,206		5,056
Property, plant and equipment, net of accumulated depreciation	30,904		30,288
Other non-current assets, net	514		462
Total assets	43,642	[1]	39,258
Accrued liabilities	3,108		2,299
Current debt, net of discount and debt issuance costs	1,717		366
Other current liabilities	50		94
Total current liabilities	9,375		4,693
Long-term debt, net of premium, discount and debt issuance costs	25,325		29,449
Other non-current liabilities	$ 161		50
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	$ 988		876
Restricted cash and cash equivalents	195		98
Trade and other receivables, net of current expected credit losses	805		580
Contract assets	387		0
Other current assets	401		285
Total current assets	2,776		1,839
Property, plant and equipment, net of accumulated depreciation	16,827		16,830
Other non-current assets, net	300		316
Total assets	19,903		18,985
Accrued liabilities	1,665		1,077
Current debt, net of discount and debt issuance costs	1,498		0
Other current liabilities	1,363		200
Total current liabilities	4,526		1,277
Long-term debt, net of premium, discount and debt issuance costs	15,699		17,177
Other non-current liabilities	4,081		100
Total liabilities	$ 24,306		$ 18,554

[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, 2022, total assets and liabilities of CQP were $19.9 billion and $24.3 billion, respectively, including $1.0 billion of cash and cash equivalents and $0.2 billion of restricted cash and cash equivalents.

XML

Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Accrued Liabilities, Current [Abstract]
Natural gas purchases	$ 2,112	$ 1,323
Derivative settlements	98	329
Interest costs and related debt fees	345	214
LNG terminals and related pipeline costs	254	144
Compensation and benefits	109	180
LNG inventory	8	34
Accrued dividends	101	0
Other accrued liabilities	81	75
Total accrued liabilities	$ 3,108	$ 2,299

XML

Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions			1 Months Ended
		Jan. 05, 2022	Oct. 31, 2022	Sep. 30, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				$ 27,273	$ 30,406
Current portion of long-term debt				(219)	(117)
Short-term Debt				(1,498)	(250)
Unamortized premium, discount and debt issuance costs, net				(231)	(590)
Total Long-Term Debt, Net of Premium, Discount and Debt Issuance Costs				25,325	29,449
SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				13,132	13,132
2023 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[1]			$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage				5.625%
2023 SPL Senior Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Debt			$ 300
2024 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				5.75%
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				$ 1,282	1,282
2037 SPL Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.27%
SPL Working Capital 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				4,200	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%
CQP Credit Facilities [Member]
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				8,441	8,471
2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				$ 1,250	1,250
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	[2]			$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage				5.875%
CCH Senior Notes due 2027, 2029 and 2039 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net			(2)
Repayments of Debt			$ 221
2027 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[2]			$ 1,500	1,500
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	[2]			$ 1,492	1,500
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]			$ 2,699	2,721
2039 CCH Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				3.72%
CCH Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				$ 0	1,728
CCH Working Capital Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[3]			0	250
Short-term Debt	[4]			0
2028 Cheniere Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				$ 1,500	2,000
Debt Instrument, Interest Rate, Stated Percentage				4.625%
2045 Cheniere Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[5]			$ 0	625
Debt Instrument, Interest Rate, Stated Percentage				4.25%
Repayments of Debt		$ 625
Cheniere Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				$ 0	0
Cheniere Marketing Trade Finance Facilities [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[3]			0	0
SPL [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				13,132	13,132
CQP [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				4,200	4,200
CCH [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				8,441	10,449
Cheniere [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount				$ 1,500	$ 2,625

[1] In October 2022, $300 million of the 2023 SPL Senior Notes were redeemed. As of September 30, 2022, the entire amount of the 2023 SPL Senior Notes was classified as short-term debt.

[2] Subsequent to September 30, 2022 and through October 31, 2022, we executed bond repurchases totaling $221 million, inclusive of CCH’s Senior Secured Notes due 2027, 2029 and 2039 on the open market, which are classified as current portion of long-term debt as of September 30, 2022 net of discount and debt issuance costs of $2 million.

[3] These debt instruments are classified as short-term debt.

[4] In June 2022, CCH amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.

[5] The redemption of these notes was financed with borrowings under the Cheniere Revolving Credit Facility, which is a long-term debt instrument. Therefore, the 2045 Cheniere Convertible Senior Notes were classified as long-term debt as of December 31, 2021. See Convertible Notes section below for further discussion of the redemption.

XML

Debt - Credit Facilities Table (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
		Jun. 30, 2022	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Line of Credit Facility [Line Items]
Outstanding balance - current			$ 1,498		$ 1,498		$ 250
Debt modification and extinguishment costs			3	$ (36)	(43)	$ (95)
SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size			1,200		1,200
Outstanding balance			0		0
Letters of credit issued			363		363
Available commitment			837		$ 837
Debt Instrument, Description of Variable Rate Basis					LIBOR or base rate
Line of Credit Facility, Commitment Fee Percentage					0.15%
Maturity date					Mar. 19, 2025
SPL Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					1.125%
SPL Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					1.75%
SPL Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					0.125%
SPL Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					0.75%
CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Total facility size			750		$ 750
Outstanding balance			0		0
Letters of credit issued			0		0
Available commitment			750		$ 750
Debt Instrument, Description of Variable Rate Basis					LIBOR or base rate
Line of Credit Facility, Commitment Fee Percentage					0.49%
Maturity date					May 29, 2024
CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					1.25%
CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					2.125%
CQP Credit Facilities [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					0.25%
CQP Credit Facilities [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					1.125%
CCH Credit Facility and CCH Working Capital Facility
Line of Credit Facility [Line Items]
Debt modification and extinguishment costs		$ 20
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	[1]		3,260		$ 3,260
Outstanding balance	[1]		0		0
Letters of credit issued	[1]		0		0
Available commitment	[1]		3,260		$ 3,260
Debt Instrument, Description of Variable Rate Basis					SOFR or base rate
Line of Credit Facility, Commitment Fee Percentage					0.53%
Incremental commitments		3,700
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] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	[1]				0.10%
Debt Instrument, Basis Spread on Variable Rate	[1]				1.50%
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]				0.50%
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	[1]		1,500		$ 1,500
Outstanding balance - current	[1]		0		0
Letters of credit issued	[1]		218		218
Available commitment	[1]		1,282		$ 1,282
Debt Instrument, Description of Variable Rate Basis					SOFR or base rate
Line of Credit Facility, Commitment Fee Percentage	[1]				0.18%
Maturity date	[1]				Jun. 15, 2027
Incremental commitments		$ 300
CCH Working Capital Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	[1]				0.10%
CCH Working Capital Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]				1.00%
CCH Working Capital Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]				1.50%
Cheniere Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size			1,250		$ 1,250
Outstanding balance			0		0
Letters of credit issued			0		0
Available commitment			$ 1,250		$ 1,250
Debt Instrument, Description of Variable Rate Basis					LIBOR or base rate
Line of Credit Facility, Commitment Fee Percentage					0.25%
Maturity date					Oct. 28, 2026
Cheniere Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]				1.25%
Cheniere Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]				2.375%
Cheniere Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]				0.25%
Cheniere Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]				1.375%

[1] In June 2022, CCH amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.

[2] This facility was amended in 2021 to establish a SOFR-indexed replacement rate for LIBOR.

XML

Debt - Convertible Notes (Details) $ in Millions		3 Months Ended		9 Months Ended
	Jan. 05, 2022 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2022 USD ($) unit	Sep. 30, 2021 USD ($)
Debt Instrument [Line Items]
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio | unit				1.25
Debt modification and extinguishment costs		$ 3	$ (36)	$ (43)	$ (95)
2045 Cheniere Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of Debt	$ 625
Debt modification and extinguishment costs				$ 16

XML

Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Debt Instrument [Line Items]
Amortization of debt discount and debt issuance costs			$ 43	$ 57
Total interest cost	$ 376	$ 398	1,118	1,216
Capitalized interest	(22)	(34)	(58)	(128)
Total interest expense, net of capitalized interest	354	364	1,060	1,088
Convertible Debt [Member]
Debt Instrument [Line Items]
Interest per contractual rate	0	6	0	29
Amortization of debt discount and debt issuance costs	0	1	0	9
Total interest cost	0	7	0	38
Debt and Finance Leases Excluding Convertible Debt [Member]
Debt Instrument [Line Items]
Total interest cost	$ 376	$ 391	$ 1,118	$ 1,178

XML

Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2022	Dec. 31, 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 27,273	$ 30,406
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	24,020	24,550
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	3,253	3,253
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	22,461	26,725
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]	2,916	3,693
2045 Cheniere Convertible Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[3]	0	625
2045 Cheniere Convertible Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[4]	0	625
2045 Cheniere Convertible Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible Debt, Estimated Fair Value	[4]	$ 0	$ 526

[1] The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

[2] The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 

[3] The redemption of these notes was financed with borrowings under the Cheniere Revolving Credit Facility, which is a long-term debt instrument. Therefore, the 2045 Cheniere Convertible Senior Notes were classified as long-term debt as of December 31, 2021. See Convertible Notes section below for further discussion of the redemption.

[4] The Level 1 estimated fair value was based on unadjusted quoted prices in active markets for identical liabilities that we had the ability to access at the measurement date.

XML

Leases - Balance Sheet Location Table (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Right-of-use assets—Operating	$ 2,795	$ 2,102
Total right-of-use assets	2,865	2,152
Current operating lease liabilities	669	535
Non-current operating lease liabilities	2,082	1,541
Non-current finance lease liabilities	75	57
Total lease liabilities	2,832	2,135
Operating lease assets, net [Member]
Lessee, Lease, Description [Line Items]
Right-of-use assets—Operating	2,795	2,102
Property, plant and equipment, net of accumulated depreciation [Member]
Lessee, Lease, Description [Line Items]
Right-of-use assets—Financing	70	50
Current operating lease liabilities [Member]
Lessee, Lease, Description [Line Items]
Current operating lease liabilities	669	535
Other current liabilities [Member]
Lessee, Lease, Description [Line Items]
Current finance lease liabilities	6	2
Operating lease liabilities [Member]
Lessee, Lease, Description [Line Items]
Non-current operating lease liabilities	2,082	1,541
Finance lease liabilities [Member]
Lessee, Lease, Description [Line Items]
Non-current finance lease liabilities	$ 75	$ 57

XML

Leases - Income Statement Location Table (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Finance lease cost:
Total lease cost		$ 216	$ 147	$ 614	$ 450
Operating costs and expenses [Member]
Lessee, Lease, Description [Line Items]
Operating lease cost	[1]	213	145	604	441
Finance lease cost:
Short-term lease costs		16	22	80	103
Variable lease costs		7	7	16	20
Depreciation and amortization expense [Member]
Finance lease cost:
Amortization of right-of-use assets		1	0	3	2
Interest expense, net of capitalized interest [Member]
Finance lease cost:
Interest on lease liabilities		$ 2	$ 2	$ 7	$ 7

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

XML

Leases - Future Minimum Payments Table (Details) $ in Millions	Sep. 30, 2022 USD ($)
Operating Leases, Future Minimum Payments
2022	$ 193	[1]
2023	736	[1]
2024	651	[1]
2025	474	[1]
2026	341	[1]
Thereafter	763	[1]
Total lease payments	3,158	[1]
Less: Interest	(407)	[1]
Present value of lease liabilities	2,751	[1]
Finance Leases, Future Minimum Payments
2022	4
2023	15
2024	15
2025	15
2026	15
Thereafter	122
Total lease payments	186
Less: Interest	(105)
Present value of lease liabilities	81
Operating Lease, Lease Not yet Commenced, Payments Due	$ 2,900
Maximum [Member]
Finance Leases, Future Minimum Payments
Operating Leases, Lease Not yet Commenced, Term of Contract	10 years

[1] Does not include approximately $2.9 billion of legally binding minimum payments primarily for vessel charters contracted for as of September 30, 2022 which will commence in future periods with fixed minimum lease terms of up to 10 years.

XML

Leases - Other Quantitative Information (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Operating Leases
Weighted-average remaining lease term		6 years 1 month 6 days		5 years 7 months 6 days
Weighted-average discount rate	[1]	4.00%		3.60%
Finance Leases
Weighted-average remaining lease term		13 years 2 months 12 days		16 years 8 months 12 days
Weighted-average discount rate	[1]	14.60%		16.20%
Operating cash flows from operating leases		$ 524	$ 331
Operating cash flows from finance leases		6	7
Right-of-use assets obtained in exchange for operating lease liabilities		1,139	1,575
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability		$ 23	$ 0

[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.

XML

Leases - Subleases (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Leases [Abstract]
Sublease payments to be received	$ 534		$ 534		$ 15
Sublease Income, Fixed	122	$ 17	188	$ 28
Sublease Income, Variable	12	15	37	21
Sublease Income, Total	$ 134	$ 32	$ 225	$ 49

XML

Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 8,904	$ 4,260	$ 24,443	$ 10,773
Net derivative loss	[1]	(186)	(1,092)	(325)	(1,515)
Other revenues	[2]	134	32	225	49
Total revenues		8,852	3,200	24,343	9,307
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		8,422	4,170	23,774	10,505
Total revenues		8,236	3,078	23,449	8,990
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		455	68	591	202
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		27	22	78	66
Total revenues		$ 161	$ 54	$ 303	$ 115

[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.

XML

Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 553	$ 140
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	194
Cash received but not yet recognized in revenue	284
Revenue recognized from prior year end deferral	(194)
Deferred revenue, end of period	$ 284

XML

Revenues - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		3 Months Ended		9 Months Ended
		Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price						$ 109.0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 115.1		$ 115.1
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		76.00%	61.00%	72.00%	56.00%
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price						$ 107.1
Weighted Average Recognition Timing	[1]					9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 113.5		$ 113.5
Weighted Average Recognition Timing	[1]	9 years		9 years
Regasification [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		1.00%	5.00%	2.00%	5.00%
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price						$ 1.9
Weighted Average Recognition Timing	[1]					4 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 1.6		$ 1.6
Weighted Average Recognition Timing	[1]	2 years		2 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.

XML

Revenues - Termination Agreement with Chevron (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Sep. 30, 2022	Dec. 31, 2021
Revenue from External Customer [Line Items]
Contract assets		$ 392	$ 5
Chevron U.S.A. Inc.
Revenue from External Customer [Line Items]
Contract Termination Fee	$ 765
Chevron U.S.A. Inc. | Terminated commitments [Member]
Revenue from External Customer [Line Items]
Contract Termination Fee	796
Chevron U.S.A. Inc. | Gain (Loss) on extinguishment of obligations [Member]
Revenue from External Customer [Line Items]
Contract Termination Fee	(31)
Chevron U.S.A. Inc. | Regasification [Member]
Revenue from External Customer [Line Items]
Revenue Performance Obligation Fixed Consideration	$ 125
Contract assets		$ 387

XML

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Related Party Transaction [Line Items]
Revenues		$ 8,852	$ 3,200	$ 24,343	$ 9,307
Cost of sales		11,073	4,868	24,161	8,408
Operating and maintenance expense		419	350	1,227	1,057
LNG [Member]
Related Party Transaction [Line Items]
Revenues		8,236	3,078	23,449	8,990
Other [Member]
Related Party Transaction [Line Items]
Revenues		161	54	303	115
Natural Gas Supply, Transportation And Storage Service Agreements [Member]
Related Party Transaction [Line Items]
Cost of sales		0	53	1	125
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Cost of sales		0	0	1	1
Operating and maintenance expense		18	14	45	41
Natural Gas Transportation and Storage Agreements [Member] | LNG [Member]
Related Party Transaction [Line Items]
Revenues		0	0	4	0
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales	[1]	0	53	0	124
Natural Gas Supply Agreement [Member] | Liquefaction Supply Derivatives [Member]
Related Party Transaction [Line Items]
Liquefaction Supply Derivative gain	[1]	0	6	0	13
Operation and Maintenance Agreement [Member] | Other [Member]
Related Party Transaction [Line Items]
Revenues		$ 3	$ 2	$ 5	$ 5

[1] Includes amounts recorded related to natural gas supply contracts that SPL and CCL had with related parties. These agreements ceased to be considered related party agreements during 2021, as discussed below.

XML

Related Party Transactions - Narrative (Details) $ / shares in Units, shares in Thousands, $ in Millions		3 Months Ended		9 Months Ended
	Jun. 30, 2022 USD ($) $ / shares shares	Sep. 30, 2022 USD ($) $ / shares shares	Sep. 30, 2021 USD ($) $ / shares shares	Sep. 30, 2022 USD ($) unit $ / shares shares	Sep. 30, 2021 USD ($) $ / shares shares	Dec. 31, 2021 USD ($)
Related Party Transaction [Line Items]
Accrued liabilities		$ 3,108		$ 3,108		$ 2,299
Trade and other receivables, net of current expected credit losses		1,834		1,834		1,506
Total amount paid		$ 75	$ 6	$ 640	$ 6
Aggregate common stock repurchased | shares		600	80	4,970	80
Weighted average price paid per share | $ / shares		$ 125.34	$ 83.97	$ 128.73	$ 83.97
Midship Holdings LLC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Other than Temporary Impairment		$ 67
Equity method investments		$ 11		$ 11
ADCC Pipeline, LLC [Member]
Related Party Transaction [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent		30.00%		30.00%
Length of Natural Gas Pipeline | unit				42
Maximum [Member] | ADCC Pipeline, LLC [Member]
Related Party Transaction [Line Items]
Funding Commitment				$ 93
Icahn Share Repurchase Agreement
Related Party Transaction [Line Items]
Total amount paid	$ 350
Aggregate common stock repurchased | shares	2,680
Weighted average price paid per share | $ / shares	$ 130.52
Sabine Pass Liquefaction LLC and Cheniere Creole Trail Pipeline LP [Member] | Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Accrued liabilities		$ 8		$ 8		4
Sabine Pass Liquefaction LLC and Cheniere Creole Trail Pipeline LP [Member] | Natural Gas Transportation and Storage Agreements [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term				10 years
CCL [Member] | Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term				10 years
Accrued liabilities		1		$ 1		1
CCL [Member] | Natural Gas Transportation and Storage Agreements [Member] | ADCC Pipeline, LLC [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term				20 years
Cheniere LNG O&M Services, LLC [Member] | Operation and Maintenance Agreement [Member]
Related Party Transaction [Line Items]
Trade and other receivables, net of current expected credit losses		$ 1		$ 1		$ 2

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Income Tax Disclosure [Abstract]
Income tax benefit	$ 752	$ 1,860	$ 762	$ 1,864
Effective Income Tax Rate	22.10%	67.00%	23.30%	79.70%

XML

Net Loss Per Share Attributable to Common Stockholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended						9 Months Ended
		Sep. 12, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2022	Sep. 30, 2021
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net loss attributable to common stockholders			$ (2,385)	$ 741	$ (865)	$ (1,084)	$ (329)	$ 393	$ (2,509)	$ (1,020)
Weighted average number of common shares outstanding, basic			249.9			253.6			252.5	253.3
Dilutive Unvested Stock			0.0			0.0			0.0	0.0
Weighted Average Number of Shares Outstanding, Diluted			249.9			253.6			252.5	253.3
Net loss per share attributable to common stockholders—basic	[1]		$ (9.54)			$ (4.27)			$ (9.94)	$ (4.03)
Net loss per share attributable to common stockholders—diluted	[1]		(9.54)			(4.27)			(9.94)	(4.03)
Common Stock, Dividends, Per Share, Declared		$ 0.395	$ 0.33			$ 0			$ 0.99	$ 0
Antidilutive securities excluded from computation of earnings per share			2.5			6.3			2.5	6.1
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]		2.5			1.8			2.3	1.6
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			4.5			0.2	4.5

[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.

[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 dates.

[3] As described in Note 9—Debt, 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 shareholders during the 2022 period. See Note 1—Nature of Operations and Basis of Presentation for further discussion of our adoption of ASU 2020-06.

XML

Stock Repurchase Programs - Narrative (Details) - USD ($) $ in Millions		9 Months Ended
	Sep. 12, 2022	Sep. 30, 2021	Oct. 01, 2022	Sep. 30, 2022
Share Repurchases [Line Items]
Stock Repurchase Program, Authorized Amount		$ 1,000.0
Stock Repurchase Program, Period in Force		3 years
Stock Repurchase Program, Remaining Authorized Repurchase Amount				$ 358.0
Subsequent Event [Member]
Share Repurchases [Line Items]
Stock Repurchase Program, Remaining Authorized Repurchase Amount			$ 4,400.0
Subsequent Board Approved Increase [Member]
Share Repurchases [Line Items]
Stock Repurchase Program, Period in Force	3 years
Stock Repurchase Program, Increased in Authorized Amount	$ 4,000.0

XML

Stock Repurchase Programs - Schedule of Share Repurchases (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Equity [Abstract]
Aggregate common stock repurchased	600	80	4,970	80
Weighted average price paid per share	$ 125.34	$ 83.97	$ 128.73	$ 83.97
Total amount paid	$ 75	$ 6	$ 640	$ 6

XML

Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%		14.00%
Customer A [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage				10.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%		13.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%		11.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%
Customer E [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		16.00%

XML

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized	$ 891	$ 902
Cash paid for income taxes, net of refunds	28	2
Transfers of property, plant and equipment in exchange for other non-current assets	17	0
Dividends Payable	103	85
Balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities	$ 354	$ 234