Cheniere Energy, Inc. (Form: 10-Q, Received: 08/05/2021 06:06:41)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2021

☐ 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 July 30, 2021, the issuer had 253,606,918 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	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7
	Note 1—Nature of Operations and Basis of Presentation	7
	Note 2—Restricted Cash	8
	Note 3—Accounts and Other Receivables, N e t of Current Expected Credit Losses	8
	Note 4—Inventory	9
	Note 5—Property, Plant and Equipment, N e t of Accumulated Depreciation	9
	Note 6—Derivative Instruments	10
	Note 7—Other Non-Current Assets, Ne t	15
	Note 8—Non-Controlling Interest and Variable Interest Entity	16
	Note 9—Accrued Liabilities	16
	Note 10—Debt	17
	Note 11—Leases	21
	Note 12—Revenues from Contracts with Customers	23
	Note 13—Related Party Transactions	24
	Note 14—Income Taxes	25
	Note 15—Share-Based Compensation	26
	Note 16—Net Income per Share Attributable to Common Stockholders	26

	Note 17—Customer Concentration	27
	Note 18—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	50

Item 4.	Controls and Procedures	51

Part II. Other Information
Item 1.	Legal Proceedings	52

Item 1A.	Risk Factors	52

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52

Item 6.	Exhibits	53

	Signatures	54

DEFINITIONS

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

Common Industry and Other Terms


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
FERC						Federal Energy Regulatory Commission
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
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
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

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of June 30, 2021, 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, Cheniere Partners.

Unless the context requires otherwise, references to the “CCH Group” refer to CCH HoldCo II, CCH HoldCo I, CCH, CCL and CCP, collectively.

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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues
LNG revenues	$	2,913	$	2,295	$	5,912	$	4,863
Regasification revenues	67		68		134		135
Other revenues	37		39		61		113

Total revenues	3,017		2,402		6,107		5,111

Operating costs and expenses
Cost of sales (excluding items shown separately below)	2,154		803		3,540		1,527

Operating and maintenance expense	385		355		707		671
Development expense	2		1		3		5
Selling, general and administrative expense	73		73		154		154
Depreciation and amortization expense	258		233		494		466

Impairment expense and loss (gain) on disposal of assets	(1)		—		(1)		5


Total operating costs and expenses	2,871		1,465		4,897		2,828

Income from operations	146		937		1,210		2,283

Other income (expense)
Interest expense, net of capitalized interest	(368)		(407)		(724)		(819)
Loss on modification or extinguishment of debt	(4)		(43)		(59)		(44)
Interest rate derivative loss, net	(2)		(25)		(1)		(233)
Other income, net	4		5		10		14
Total other expense	(370)		(470)		(774)		(1,082)

Income (loss) before income taxes and non-controlling interest	(224)		467		436		1,201
Less: income tax provision (benefit)	(93)		63		(4)		194
Net income (loss)	(131)		404		440		1,007
Less: net income attributable to non-controlling interest	198		207		376		435
Net income (loss) attributable to common stockholders	$	(329)	$	197	$	64	$	572

Net income (loss) per share attributable to common stockholders—basic (1)	$	(1.30)	$	0.78	$	0.25	$	2.27
Net income (loss) per share attributable to common stockholders—diluted (1)	$	(1.30)	$	0.78	$	0.25	$	2.26

Weighted average number of common shares outstanding—basic	253.5		252.1		253.2		252.6
Weighted average number of common shares outstanding—diluted	253.5		252.4		254.7		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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (1)

(in millions, except share data)



	June 30,		December 31,
	2021		2020
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	1,806	$	1,628
Restricted cash	424		449
Accounts and other receivables, net of current expected credit losses	613		647

Inventory	363		292
Current derivative assets	178		32
Other current assets	281		121
Total current assets	3,665		3,169


Property, plant and equipment, net of accumulated depreciation	30,288		30,421
Operating lease assets	1,698		759

Derivative assets	96		376
Goodwill	77		77
Deferred tax assets	497		489
Other non-current assets, net	431		406
Total assets	$	36,752	$	35,697

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	83	$	35
Accrued liabilities	1,197		1,175

Current debt, net of discount and debt issuance costs	949		372
Deferred revenue	105		138
Current operating lease liabilities	365		161
Current derivative liabilities	822		313
Other current liabilities	5		2
Total current liabilities	3,526		2,196

Long-term debt, net of premium, discount and debt issuance costs	29,327		30,471
Operating lease liabilities	1,332		597
Finance lease liabilities	57		57

Derivative liabilities	145		151
Other non-current liabilities	8		7



Stockholders’ equity
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—		—
Common stock, $0.003 par value, 480.0 million shares authorized; 275.0 million shares and 273.1 million shares issued at June 30, 2021 and December 31, 2020, respectively	1		1



Treasury stock: 21.4 million shares and 20.8 million shares at June 30, 2021 and December 31, 2020, respectively, at cost	(915)		(872)
Additional paid-in-capital	4,337		4,273
Accumulated deficit	(3,529)		(3,593)
Total stockholders' deficit	(106)		(191)
Non-controlling interest	2,463		2,409
Total equity	2,357		2,218
Total liabilities and stockholders’ equity	$	36,752	$	35,697

(1) Amounts presented include balances held by our consolidated variable interest entity (“VIE”), Cheniere Partners, as further discussed in Note 8— Non-controlling Interest and Variable Interest Entity. As of June 30, 2021, total assets and liabilities of Cheniere Partners, which are included in our Consolidated Balance Sheets, were $18.9 billion and $18.5 billion, respectively, including $1.2 billion of cash and cash equivalents and $0.1 billion of restricted cash.

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in millions)

(unaudited)


Three and Six Months Ended June 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 restricted stock units and performance stock units	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 restricted stock units and performance stock units	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


Three and Six Months Ended June 30, 2020
	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, 2019	253.6	$	1	17.1	$	(674)	$	4,167	$	(3,508)	$	2,449	$	2,435
Vesting of restricted stock units and performance stock units	2.1	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		29		—		—		29
Issued shares withheld from employees related to share-based compensation, at cost	(0.7)	—		0.7	(39)		—		—		—		(39)
Shares repurchased, at cost	(2.9)	—		2.9	(155)		—		—		—		(155)
Net income attributable to non-controlling interest	—	—		—	—		—		—		228		228
Distributions to non-controlling interest	—	—		—	—		—		—		(154)		(154)
Net income	—	—		—	—		—		375		—		375
Balance at March 31, 2020	252.1	1		20.7	(868)		4,196		(3,133)		2,523		2,719
Vesting of restricted stock units and performance stock units	0.1	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		31		—		—		31
Issued shares withheld from employees related to share-based compensation, at cost	—	—		—	(2)		—		—		—		(2)

Net income attributable to non-controlling interest	—	—		—	—		—		—		207		207

Distributions and dividends to non-controlling interest	—	—		—	—		—		—		(156)		(156)
Net income	—	—		—	—		—		197		—		197
Balance at June 30, 2020	252.2	$	1	20.7	$	(870)	$	4,227	$	(2,936)	$	2,574	$	2,996

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)


	Six Months Ended June 30,

	2021		2020
Cash flows from operating activities
Net income	$	440	$	1,007
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	494		466
Share-based compensation expense	63		57
Non-cash interest expense	14		34
Amortization of debt issuance costs, premium and discount	40		70
Reduction of right-of-use assets	172		166
Loss on modification or extinguishment of debt	59		44
Total losses (gains) on derivatives, net	748		(361)
Net cash provided by (used for) settlement of derivative instruments	(111)		117
Impairment expense and loss (gain) on disposal of assets	(1)		5
Impairment expense and loss (income) on equity method investments	(8)		1
Deferred taxes	(7)		192
Repayment of paid-in-kind interest related to repurchase of convertible notes	(190)		—

Changes in operating assets and liabilities:
Accounts and other receivables, net of current expected credit losses	33		(155)

Inventory	(66)		104
Other current assets	(163)		(37)
Accounts payable and accrued liabilities	88		(369)

Deferred revenue	(33)		(138)
Operating lease liabilities	(173)		(145)

Other, net	(26)		(30)
Net cash provided by operating activities	1,373		1,028

Cash flows from investing activities
Property, plant and equipment	(440)		(983)
Proceeds from sale of fixed assets	68		—
Investment in equity method investment	—		(100)
Other	(11)		(7)
Net cash used in investing activities	(383)		(1,090)

Cash flows from financing activities
Proceeds from issuances of debt	2,184		2,597
Repayments of debt	(2,603)		(2,380)
Debt issuance and other financing costs	(20)		(59)
Debt modification or extinguishment costs	(41)		(40)

Distributions to non-controlling interest	(322)		(310)
Payments related to tax withholdings for share-based compensation	(43)		(41)
Repurchase of common stock	—		(155)
Other	8		—
Net cash used in financing activities	(837)		(388)

Net increase (decrease) in cash, cash equivalents and restricted cash	153		(450)
Cash, cash equivalents and restricted cash—beginning of period	2,077		2,994
Cash, cash equivalents and restricted cash—end of period	$	2,230	$	2,544

Balances per Consolidated Balance Sheets:


	June 30,
	2021
Cash and cash equivalents	$	1,806
Restricted cash	424

Total cash, cash equivalents and restricted cash	$	2,230

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

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 at Sabine Pass and Corpus Christi (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”).

Cheniere Partners owns the Sabine Pass LNG Terminal located in Cameron Parish, Louisiana, which has natural gas liquefaction facilities consisting of five operational natural gas liquefaction Trains and one additional Train under construction that is expected to be substantially completed in the first half of 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 two marine berths, with an additional marine berth that is under construction. Cheniere Partners also owns a 94-mile pipeline that interconnects the Sabine Pass LNG Terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through its subsidiary, CTPL. As of June 30, 2021, we owned 100% of the general partner interest and 48.6% of the limited partner interest in Cheniere Partners.

The Corpus Christi LNG Terminal is located near Corpus Christi, Texas. We currently operate three Trains, for a total production capacity of approximately 15 mtpa of LNG. We also own a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, the “CCL Project”) through our subsidiary CCP, as part of the CCH Group. The CCL Project also contains three LNG storage tanks and two marine berths.

Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG Terminal adjacent to the CCL Project (“Corpus Christi Stage 3”) through our subsidiary CCL Stage III, for up to seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG. We received approval from FERC in November 2019 to site, construct and operate the expansion project.

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 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. 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 final investment decision (“FID”).

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. 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, 2020.

Results of operations for the three and six months ended June 30, 2021 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2021.

Recent Accounting Standards

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 plan to adopt

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

this guidance on January 1, 2022 using the modified retrospective approach. Preliminarily, we anticipate the adoption of ASU 2020-06 will primarily result 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. We currently estimate that the reclassification of the $194 million equity component will result in an approximate $190 million increase in the carrying value of our 2045 Cheniere Convertible Senior Notes, with the difference primarily impacting retained earnings as of January 1, 2022. We continue to evaluate the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures. See Note 10—Debt for further discussion on the 2045 Cheniere Convertible Senior Notes.

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. We have various credit facilities and interest rate swaps indexed to LIBOR, as further described in Note 6—Derivative Instruments and Note 10—Debt. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

NOTE 2—RESTRICTED CASH

Restricted cash consists 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. As of June 30, 2021 and December 31, 2020, restricted cash consisted of the following (in millions):



	June 30,		December 31,
	2021		2020
Restricted cash
SPL Project	$	65	$	97

CCL Project	122		70
Cash held by our subsidiaries that is restricted to Cheniere	237		282
Total restricted cash	$	424	$	449

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.

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

As of June 30, 2021 and December 31, 2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions):



	June 30,		December 31,
	2021		2020
Trade receivables
SPL and CCL	$	405	$	482

Cheniere Marketing	123		113
Other accounts receivable, net of current expected credit losses	85		52

Total accounts and other receivables, net of current expected credit losses	$	613	$	647

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 4—INVENTORY

As of June 30, 2021 and December 31, 2020, inventory consisted of the following (in millions):



	June 30,		December 31,
	2021		2020
Materials	$	162	$	150
LNG in-transit	102		88
LNG	61		27
Natural gas	36		26
Other	2		1
Total inventory	$	363	$	292

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

As of June 30, 2021 and December 31, 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):



	June 30,		December 31,
	2021		2020
LNG terminal
LNG terminal and interconnecting pipeline facilities	$	30,598	$	27,475
LNG site and related costs	343		324
LNG terminal construction-in-process	2,650		5,378
Accumulated depreciation	(3,413)		(2,935)
Total LNG terminal, net of accumulated depreciation	30,178		30,242
Fixed assets and other
Computer and office equipment	27		25
Furniture and fixtures	20		19
Computer software	120		117
Leasehold improvements	45		45
Land	1		59
Other	20		25
Accumulated depreciation	(175)		(164)
Total fixed assets and other, net of accumulated depreciation	58		126
Assets under finance lease
Tug vessels	60		60
Accumulated depreciation	(8)		(7)
Total assets under finance lease, net of accumulated depreciation	52		53
Property, plant and equipment, net of accumulated depreciation	$	30,288	$	30,421

The following table shows depreciation expense and offsets to LNG terminal costs during the three and six months ended June 30, 2021 and 2020 (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Depreciation expense	$	258	$	231	$	492	$	463
Offsets to LNG terminal costs (1)	36		—		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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 6—DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments that are reported at fair value:

•interest rate swaps (“CCH Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on CCH’s amended and restated credit facility (the “CCH Credit Facility”) and previously, to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH (“CCH Interest Rate Forward Start Derivatives” and, collectively with the CCH Interest Rate Derivatives, the “Interest Rate Derivatives”);

•commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Projects and potential future development of Corpus Christi Stage 3 (“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 derivatives consisting of liquified natural gas contracts 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 it is 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 as of June 30, 2021 and December 31, 2020 (in millions):


	Fair Value Measurements as of
	June 30, 2021								December 31, 2020
	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
CCH Interest Rate Derivatives liability	$	—	$	(91)	$	—	$	(91)	$	—	$	(140)	$	—	$	(140)

Liquefaction Supply Derivatives asset (liability)	(7)		4		(194)		(197)		5		(6)		241		240
LNG Trading Derivatives asset (liability)	20		(226)		(195)		(401)		(3)		(131)		—		(134)
FX Derivatives liability	—		(4)		—		(4)		—		(22)		—		(22)

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 evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of June 30, 2021 and December 31, 2020, some of our Physical Liquefaction

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

We include our Physical LNG Trading Derivatives and a 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, volatility and contract duration.

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 and Physical LNG Trading Derivatives as of June 30, 2021:

Net Fair Value Liability
(in millions)

Valuation Approach

Significant Unobservable Input

Range of Significant Unobservable Inputs / Weighted Average (1)

Physical Liquefaction Supply Derivatives

$(194)

Market approach incorporating present value techniques

Henry Hub basis spread

$(0.573) - $0.385 / $(0.009)

Option pricing model

International LNG pricing spread, relative to Henry Hub (2)

137% - 297% / 175%

Physical LNG Trading Derivatives

$(195)

Market approach incorporating present value techniques

International LNG pricing spread, relative to Henry Hub or TTF, as applicable (2)

$(3.108) - $7.078 / $5.161

(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 during the three and six months ended June 30, 2021 and 2020 (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Balance, beginning of period	$	131	$	674	$	241	$	138
Realized and mark-to-market gains (losses):
Included in cost of sales	(464)		(84)		(471)		452

Purchases and settlements:
Purchases	(58)		(4)		(187)		(3)
Settlements	2		1		28		(1)
Transfers into Level 3, net (1)	—		3		—		4
Balance, end of period	$	(389)	$	590	$	(389)	$	590
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(464)	$	(84)	$	(471)	$	452

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

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 our derivative contracts with the same counterparty 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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. 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 has entered into interest rate swaps to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility. CCH previously also had interest rate swaps to hedge against changes in interest rates that could impact the anticipated future issuance of debt. In August 2020, we settled the outstanding CCH Interest Rate Forward Start Derivatives.

As of June 30, 2021, we had the following Interest Rate Derivatives outstanding:

Notional Amounts

June 30, 2021

December 31, 2020

Latest Maturity Date

Weighted Average Fixed Interest Rate Paid

Variable Interest Rate Received

CCH Interest Rate Derivatives

$4.6 billion

May 31, 2022

2.30%

One-month LIBOR

The following table shows the gain (loss) from changes in the fair value and settlements of our Interest Rate Derivatives recorded in interest rate derivative loss, net on our Consolidated Statements of Operations during the three and six months ended June 30, 2021 and 2020 (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
CCH Interest Rate Derivatives	$	(2)	$	(15)	$	(1)	$	(138)
CCH Interest Rate Forward Start Derivatives	—		(10)		—		(95)

Commodity Derivatives

SPL, CCL and CCL Stage III have entered into physical natural gas supply contracts and associated economic hedges, including those associated with our integrated production marketing (“IPM”) transactions, to purchase natural gas for the commissioning and operation of the Liquefaction Projects and potential future development of Corpus Christi Stage 3, respectively, which are primarily indexed to the natural gas market and international LNG indices. The remaining terms of the index-based physical natural gas supply contracts range up to approximately 15 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 first quarter of 2021, we have 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 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”):

June 30, 2021

December 31, 2020

Liquefaction Supply Derivatives

LNG Trading Derivatives

Liquefaction Supply Derivatives

LNG Trading Derivatives

Notional amount, net (in TBtu) (1)

10,631

10,483

(1) Includes notional amounts for natural gas supply contracts that SPL and CCL have with related parties. See Note 13—Related Party Transactions.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the gain (loss) from changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2021 and 2020 (in millions):


	Consolidated Statements of Operations Location (1)	Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020

LNG Trading Derivatives	LNG revenues	$	(379)	$	(34)	$	(441)	$	106
LNG Trading Derivatives	Cost of sales	53		34		81		—
Liquefaction Supply Derivatives (2)	LNG revenues	—		(13)		1		(14)
Liquefaction Supply Derivatives (2)	Cost of sales	(341)		(62)		(404)		475

(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.

FX Derivatives

Cheniere Marketing has entered into 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 $267 million and $786 million as of June 30, 2021 and December 31, 2020, respectively.

The following table shows the gain (loss) from changes in the fair value, settlements and location of our FX Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2021 and 2020 (in millions):


	Consolidated Statements of Operations Location	Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
FX Derivatives	LNG revenues	$	(5)	$	2	$	16	$	27

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):


	June 30, 2021
	CCH Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	53	$	119	$	6	$	178
Derivative assets	—		96		—		—		96
Total derivative assets	—		149		119		6		274

Current derivative liabilities	(91)		(201)		(520)		(10)		(822)
Derivative liabilities	—		(145)		—		—		(145)
Total derivative liabilities	(91)		(346)		(520)		(10)		(967)

Derivative liability, net	$	(91)	$	(197)	$	(401)	$	(4)	$	(693)

	December 31, 2020
	CCH Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	27	$	—	$	5	$	32
Derivative assets	—		376		—		—		376
Total derivative assets	—		403		—		5		408

Current derivative liabilities	(100)		(54)		(134)		(25)		(313)
Derivative liabilities	(40)		(109)		—		(2)		(151)
Total derivative liabilities	(140)		(163)		(134)		(27)		(464)

Derivative asset (liability), net	$	(140)	$	240	$	(134)	$	(22)	$	(56)

(1) Does not include collateral posted with counterparties by us of $22 million and $9 million, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2021 and December 31, 2020, respectively. Includes derivative assets for natural gas supply contracts that SPL and CCL have with related parties. See Note 13—Related Party Transactions.

(2) Does not include collateral posted with counterparties by us of $1 million and $7 million, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2021 and December 31, 2020, respectively.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Consolidated Balance Sheets Presentation

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


	CCH Interest Rate Derivatives		Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives

As of June 30, 2021
Gross assets	$	—	$	203	$	131	$	9
Offsetting amounts	—		(54)		(12)		(3)
Net assets	$	—	$	149	$	119	$	6

Gross liabilities	$	(91)	$	(401)	$	(614)	$	(37)
Offsetting amounts	—		55		94		27
Net liabilities	$	(91)	$	(346)	$	(520)	$	(10)

As of December 31, 2020
Gross assets	$	—	$	452	$	—	$	6
Offsetting amounts	—		(49)		—		(1)
Net assets	$	—	$	403	$	—	$	5

Gross liabilities	$	(140)	$	(184)	$	(163)	$	(62)
Offsetting amounts	—		21		29		35
Net liabilities	$	(140)	$	(163)	$	(134)	$	(27)

NOTE 7—OTHER NON-CURRENT ASSETS, NET

As of June 30, 2021 and December 31, 2020, other non-current assets, net consisted of the following (in millions):



	June 30,		December 31,
	2021		2020
Contract assets, net of current expected credit losses	$	105	$	80
Advances made to municipalities for water system enhancements	82		84
Equity method investments	88		81
Advances and other asset conveyances to third parties to support LNG terminals	69		60
Debt issuance costs and debt discount, net of accumulated amortization	30		42
Advances made under EPC and non-EPC contracts	2		9
Advance tax-related payments and receivables	18		20
Other	37		30
Total other non-current assets, net	$	431	$	406

Equity Method Investments

As of June 30, 2021, our equity method investment consists of our interest in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”). Midship Pipeline is currently operating an approximately 200-mile natural gas pipeline project (the “Midship Project”) that connects production in the Anadarko Basin to Gulf Coast markets. The Midship Project commenced operations in April 2020.

Our investment in Midship Holdings, net of impairment losses, was $88 million and $80 million as of June 30, 2021 and December 31, 2020, respectively.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—NON-CONTROLLING INTEREST AND VARIABLE INTEREST ENTITY

We own a 48.6% limited partner interest in Cheniere Partners in the form of 239.9 million common units, with the remaining non-controlling limited partner interest held by The Blackstone Group Inc., Brookfield Asset Management Inc. and the public. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners. Cheniere Partners is accounted for as a consolidated VIE. See Note 9—Non-Controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the fiscal year ended December 31, 2020 for further information.

The following table presents the summarized assets and liabilities (in millions) of Cheniere Partners, our consolidated VIE, which are included in our Consolidated Balance Sheets as of June 30, 2021 and December 31, 2020. The assets in the table below may only be used to settle obligations of Cheniere Partners. 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 Cheniere Partners only and exclude intercompany balances that eliminate in consolidation.



	June 30,		December 31,
	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	1,239	$	1,210
Restricted cash	65		97
Accounts and other receivables, net of current expected credit losses	285		318
Other current assets	236		182
Total current assets	1,825		1,807


Property, plant and equipment, net of accumulated depreciation	16,789		16,723
Other non-current assets, net	289		287

Total assets	$	18,903	$	18,817

LIABILITIES
Current liabilities

Accrued liabilities	$	649	$	658
Current debt, net of premium, discount and debt issuance costs	654		—
Other current liabilities	154		171

Total current liabilities	1,457		829

Long-term debt, net of premium, discount and debt issuance costs	16,935		17,580

Other non-current liabilities	95		126
Total liabilities	$	18,487	$	18,535

NOTE 9—ACCRUED LIABILITIES

As of June 30, 2021 and December 31, 2020, accrued liabilities consisted of the following (in millions):



	June 30,		December 31,
	2021		2020
Interest costs and related debt fees	$	236	$	245
Accrued natural gas purchases	559		576
LNG terminals and related pipeline costs	169		147
Compensation and benefits	69		123
Accrued LNG inventory	49		4
Other accrued liabilities	115		80
Total accrued liabilities	$	1,197	$	1,175

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—DEBT

As of June 30, 2021 and December 31, 2020, our debt consisted of the following (in millions):



	June 30,		December 31,
	2021		2020
Long-term debt:











SPL — 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 SPL Working Capital Facility”)	$	12,994	$	13,650






Cheniere Partners — 4.000% to 5.625% senior notes due between October 2025 and March 2031 and credit facilities (“2019 CQP Credit Facilities”)	4,100		4,100









CCH — 3.52% to 7.000% senior secured notes due between June 2024 and December 2039 and CCH Credit Facility	10,216		10,217







Cheniere — 4.625% senior secured notes due October 2028 (the “2028 Cheniere Senior Notes”), convertible notes, revolving credit facility (“Cheniere Revolving Credit Facility”) and term loan facility (“Cheniere Term Loan Facility”)	2,625		3,145
Unamortized premium, discount and debt issuance costs, net of accumulated amortization	(608)		(641)
Total long-term debt, net of premium, discount and debt issuance costs	29,327		30,471

Current debt:
SPL — current portion of 6.25% senior secured notes due March 2022 (“2022 SPL Senior Notes”) (1)	656		—

CCH — $1.2 billion CCH working capital facility (“CCH Working Capital Facility”) and current portion of CCH Credit Facility	132		271
Cheniere Marketing — trade finance facilities and letter of credit facility	30		—
Cheniere — current portion of the 4.875% convertible unsecured notes due May 2021 (“2021 Cheniere Convertible Notes”) and Cheniere Revolving Credit Facility (2)	134		104
Unamortized discount and debt issuance costs, net of accumulated amortization	(3)		(3)
Total current debt, net of discount and debt issuance costs	949		372

Total debt, net of premium, discount and debt issuance costs	$	30,276	$	30,843

(1)A portion of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected series of sales of approximately $347 million aggregate principal amount of senior secured notes due 2037, expected to be issued in the second half of 2021, subject to customary closing conditions, will be used to strategically refinance a portion of 2022 SPL Senior Notes and pay related fees, costs and expenses.

(2) The outstanding balance under the Cheniere Revolving Credit Facility as of June 30, 2021 was repaid in July 2021 and is categorized as short-term debt.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Issuances, Redemptions and Repayments

The following table shows the issuances, redemptions and repayments of long-term debt during the six months ended June 30, 2021 (in millions):


Issuances	Principal Amount Issued
Three Months Ended March 31, 2021
Cheniere Partners — 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) (1)	$	1,500

Three Months Ended June 30, 2021
Cheniere — Cheniere Term Loan Facility (2)	220
Cheniere — Cheniere Revolving Credit Facility	134
Six Months Ended June 30, 2021 total	$	1,854

Redemptions and Repayments	Principal Amount Redeemed/Repaid
Three Months Ended March 31, 2021
Cheniere Partners — 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) (1)	$	1,500
Cheniere — Cheniere Term Loan Facility (3)	148

Three Months Ended June 30, 2021
Cheniere — 2021 Cheniere Convertible Notes (2)	476
Cheniere — Cheniere Term Loan Facility (3)	220
Six Months Ended June 30, 2021 total	$	2,344

(1)Proceeds of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of CQP’s outstanding 2025 CQP Senior Notes, resulting in the recognition of debt extinguishment costs of $54 million for the six months ended June 30, 2021 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

(2)In May 2021, the 2021 Cheniere Convertible Notes were repaid using a combination of borrowings under the Cheniere Term Loan Facility and cash on hand upon the maturity date at par value.

(3)As of June 30, 2021, the remaining commitments under the Cheniere Term Loan Facility were terminated in accordance with the credit agreement, resulting in $4 million of loss on extinguishment of debt.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2021 (in millions):


	2020 SPL Working Capital Facility (1)		2019 CQP Credit Facilities		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Original facility size	$	1,200	$	1,500	$	8,404	$	350	$	750
Incremental commitments	—		—		1,566		850		500
Less:
Outstanding balance	—		—		2,627		—		134
Commitments prepaid or terminated	—		750		7,343		—		—
Letters of credit issued	396		—		—		293		—
Available commitment	$	804	$	750	$	—	$	907	$	1,116

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%		LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75%		LIBOR plus 1.75% - 2.50% or base rate plus 0.75% - 1.50%
Weighted average interest rate of outstanding balance	n/a		n/a		1.85%		n/a		1.82%
Maturity date	March 19, 2025		May 29, 2024		June 30, 2024		June 29, 2023		December 13, 2022

(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

Convertible Notes

Below is a summary of our convertible notes outstanding as of June 30, 2021 (in millions):


	2045 Cheniere Convertible Senior Notes



Aggregate original principal	$	625

Debt component, net of discount and debt issuance costs	$	319
Equity component	$	194
Interest payment method	Cash
Conversion by us (1)	(2)
Conversion by holders (1)	(3)
Conversion basis	Cash and/or stock
Conversion value in excess of principal	$	—
Maturity date	March 15, 2045
Contractual interest rate	4.25		%
Effective interest rate (4)	9.4		%
Remaining debt discount and debt issuance costs amortization period (5)	23.7 years

(1)Conversion is subject to various limitations and conditions, which have not been met as of the balance sheet date.

(2)Redeemable at any time at a redemption price payable in cash equal to the accreted amount of the $625 million aggregate principal amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date.

(3)Prior to December 15, 2044, convertible only under certain circumstances as specified in the indenture; thereafter, holders may convert their notes regardless of these circumstances. The conversion rate will initially equal 7.2265 shares of our common stock per $1,000 principal amount of the 2045 Cheniere Convertible Senior Notes,

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

which corresponds to an initial conversion price of approximately $138.38 per share of our common stock (subject to adjustment upon the occurrence of certain specified events).

(4)Rate to accrete the discounted carrying value of the convertible notes to the face value over the remaining amortization period.

(5)We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity.

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.

As of June 30, 2021, 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Interest cost on convertible notes:
Interest per contractual rate	$	11	$	57	$	23	$	120
Amortization of debt discount	3		20		8		34
Amortization of debt issuance costs	—		4		—		7
Total interest cost related to convertible notes	14		81		31		161
Interest cost on debt and finance leases excluding convertible notes	387		388		787		779
Total interest cost	401		469		818		940
Capitalized interest	(33)		(62)		(94)		(121)
Total interest expense, net of capitalized interest	$	368	$	407	$	724	$	819

Fair Value Disclosures

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


	June 30, 2021				December 31, 2020
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	24,700	$	27,503	$	24,700	$	27,897
Senior notes — Level 3 (2)	2,771		3,350		2,771		3,423
Credit facilities — Level 3 (3)	2,791		2,791		2,915		2,915
2021 Cheniere Convertible Notes — Level 3 (2)	—		—		476		480

2045 Cheniere Convertible Senior Notes — Level 1 (4)	625		527		625		496

(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 3 estimated fair value approximates the principal amount 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.

(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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—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 our tug vessels supporting the Corpus Christi LNG Terminal, 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):



		June 30,		December 31,
	Consolidated Balance Sheets Location	2021		2020
Right-of-use assets—Operating	Operating lease assets	$	1,698	$	759
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	52		53
Total right-of-use assets		$	1,750	$	812

Current operating lease liabilities	Current operating lease liabilities	$	365	$	161
Current finance lease liabilities	Other current liabilities	2		2
Non-current operating lease liabilities	Operating lease liabilities	1,332		597
Non-current finance lease liabilities	Finance lease liabilities	57		57
Total lease liabilities		$	1,756	$	817

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 June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
Operating lease cost (a)	Operating costs and expenses (1)	$	145	$	98	$	296	$	239
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	1		1		2		2
Interest on lease liabilities	Interest expense, net of capitalized interest	3		3		5		5

Total lease cost		$	149	$	102	$	303	$	246

(a) Included in operating lease cost:
Short-term lease costs		$	30	$	16	$	81	$	51
Variable lease costs		11		4		13		9

(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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Future annual minimum lease payments for operating and finance leases as of June 30, 2021 are as follows (in millions):


Years Ending December 31,	Operating Leases (1)		Finance Leases
2021	$	227	$	5
2022	397		10
2023	358		10
2024	313		10
2025	213		10
Thereafter	448		127
Total lease payments	1,956		172
Less: Interest	(259)		(113)
Present value of lease liabilities	$	1,697	$	59

(1) Does not include $984 million of legally binding minimum lease payments primarily for vessel charters which were executed as of June 30, 2021 but will commence in future periods primarily in the next year and have fixed minimum lease terms of up to seven years.

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


	June 30, 2021		December 31, 2020
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.4	17.2	8.2	17.7
Weighted-average discount rate (1)	4.1%	16.2%	5.4%	16.2%

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

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


	Six Months Ended June 30,
	2021		2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows used in operating leases	$	201	$	157
Operating cash flows used in finance leases	5		5

Right-of-use assets obtained in exchange for operating lease liabilities	1,112		246

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 June 30, 2021 and December 31, 2020, we had $4 million and zero, respectively, in 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Fixed income	$	8	$	15	$	11	$	52
Variable income	5		8		6		23
Total sublease income	$	13	$	23	$	17	$	75

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 12—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and six months ended June 30, 2021 and 2020 (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
LNG revenues (1)	$	3,297	$	2,340	$	6,336	$	4,744
Regasification revenues	67		68		134		135
Other revenues	24		16		44		38

Total revenues from customers	3,388		2,424		6,514		4,917
Net derivative gain (loss) (2)	(384)		(45)		(424)		119
Other (3)	13		23		17		75
Total revenues	$	3,017	$	2,402	$	6,107	$	5,111

(1) LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three and six months ended June 30, 2020, we recognized $708 million and $761 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $458 million would have been recognized subsequent to June 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended June 30, 2020 and six months ended June 30, 2021 excluded $53 million and $38 million, respectively, that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the three and six months ended June 30, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

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

(3) Includes revenues from LNG vessel subcharters. See Note 11—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 other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):



	June 30,		December 31,
	2021		2020
Contract assets, net of current expected credit losses	$	109	$	80

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the six months ended June 30, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

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



	Six Months Ended June 30, 2021
Deferred revenue, beginning of period	$	138
Cash received but not yet recognized in revenue	105
Revenue recognized from prior period deferral	(138)
Deferred revenue, end of period	$	105

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 as of June 30, 2021 and December 31, 2020:


	June 30, 2021			December 31, 2020
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	101.1	10	$	102.3	10
Regasification revenues	2.0		4	2.1		5
Total revenues	$	103.1		$	104.4

(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. Approximately 53% and 26% of our LNG revenues from contracts included in the table above during the three months ended June 30, 2021 and 2020, respectively, and approximately 52% and 34% of our LNG revenues from contracts included in the table above during the six months ended June 30, 2021 and 2020, respectively, were related to variable consideration received from customers. During each of the three and six months ended June 30, 2021, approximately 5% of our regasification revenues were related to variable consideration received from customers and during each of the three and six months ended June 30, 2020, approximately 6% 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.

NOTE 13—RELATED PARTY TRANSACTIONS

Natural Gas Supply Agreements

SPL and CCL are party to natural gas supply agreements with related parties in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Projects. These related parties are partially owned by The Blackstone Group Inc., who also partially owns Cheniere Partners’ limited partner interests.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPL Natural Gas Supply Agreement

The term of the SPL agreement is for five years, which can commence no earlier than November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions precedent. As of both June 30, 2021 and December 31, 2020, the notional amount for this agreement was 91 TBtu and had a fair value of zero.

CCL Natural Gas Supply Agreement

The term of the CCL agreement extends through March 2022. Under this agreement, CCL recorded $13 million in accrued liabilities, as of both June 30, 2021 and December 31, 2020.

The Liquefaction Supply Derivatives related to this agreement are recorded on our Consolidated Balance Sheets as follows (in millions, except notional amount):



	June 30,		December 31,
	2021		2020
Current derivative assets	$	4	$	3
Derivative assets	7		1

Notional amount (in TBtu)	132		60

We recorded the following amounts on our Consolidated Statements of Operations during the three and six months ended June 30, 2021 and 2020 related to this agreement (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Cost of sales (a)	$	36	$	25	$	71	$	48

(a) Included in costs of sales:
Liquefaction Supply Derivative gain	$	6	$	1	$	7	$	2

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 Cheniere Partners’ limited partner interests in September 2020. We recorded operating and maintenance expense of $12 million and $22 million and cost of sales of $1 million and $1 million during the three and six months ended June 30, 2021, respectively, and accrued liabilities of $4 million as of both June 30, 2021 and December 31, 2020 with this related party.

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 $3 million in the three months ended June 30, 2021 and 2020, respectively, and $3 million and $6 million in the six months ended June 30, 2021 and 2020, respectively, of other revenues and $1 million and $2 million of accounts receivable as of June 30, 2021 and December 31, 2020, respectively, for services provided to Midship Pipeline under these agreements.

NOTE 14—INCOME TAXES

We recorded an income tax benefit of $93 million and $4 million during the three and six months ended June 30, 2021, respectively, and an income tax provision of $63 million and $194 million during the three and six months ended June 30, 2020, respectively. The effective tax rates for the three and six months ended June 30, 2021 were 41.5% and (0.9)%, respectively, and do not bear a customary relationship to statutory income tax rates due to a combination of factors including income

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

allocated to non-controlling interest that is not taxable to Cheniere and a $58 million discrete tax benefit related to releasing a portion of our valuation allowance caused by a change in tax law allowing for indefinite Louisiana net operating loss (“NOL”) carryover. The effective tax rates for the three and six months ended June 30, 2020 were 13.5% and 16.2%, respectively, which were lower than the 21% federal statutory tax rate primarily due to income allocated to non-controlling interest that is not taxable to Cheniere, partially offset by a $38 million discrete tax expense related to an internal restructuring.

NOTE 15—SHARE-BASED COMPENSATION

We have granted restricted stock shares, restricted stock units, performance stock units and phantom units to employees and non-employee directors under the 2011 Incentive Plan, as amended (the “2011 Plan”) and the 2020 Incentive Plan. For the six months ended June 30, 2021, we granted 1.5 million restricted stock units and 0.3 million performance stock units at target performance under the 2020 Plan to certain employees. Additionally, 0.2 million incremental shares of our common stock were issued based on performance results from previously-granted performance stock unit awards.

Restricted stock units are stock awards that vest over a service period of three years and entitle the holder to receive shares of our common stock upon vesting, subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with us prior to the lapse of the restrictions. Performance stock units provide for cliff vesting after a period of three years with payouts based on metrics dependent upon market and performance achieved over the defined performance period compared to pre-established performance targets. The settlement amounts of the awards are based on market and performance metrics which include cumulative distributable cash flow per share, and in certain circumstances, absolute total shareholder return (“ATSR”) of our common stock. Where applicable, the compensation for performance stock units is based on fair value assigned to the market metric of ATSR using a Monte Carlo model upon grant, which remains constant through the vesting period, and a performance metric, which will vary due to changing estimates regarding the expected achievement of the performance metric of cumulative distributable cash flow per share. The number of shares that may be earned at the end of the vesting period ranges from 0% up to 300% of the target award amount. Both restricted stock units and performance stock units will be settled in Cheniere common stock (on a one-for-one basis) and are classified as equity awards, however, a portion of the performance stock units granted in 2021 will partially settle in cash, subject to individual limits. The portion of performance stock units expected to settle in Cheniere common stock (on a one-for-one basis) are classified as equity awards and the portion of performance stock units expected to settle in cash are classified as liability awards.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Share-based compensation costs, pre-tax:
Equity awards	$	31	$	31	$	64	$	60
Liability awards	1		1		2		1
Total share-based compensation	32		32		66		61
Capitalized share-based compensation	(1)		(3)		(3)		(4)
Total share-based compensation expense	$	31	$	29	$	63	$	57
Tax benefit associated with share-based compensation expense	$	1	$	1	$	27	$	19

NOTE 16—NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

Basic net income (loss) per share attributable to common stockholders (“EPS”) excludes dilution and is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued. The dilutive effect of unvested stock is calculated using the treasury-stock method and the dilutive effect of convertible securities is calculated using the if-converted method.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table reconciles basic and diluted weighted average common shares outstanding for the three and six months ended June 30, 2021 and 2020 (in millions, except per share data):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net income (loss) attributable to common stockholders	$	(329)	$	197	$	64	$	572

Weighted average common shares outstanding:
Basic	253.5		252.1		253.2		252.6
Dilutive unvested stock	—		0.3		1.5		0.7

Diluted	253.5		252.4		254.7		253.3

Net income (loss) per share attributable to common stockholders—basic (1)	$	(1.30)	$	0.78	$	0.25	$	2.27
Net income (loss) per share attributable to common stockholders—diluted (1)	$	(1.30)	$	0.78	$	0.25	$	2.26

(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.

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


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
Unvested stock (1)	1.5	2.8	—	2.5



2045 Cheniere Convertible Senior Notes	4.5	4.5	4.5	4.5
Total potentially dilutive common shares	6.0	7.3	4.5	7.0

(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.

NOTE 17—CUSTOMER CONCENTRATION

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


	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,

	2021	2020	2021	2020		2021	2020
Customer A	14%	15%	15%	15%		*	14%
Customer B	12%	12%	12%	10%		*	12%
Customer C	*	10%	11%	*		*	*

* Less than 10%

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION

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


	Six Months Ended June 30,
	2021		2020
Cash paid during the period for interest on debt, net of amounts capitalized	$	675	$	750
Cash paid for income taxes, net of refunds	1		1

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities was $264 million and $222 million as of June 30, 2021 and 2020, respectively.

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 regarding the amount and timing of share repurchases;

•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;

•statements regarding the outbreak of COVID-19 and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing credit worthiness of our contractual counterparties, any disruptions in our operations or construction of our Trains and the health and safety of our employees, and on our customers, the global economy and the demand for LNG; 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 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, 2020. 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 of Business

•Overview of Significant Events

•Results of Operations

•Liquidity and Capital Resources

•Off-Balance Sheet Arrangements

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Overview of Business

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. We own and operate the Sabine Pass LNG terminal in Louisiana, one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. As of June 30, 2021, we owned 100% of the general partner interest and 48.6% of the limited partner interest in Cheniere Partners. We also own and operate the Corpus Christi LNG terminal in Texas, which is wholly owned by us.

Cheniere Partners owns the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, which has natural gas liquefaction facilities consisting of five operational natural gas liquefaction Trains and one additional Train under construction that is expected to be substantially completed in the first half of 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 with aggregate capacity of approximately 17 Bcfe, two existing marine berths and one under construction that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4 Bcf/d. Cheniere Partners also owns a 94-mile pipeline through its subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

We also own the Corpus Christi LNG terminal near Corpus Christi, Texas, and currently operate three Trains for a total production capacity of approximately 15 mtpa of LNG. Additionally, we operate a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, the “CCL Project”) through our subsidiaries CCL and CCP, respectively, as part of the CCH Group. The CCL Project also contains three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters.

We have contracted approximately 85% of the total production capacity from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) on a term basis, with approximately 17 years of weighted average remaining life as of June 30, 2021. This includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, as well as a portion of volumes contracted under integrated production marketing (“IPM”) gas supply agreements.

Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (“Corpus Christi Stage 3”) through our subsidiary CCL Stage III for up to seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG. We received approval from FERC in November 2019 to site, construct and operate the expansion project. CCL Stage III has entered into various IPM gas supply agreements.

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. 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 can make a final investment decision (“FID”).

Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. We published our 2020 Corporate Responsibility (“CR”) report, which details our strategy and progress on ESG issues, as well as our efforts on integrating climate considerations into our business strategy and taking a leadership position on increased environmental transparency, including conducting a climate scenario analysis and our plan to provide LNG customers with Cargo Emission Tags. Our CR report is available at cheniere.com/IMPACT.

Overview of Significant Events

Our significant events since January 1, 2021 and through the filing date of this Form 10-Q include the following:

Strategic

•In July 2021, CCL Stage III entered into an IPM gas supply agreement with Tourmaline Oil Marketing Corp. to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023.

•On July 1, 2021, the board of directors of the Company (the “Board”) appointed Mses. Patricia K. Collawn and Lorraine Mitchelmore to serve as members of the Board. Ms. Collawn was appointed to the Audit Committee and the Compensation Committee of the Board, and Ms. Mitchelmore was appointed to the Audit Committee and the Governance and Nominating Committee of the Board.

•Our subsidiaries entered into SPAs with multiple counterparties for portfolio volumes aggregating approximately 12 million tonnes of LNG to be delivered between 2021 and 2032.

Operational

•As of July 31, 2021, approximately 1,675 cumulative LNG cargoes totaling approximately 115 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

•On March 26, 2021, substantial completion of Train 3 of the CCL Project was achieved.

Financial

•We completed the following financing transactions:

◦During 2021, SPL entered into a series of note purchase agreements for the sale of approximately $347 million aggregate principal amount of Senior Secured Notes due 2037 (the “2037 SPL Private Placement Senior Secured Notes”) on a private placement basis. The 2037 SPL Private Placement Senior Secured Notes are expected to be issued in the second half of 2021, subject to customary closing conditions, and the net proceeds will be used to strategically refinance a portion of SPL’s outstanding 6.25% SPL Senior Secured

Notes due 2022 and pay related fees, costs and expenses. The 2037 SPL Private Placement Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years.

◦In March 2021, Cheniere Partners issued an aggregate principal amount of approximately $1.5 billion of 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”). The net proceeds of the 2031 CQP Senior Notes, along with cash on hand, were used to refinance the 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) and to pay fees and expenses in connection with the refinancing.

•During the six months ended June 30, 2021, in line with our previously announced capital allocation priorities, we fully repaid the $624 million of total outstanding indebtedness under Cheniere’s term loan facility (“Cheniere Term Loan Facility”) and Cheniere’s 4.875% convertible notes due May 2021 (“2021 Cheniere Convertible Notes”) with $500 million of available cash and the remainder from borrowings under the Cheniere Revolving Credit Facility.

•In January 2021, the term commenced on Cheniere Marketing International LLP’s 25 year SPA with CPC Corporation, Taiwan.

•In February 2021, Fitch Ratings (“Fitch”) changed the outlook of SPL’s senior secured notes rating to positive from stable and the outlook of Cheniere Partners’ long-term issuer default rating and senior unsecured notes rating to positive from stable.

•In April 2021, S&P Global Ratings changed the outlook of Cheniere and Cheniere Partners’ ratings to positive from negative.

Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Projects (including both operational and commissioning volumes) during the six months ended June 30, 2021 and 2020:

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 during the three and six months ended June 30, 2021:


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
(in TBtu)	Operational	Commissioning	Operational	Commissioning
Volumes loaded during the current period	499	—	947	28
Volumes loaded during the prior period but recognized during the current period	32	6	26	3
Less: volumes loaded during the current period and in transit at the end of the period	(23)	—	(23)	—
Total volumes recognized in the current period	508	6	950	31

Net income attributable to common stockholders


	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except per share data)	2021		2020		Change		2021		2020		Change
Net income (loss) attributable to common stockholders	$	(329)	$	197	$	(526)	$	64	$	572	$	(508)
Net income (loss) per share attributable to common stockholders—basic	(1.30)		0.78		(2.08)		0.25		2.27		(2.02)
Net income (loss) per share attributable to common stockholders—diluted	(1.30)		0.78		(2.08)		0.25		2.26		(2.01)

Net income attributable to common stockholders decreased by $526 million and $508 million during the three and six months ended June 30, 2021, respectively, from the comparable periods in 2020, primarily as a result of a $472 million and $886 million increase in derivative-related after-tax losses attributable to common stockholders for the three and six months ended June 30, 2021, respectively. The derivative-related losses in the three and six months ended June 30, 2021 were mainly the result of $674 million and $748 million, respectively, of pre-tax derivative losses, primarily on our commodity derivatives as a result of unfavorable shifts in international forward commodity curves. Additionally, during the three months ended June 30, 2021 compared to the comparable period in 2020, margins declined due to the non-recurrence, during the three months ended June 30, 2021, of accelerated revenues recognized from LNG cargoes for which customers notified us that they would not take delivery, which were partially offset by increased revenue on increased volume of LNG delivered. During the six months ended June 30, 2021, the decrease in net income attributable to common stockholders due to losses in derivatives was partially offset by increased commodity margins per MMBtu on volumes delivered, due to both increased revenue per MMBtu and volumes delivered, as well as higher than normal contributions from LNG and natural gas portfolio optimization activities due to significant volatility in LNG and natural gas markets during the six months ended June 30, 2021. This was partially offset by the non-recurrence, during the six months ended June 30, 2021, of accelerated revenues recognized from LNG cargoes for which customers notified us that they would not take delivery.

We enter into derivative instruments to manage our exposure to (1) changing interest rates, (2) commodity-related marketing and price risks, including those associated with our IPM transactions, and (3) foreign exchange volatility. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions being economically hedged are accounted for under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt 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, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.

Revenues


	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2021		2020		Change		2021		2020		Change
LNG revenues	$	2,913	$	2,295	$	618	$	5,912	$	4,863	$	1,049
Regasification revenues	67		68		(1)		134		135		(1)
Other revenues	37		39		(2)		61		113		(52)

Total revenues	$	3,017	$	2,402	$	615	$	6,107	$	5,111	$	996

Total revenues increased during the three and six months ended June 30, 2021 from the comparable periods in 2020, primarily as a result of increased revenues per MMBtu and higher volume of LNG delivered between the periods due to the non-recurrence of notification by our customers to not take delivery of scheduled LNG during the three and six months ended June 30, 2021. Revenues per MMBtu of LNG was higher due to improved market prices recognized by our integrated marketing function and as a result of variable fees that are received in addition to fixed fees when the customers take delivery of the cargo as opposed to exercising their contractual right to not take delivery. During the three and six months ended June 30, 2020, we recognized $708 million and $761 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $458 million would have been recognized subsequent to June 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended June 30, 2020 and six months ended June 30, 2021 excluded $53 million and $38 million, respectively, that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the

customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the three and six months ended June 30, 2021.

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 three and six months ended June 30, 2021, we realized offsets to LNG terminal costs of $36 million and $227 million, corresponding to 6 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 and six months ended June 30, 2020.

Also included in LNG revenues are sales of certain unutilized natural gas procured for the liquefaction process and 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 revenues (offsets to revenues) of $(340) million and $61 million during the three months ended June 30, 2021 and 2020, respectively, and $(276) million and $273 million during the six months ended June 30, 2021 and 2020, respectively, related to these transactions.

We expect our LNG revenues to increase in the future with Train 3 of the CCL Project now fully operational and upon Train 6 of the SPL Project becoming operational.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	$	2,482	$	1,244	$	4,801	$	3,151
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	683		150		1,202		475
LNG procured from third parties	88		132		185		203
LNG revenues associated with cargoes not delivered per customer notification (2)	—		708		—		761
Other revenues and net derivative gains (losses)	(340)		61		(276)		273
Total LNG revenues	$	2,913	$	2,295	$	5,912	$	4,863

Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	403		253		784		619
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	105		52		166		145
LNG procured from third parties	14		34		28		48
Total volumes delivered as LNG revenues	522		339		978		812

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

(2) LNG revenues include revenues with no corresponding volumes due to revenues attributable to LNG cargoes for which customers notified us that they would not take delivery.

Operating costs and expenses


	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2021		2020		Change		2021		2020		Change
Cost of sales	$	2,154	$	803	$	1,351	$	3,540	$	1,527	$	2,013

Operating and maintenance expense	385		355		30		707		671		36
Development expense	2		1		1		3		5		(2)
Selling, general and administrative expense	73		73		—		154		154		—
Depreciation and amortization expense	258		233		25		494		466		28

Impairment expense and loss (gain) on disposal of assets	(1)		—		(1)		(1)		5		(6)


Total operating costs and expenses	$	2,871	$	1,465	$	1,406	$	4,897	$	2,828	$	2,069

Our total operating costs and expenses increased during the three and six months ended June 30, 2021 from the comparable periods in 2020, primarily as a result of increased cost of sales.

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 increased during the three and six months ended June 30, 2021 from the comparable 2020 periods, primarily due to increased pricing of natural gas feedstock and increased volume of LNG produced, as well as unfavorable changes in our commodity derivatives to secure natural gas feedstock for the Liquefaction Projects driven by unfavorable shifts in international forward commodity curves. Partially offsetting these increases were decreases in net costs associated with the sale of certain unutilized natural gas procured for the liquefaction process and a portion of derivative instruments that settle through physical delivery. Cost of sales also includes port and canal fees, variable transportation and storage costs, net of margins from the sale of natural gas procured for the liquefaction process and other costs to convert natural gas into LNG.

We expect our operating costs and expenses to generally increase in the future upon Train 6 of the SPL Project achieving substantial completion, although we expect certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.

Other expense (income)


	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2021		2020		Change		2021		2020		Change
Interest expense, net of capitalized interest	$	368	$	407	$	(39)	$	724	$	819	$	(95)
Loss on modification or extinguishment of debt	4		43		(39)		59		44		15
Interest rate derivative loss, net	2		25		(23)		1		233		(232)
Other income, net	(4)		(5)		1		(10)		(14)		4
Total other expense	$	370	$	470	$	(100)	$	774	$	1,082	$	(308)

Interest expense, net of capitalized interest, decreased during the three and six months ended June 30, 2021 from the comparable 2020 periods as a result of lower interest costs as a result of refinancing higher cost debt. During the three months ended June 30, 2021 and 2020, we incurred $401 million and $469 million of total interest cost, respectively, of which we capitalized $33 million and $62 million, respectively, which was primarily related to interest costs incurred for the construction of the Liquefaction Projects. During the six months ended June 30, 2021 and 2020, we incurred $818 million and $940 million of total interest cost, respectively, of which we capitalized $94 million and $121 million, respectively, which was primarily related to interest costs incurred for the construction of the Liquefaction Projects.

Loss on modification or extinguishment of debt decreased during the three months ended June 30, 2021 and increased during the six months ended June 30, 2021 from the respective comparable periods in 2020. During the three months ended June 30, 2021, we recognized $4 million of debt extinguishment costs relating to the termination of the Cheniere Term Loan Facility and in the six months ended June 30, 2021, we further recognized $54 million of debt extinguishment costs relating to the payment of early redemption fees and premiums and write off of unamortized debt issuance costs with the redemption of the 2025 CQP Senior Notes. Loss on modification or extinguishment of debt recognized in 2020 was primarily attributable to $43 million of debt extinguishment costs relating to the payment of early redemption fees and write off of unamortized debt premiums and issuance costs associated with the 5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”).

Interest rate derivative loss, net decreased during the three and six months ended June 30, 2021 compared to the comparable 2020 periods, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods and the settlement of certain outstanding derivatives in August 2020.

Income tax provision (benefit)


	Three Months Ended June 30,								Six Months Ended June 30,
(in millions)	2021			2020			Change		2021			2020			Change
Income (loss) before income taxes and non-controlling interest	$	(224)		$	467		$	(691)	$	436		$	1,201		$	(765)
Income tax provision (benefit)	(93)			63			(156)		(4)			194			(198)
Effective tax rate	41.5		%	13.5		%			(0.9)		%	16.2		%

The effective tax rates for the three and six months ended June 30, 2021 were 41.5% and (0.9)%, respectively, and do not bear a customary relationship to statutory income tax rates due to a combination of factors including income allocated to non-controlling interest that is not taxable to Cheniere and a $58 million discrete tax benefit related to releasing a portion of our valuation allowance caused by a change in tax law allowing for indefinite Louisiana net operating loss (“NOL”) carryover. The effective tax rates for the three and six months ended June 30, 2020 were 13.5% and 16.2%, respectively, which were lower than the 21% federal statutory tax rate primarily due to income allocated to non-controlling interest that is not taxable to Cheniere, partially offset by a $38 million discrete tax expense related to an internal restructuring. Our effective tax rate may continue to experience volatility prospectively due to variability in our pre-tax and taxable earnings and the proportion of such earnings attributable to non-controlling interests.

Net income attributable to non-controlling interest


	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2021		2020		Change		2021		2020		Change
Net income attributable to non-controlling interest	$	198	$	207	$	(9)	$	376	$	435	$	(59)

Net income attributable to non-controlling interest decreased during the three and six months ended June 30, 2021 from the three and six months ended June 30, 2020 primarily due to a decrease in consolidated net income recognized by Cheniere Partners, which decreased from $406 million in the three months ended June 30, 2020 to $395 million in the three months ended June 30, 2021 and decreased from $841 million in the six months ended June 30, 2020 to $742 million in the six months ended June 30, 2021.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, SPL, Cheniere Partners, CCH Group and Cheniere operate with independent capital structures. Our capital requirements include capital and investment expenditures, repayment of long-term debt and repurchase of our shares. We expect the cash needs for at least the next twelve months will be met for each of these independent capital structures as follows:

•SPL through operating cash flows, project debt and borrowings and equity contributions from Cheniere Partners;

•Cheniere Partners through operating cash flows from SPLNG, SPL and CTPL, debt or equity offerings and borrowings;

•CCH Group through operating cash flows from CCL and CCP, project debt and borrowings and equity contributions from Cheniere; and

•Cheniere through existing unrestricted cash, debt and equity offerings by us or our subsidiaries, operating cash flows, borrowings, services fees from our subsidiaries and distributions from our investment in Cheniere Partners.

The following table provides a summary of our liquidity position at June 30, 2021 and December 31, 2020 (in millions):



	June 30,		December 31,
	2021		2020
Cash and cash equivalents (1)	$	1,806	$	1,628
Restricted cash designated for the following purposes:

SPL Project	65		97


CCL Project	122		70
Other	237		282
Available commitments under the following credit facilities:

$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”)	804		787
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”)	750		750


$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	907		767
$1.25 billion Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	1,116		1,126
Cheniere Term Loan Facility	—		372

(1) Amounts presented include balances held by our consolidated variable interest entity (“VIE”), Cheniere Partners, as discussed in Note 8—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of both June 30, 2021 and December 31, 2020, assets of Cheniere Partners, which are included in our Consolidated Balance Sheets, included $1.2 billion of cash and cash equivalents.

Sabine Pass LNG Terminal

Liquefaction Facilities

The SPL Project is one of the largest LNG production facilities in the world. Through Cheniere Partners, we are currently operating five Trains and two marine berths at the SPL Project, and are constructing one additional Train that is expected to be substantially completed in the first half of 2022, and a third marine berth. We have achieved substantial completion of the first five Trains of the SPL Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the SPL Project as of June 30, 2021:


						SPL Train 6
Overall project completion percentage						89.6%
Completion percentage of:
Engineering						99.7%
Procurement						99.9%
Subcontract work						70.2%
Construction						79.3%
Date of expected substantial completion						1H 2022

The DOE has issued three orders authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries through December 31, 2050, up to a combined total equivalent of approximately 1,509.3 Bcf/yr (approximately 30 mtpa) of natural gas.

In December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations separately from long-term authorizations. Accordingly, the DOE amended each of SPL’s long-term authorizations to include short-term export authority, and vacated the short-term orders.

An application was filed in September 2019 seeking authorization to make additional exports from the SPL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 153 Bcf/yr of natural gas, for a total SPL Project export capacity of approximately 1,662 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the SPL Project of the volumes contemplated in the application. In April 2020, the DOE issued an order authorizing SPL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing SPL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for

authorization to increase the total LNG production capacity of the SPL Project from the currently authorized level to approximately 1,662 Bcf/yr was also submitted to the FERC and is currently pending.

Customers

SPL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 17 years (plus extension rights) for Trains 1 through 6 of the SPL Project. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion for Trains 1 through 5. After giving effect to an SPA that Cheniere has committed to provide to SPL and upon the date of first commercial delivery of Train 6, the annual fixed fee portion to be paid by the third-party SPA customers is expected to increase to at least $3.3 billion.

In addition, Cheniere Marketing has an agreement with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers. See Marketing section for additional information regarding agreements entered into by Cheniere Marketing.

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of June 30, 2021, SPL had secured up to approximately 5,025 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.

Construction

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the SPL Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 6 of the SPL Project is approximately $2.5 billion, including estimated costs for the third marine berth that is currently under construction. As of June 30, 2021, we have incurred $2.1 billion under this contract.

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. Approximately 2 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Each of Total Gas & Power North America, Inc. (“Total”) and

Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually, prior to inflation adjustments, for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During each of the three months ended June 30, 2021 and 2020, SPL recorded $33 million, and during each of the six months ended June 30, 2021 and 2020, SPL recorded $65 million, as operating and maintenance expense under this partial TUA assignment agreement.

Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to the SPL Project will be financed through project debt and borrowings, cash flows under the SPAs and equity contributions from Cheniere Partners. We believe that with the net proceeds of borrowings, available commitments under the 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities, cash flows from operations and equity contributions from Cheniere Partners, SPL will have adequate financial resources available to meet its currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the SPL Project. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at June 30, 2021 and December 31, 2020 (in millions):


	June 30,		December 31,

	2021		2020
Senior notes (1)	$	17,750	$	17,750

Letters of credit issued (2)	396		413
Available commitments under credit facilities (2)	1,554		1,537
Total capital resources from borrowings and available commitments (3)	$	19,700	$	19,700

(1) Includes SPL’s 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”), 4.500% Senior Secured Notes due 2030 (the “2030 SPL Senior Notes”) and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”), as well as the 2025 CQP Senior Notes, $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”), the 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”) and the 2031 CQP Senior Notes (collectively, the “CQP Senior Notes”).

(2) Consists of 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities.

(3) Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash equivalents.

SPL Senior Notes

The SPL Senior Notes are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2030 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the ‘make-whole’ price (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2030 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes and the 2020 SPL Working Capital Facility. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025 and are fully amortizing according to a fixed sculpted amortization schedule.

During 2021, SPL entered into a series of note purchase agreements for the sale of approximately $347 million aggregate principal amount of the 2037 SPL Private Placement Senior Secured Notes on a private placement basis. The 2037 SPL Private Placement Senior Secured Notes are expected to be issued in the second half of 2021, subject to customary closing conditions, and the net proceeds will be used to strategically refinance a portion of SPL’s outstanding 6.25% SPL Senior Secured Notes due 2022 and pay related fees, costs and expenses. The 2037 SPL Private Placement Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years.

2020 SPL Working Capital Facility

In March 2020, SPL entered into the 2020 SPL Working Capital Facility with aggregate commitments of $1.2 billion, which replaced the $1.2 billion Amended and Restated SPL Working Capital Facility (the “2015 SPL Working Capital Facility”). The 2020 SPL Working Capital Facility is intended to be used for loans to SPL, swing line loans to SPL and the issuance of letters of credit on behalf of SPL, primarily for (1) the refinancing of the 2015 SPL Working Capital Facility, (2) fees and expenses related to the 2020 SPL Working Capital Facility, (3) SPL and its future subsidiaries’ gas purchase obligations and (4) SPL and certain of its future subsidiaries’ general corporate purposes. SPL may, from time to time, request increases in the commitments under the 2020 SPL Working Capital Facility of up to $800 million. As of June 30, 2021 and December 31, 2020, SPL had $804 million and $787 million of available commitments and $396 million and $413 million aggregate amount of issued letters of credit, respectively. As of both June 30, 2021 and December 31, 2020, SPL had no outstanding borrowings under the 2020 SPL Working Capital Facility.

The 2020 SPL Working Capital Facility matures on March 19, 2025, but may be extended with consent of the lenders. The 2020 SPL Working Capital Facility provides for mandatory prepayments under customary circumstances.

The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, satisfaction of a 12-month forward-looking and backward-looking 1.25:1.00 debt service reserve ratio test. The obligations of SPL under the 2020 SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a pari passu basis by a first priority lien with the SPL Senior Notes.

Cheniere Partners

CQP Senior Notes

The CQP Senior Notes are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture, the 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture and the 2031 CQP Senior Notes are further governed by the Fifth Supplemental Indenture. The indentures governing the CQP Senior Notes contain terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2021 for the 2026 CQP Senior Notes, October 1, 2024 for the 2029 CQP Senior Notes and March 1, 2026 for the 2031 CQP Senior Notes, Cheniere Partners may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2021 for the 2026 CQP Senior Notes, October 1, 2024 for the 2029 CQP Senior Notes and March 1, 2024 for the 2031 CQP Senior Notes, Cheniere Partners may redeem up to 35% of the aggregate principal amount of the CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.625% of the aggregate principal amount of the 2026 CQP Senior Notes, 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes and 104.000% of the aggregate principal amount of the 2031 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. Cheniere Partners also may at any time on or after October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes, October 1, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes and March 1, 2026 through the maturity date of March 1, 2031 for the 2031 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.

The CQP Senior Notes are Cheniere Partners’ senior obligations, ranking equally in right of payment with Cheniere Partners’ other existing and future unsubordinated debt and senior to any of its future subordinated debt. In the event that the aggregate amount of Cheniere Partners’ secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on substantially all the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

2019 CQP Credit Facilities

Cheniere Partners has a $750 million revolving credit facility under the 2019 CQP Credit Facilities. Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the SPL Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit. As of both June 30, 2021 and December 31, 2020, Cheniere Partners had $750 million of available commitments and no letters of credit issued or loans outstanding under the 2019 CQP Credit Facilities.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit Cheniere Partners’ ability to make restricted payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.

The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted encumbrances) on substantially all of Cheniere Partners’ and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).

Corpus Christi LNG Terminal

Liquefaction Facilities

We are currently operating three Trains and two marine berths at the CCL Project. We completed construction of Trains 1, 2 and 3 of the CCL Project and commenced commercial operating activities in February 2019, August 2019 and March 2021, respectively.

Separate from the CCH Group, we are also developing Corpus Christi Stage 3 through our subsidiary CCL Stage III, adjacent to the CCL Project. We received approval from FERC in November 2019 to site, construct and operate seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG.

The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal:

•CCL Project—FTA countries and non-FTA countries through December 31, 2050, up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas.

•Corpus Christi Stage 3—FTA countries and non-FTA countries through December 31, 2050 in an amount equivalent to 582.14 Bcf/yr (approximately 11 mtpa) of natural gas.

In December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations separately from long-term authorizations. Accordingly, the DOE amended each of CCL’s long-term authorizations to include short-term export authority, and vacated the short-term orders.

An application was filed in September 2019 to authorize additional exports from the CCL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 108 Bcf/yr of natural gas, for a total CCL Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the CCL Project of the volumes contemplated in the application. In April 2020, the DOE issued an order authorizing CCL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing CCL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the CCL Project from the currently authorized level to approximately 875.16 Bcf/yr was also submitted to the FERC and is currently pending.

Customers

CCL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 18 years (plus extension rights) for Trains 1 through 3 of the CCL Project. Under these SPAs, the customers will purchase LNG from CCL on a free on board (“FOB”) basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in

connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the CCL Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for the applicable Train, as specified in each SPA.

In aggregate, the minimum annual fixed fee portion to be paid by the third-party SPA customers is approximately $1.8 billion for Trains 1 through 3.

In addition, Cheniere Marketing has agreements with CCL to purchase: (1) approximately 15 TBtu per annum of LNG with a term through 2043, (2) any LNG produced by CCL in excess of that required for other customers at Cheniere Marketing’s option and (3) approximately 44 TBtu of LNG with a maximum term up to 2026 associated with the IPM gas supply agreement between CCL and EOG Resources, Inc. See Marketing section for additional information regarding agreements entered into by Cheniere Marketing.

Natural Gas Transportation, Storage and Supply

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing variability in natural gas needs for the CCL Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. As of June 30, 2021, CCL had secured up to approximately 2,980 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.

CCL Stage III has also entered into long-term natural gas supply contracts with third parties, and anticipates continuing to enter into such agreements, in order to secure natural gas feedstock for Corpus Christi Stage 3. As of June 30, 2021, CCL Stage III had secured up to approximately 2,361 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to approximately 15 years, which is subject to the achievement of certain project milestones and other conditions precedent.

A portion of the natural gas feedstock transactions for CCL and CCL Stage III are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.

Construction

CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 3 of the CCL Project under which Bechtel charged a lump sum for all work performed and generally bore project cost, schedule and performance risks unless certain specified events occurred, in which case Bechtel may have caused CCL to enter into a change order, or CCL agreed with Bechtel to a change order.

Final Investment Decision for Corpus Christi Stage 3

FID for Corpus Christi Stage 3 will be subject to, among other things, entering into an EPC contract, obtaining additional commercial support for the project and securing the necessary financing arrangements.

Pipeline Facilities

In November 2019, the FERC authorized CCP to construct and operate the pipeline for Corpus Christi Stage 3. The pipeline will be designed to transport 1.5 Bcf/d of natural gas feedstock required by Corpus Christi Stage 3 from the existing regional natural gas pipeline grid.

Capital Resources

The following table provides a summary of the capital resources of the CCH Group from borrowings and available commitments for the CCL Project, excluding equity contributions from Cheniere, at June 30, 2021 and December 31, 2020 (in millions):



	June 30,		December 31,
	2021		2020
Senior notes (1)	$	7,721	$	7,721

Credit facilities outstanding balance (2)	2,627		2,767
Letters of credit issued (2)	293		293
Available commitments under credit facilities (2)	907		767
Total capital resources from borrowings and available commitments (3)	$	11,548	$	11,548

(1) Includes CCH’s 7.000% Senior Secured Notes due 2024, 5.875% Senior Secured Notes due 2025, 5.125% Senior Secured Notes due 2027, 3.700% Senior Secured Notes due 2029, 4.80% Senior Secured Notes due 2039, 3.925% Senior Secured Notes due 2039 and 3.52% CCH Senior Secured Notes (collectively, the “CCH Senior Notes”).

(2) Includes CCH’s amended and restated credit facility (the “CCH Credit Facility”) and the CCH Working Capital Facility.

(3) Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash equivalents.

CCH Senior Notes

The CCH Senior Notes are jointly and severally guaranteed by CCH’s subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The indentures governing the CCH Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any CCH Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. The covenants included in the respective indentures that govern the CCH Senior Notes are subject to a number of important limitations and exceptions.

The CCH Senior Notes are CCH’s senior secured obligations, ranking senior in right of payment to any and all of CCH’s future indebtedness that is subordinated to the CCH Senior Notes and equal in right of payment with CCH’s other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Notes. The CCH Senior Notes are secured by a first-priority security interest in substantially all of CCH’s and the CCH Guarantors’ assets.

At any time prior to six months before the respective dates of maturity for each of the CCH Senior Notes, CCH may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the appropriate indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time within six months of the respective dates of maturity for each of the CCH Senior Notes, CCH may redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

CCH Credit Facility

CCH has total commitments under the CCH Credit Facility of $6.1 billion. The obligations of CCH under the CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in CCH. As of both June 30, 2021 and December 31, 2020, CCH had no available commitments and $2.6 billion of loans outstanding under the CCH Credit Facility.

The CCH Credit Facility matures on June 30, 2024, with principal payments due quarterly commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following the completion of the CCL Project as defined in the common terms agreement and (2) a set date determined by reference to the date under which a certain LNG buyer linked to the last Train of the CCL Project to become operational is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the completion of Trains 1 through 3 and designed to achieve a minimum projected fixed debt service coverage ratio of 1.50:1.

Under the CCH Credit Facility, CCH is required to hedge not less than 65% of the variable interest rate exposure of its senior secured debt. CCH is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of Trains 1 through 3 of the CCL Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.

CCH Working Capital Facility

CCH has total commitments under the CCH Working Capital Facility of $1.2 billion. The CCH Working Capital Facility is intended to be used for loans to CCH (“CCH Working Capital Loans”) and the issuance of letters of credit on behalf of CCH for certain working capital requirements related to developing and operating the CCL Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the CCH Guarantors. CCH may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility. As of June 30, 2021 and December 31, 2020, CCH had $907 million and $767 million of available commitments and zero and $140 million of loans outstanding under the CCH Working Capital Facility, respectively. CCH had $293 million aggregate amount of issued letters of credit under the CCH Working Capital Facility as of both June 30, 2021 and December 31, 2020.

The CCH Working Capital Facility matures on June 29, 2023, and CCH may prepay the CCH Working Capital Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans”) at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. CCH is required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of CCH under the CCH Working Capital Facility are secured by substantially all of the assets of CCH and the CCH Guarantors as well as all of the membership interests in CCH and each of the CCH Guarantors on a pari passu basis with the CCH Senior Notes and the CCH Credit Facility.

Cheniere

Senior Notes

We have an aggregate principal amount of $2.0 billion of the 4.625% Senior Secured Notes due 2028 (the “2028 Cheniere Senior Notes”), the proceeds of which were used to prepay a portion of the outstanding indebtedness under the Cheniere Term Loan Facility and to pay related fees and expenses. The associated indentures (“Cheniere Indenture”) contain customary terms and events of default and certain covenants that, among other things, limit our ability to create liens or other encumbrances, enter into sale-leaseback transactions and merge or consolidate with other entities or sell all or substantially all of our assets. The Cheniere Indenture covenants are subject to a number of important limitations and exceptions.

At any time prior to October 15, 2023, we may redeem all or a part of the 2028 Cheniere Senior Notes at a redemption price equal to 100% of the aggregate principal amount thereof, plus the “applicable premium” and accrued and unpaid interest, if any, to but not including the date of redemption. We also may, at any time prior to October 15, 2023, redeem up to 40% of the aggregate principal amount of the 2028 Cheniere Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 104.625% of the aggregate principal amount of the notes being redeemed, plus accrued and unpaid interest, if any, to but not including, the date of redemption. At any time on or after October 15, 2023 through the maturity date of October 15, 2028, we may redeem all or part of the 2028 Cheniere Senior Notes at the redemption prices described in the Cheniere Indenture.

The 2028 Cheniere Senior Notes are our general senior obligations and rank senior in right of payment to all of our future obligations that are, by their terms, expressly subordinated in right of payment to the 2028 Cheniere Senior Notes and equally in right of payment with all of our other existing and future unsubordinated indebtedness. The 2028 Cheniere Senior Notes became unsecured in June 2021 concurrent with the repayment of all outstanding obligations under the Cheniere Term Loan Facility and may, in certain instances become secured in the future in connection with the incurrence of additional secured indebtedness by us. When required, the 2028 Cheniere Senior Notes will be secured on a first-priority basis by a lien on substantially all of our assets and equity interests in our direct subsidiaries (other than certain excluded subsidiaries), which liens rank pari passu with the liens securing the Cheniere Revolving Credit Facility. As of June 30, 2021, the 2028 Cheniere Senior Notes are not guaranteed by any of our subsidiaries. In the future, the 2028 Cheniere Senior Notes will be guaranteed by our subsidiaries who guarantee our other material indebtedness.

Convertible Notes

We have $625 million aggregate principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”). We have the right, at our option, at any time after March 15, 2020, to redeem all or any part of the 2045 Cheniere Convertible Senior Notes at a redemption price equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date. Prior to December 15, 2044, the 2045 Cheniere Convertible Senior Notes are convertible only under certain circumstances as specified in the indenture; thereafter, holders may convert their notes regardless of these circumstances. The conversion rate will initially equal 7.2265 shares of our common stock per $1,000 principal amount of the 2045 Cheniere Convertible Senior Notes, which corresponds to an initial conversion price of approximately $138.38 per share of our common stock (subject to adjustment upon the occurrence of certain specified events).

We have the option to satisfy the conversion obligation for the 2045 Cheniere Convertible Senior Notes with cash, common stock or a combination thereof.

Cheniere Revolving Credit Facility

We have total commitments under the Cheniere Revolving Credit Facility of $1.25 billion. The Cheniere Revolving Credit Facility is intended to fund, through loans and letters of credit, equity capital contributions to CCH HoldCo II and its subsidiaries for the development of the CCL Project and, provided that certain conditions are met, for general corporate purposes. As of both June 30, 2021 and December 31, 2020, we had $1.1 billion of available commitments and $134 million and zero, respectively, of loans outstanding under the Cheniere Revolving Credit Facility. We had zero and $124 million aggregate amount of issued letters of credit under the Cheniere Revolving Credit Facility as of June 30, 2021 and December 31, 2020, respectively. In July 2021, the outstanding balance under the Cheniere Revolving Credit Facility was repaid.

The Cheniere Revolving Credit Facility matures on December 13, 2022 and contains representations, warranties and affirmative and negative covenants customary for companies like us with lenders of the type participating in the Cheniere Revolving Credit Facility that limit our ability to make restricted payments, including distributions, unless certain conditions are satisfied, as well as limitations on indebtedness, guarantees, hedging, liens, investments and affiliate transactions. Under the Cheniere Revolving Credit Facility, we are required to ensure that the sum of our unrestricted cash and the amount of undrawn commitments under the Cheniere Revolving Credit Facility is at least equal to the lesser of (1) 20% of the commitments under the Cheniere Revolving Credit Facility and (2) $200 million (the “Liquidity Covenant”). However, at any time that the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit under the Cheniere Revolving Credit Facility is greater than 30% of aggregate commitments under the Cheniere Revolving Credit Facility, the Liquidity Covenant will not apply and we will instead be governed by a quarterly non-consolidated leverage ratio covenant not to exceed 5.75:1.00 (the “Springing Leverage Covenant”).

The Cheniere Revolving Credit Facility is secured by a first priority security interest (subject to permitted liens and other customary exceptions) in substantially all of our assets, including our interests in our direct subsidiaries (excluding CCH HoldCo II and certain other subsidiaries).

Cash Receipts from Subsidiaries

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of June 30, 2021, we owned a 48.6% limited partner interest in Cheniere Partners in the form of 239.9 million common units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners. We are eligible to receive quarterly equity distributions from Cheniere Partners related to our ownership interests and our incentive distribution rights.

We also receive fees for providing management services to some of our subsidiaries. We received $57 million and $53 million in total service fees from these subsidiaries during the six months ended June 30, 2021 and 2020, respectively.

Share Repurchase Program

On June 3, 2019, we announced that our Board authorized a 3-year, $1.0 billion share repurchase program. During the six months ended June 30, 2020, we repurchased an aggregate of 2.9 million shares of our common stock for $155 million, for a weighted average price per share of $53.88. We did not make any repurchases during the three months ended June 30, 2021 and 2020 or the six months ended June 30, 2021. As of June 30, 2021, we had $596 million of the share repurchase program available. Under the share repurchase program, repurchases can be made from time to time using a variety of methods, which may include open market purchases, privately negotiated transactions or otherwise, all in accordance with the rules of the SEC and other applicable legal requirements. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by our management based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and may be modified, suspended or discontinued at any time or from time to time at our discretion.

Marketing

We market and sell LNG produced by the Liquefaction Projects that is not required for other customers through our integrated marketing function. We have, and continue to develop, a portfolio of long-, medium- and short-term SPAs to transport and unload commercial LNG cargoes to locations worldwide. These volumes are expected to be primarily sourced by LNG produced by the Liquefaction Projects but supplemented by volumes procured from other locations worldwide, as needed. As of June 30, 2021, we have sold or have options to sell approximately 5,002 TBtu of LNG to be delivered to customers between 2021 and 2045, including volume from an SPA Cheniere Marketing has committed to provide to SPL. The cargoes have been sold either on a FOB basis (delivered to the customer at the Sabine Pass LNG terminal or the Corpus Christi LNG terminal, as applicable) or a delivered at terminal (“DAT”) basis (delivered to the customer at their specified LNG receiving terminal). We have chartered LNG vessels to be utilized for cargoes sold on a DAT basis.

Cheniere Marketing has uncommitted trade finance facilities with available credit of $240 million as of June 30, 2021, primarily to be used for the purchase and sale of LNG for ultimate resale in the course of its operations. The finance facilities are intended to be used for advances, guarantees or the issuance of letters of credit or standby letters of credit on behalf of Cheniere Marketing. As of June 30, 2021 and December 31, 2020, Cheniere Marketing had $5 million and $34 million, respectively, in standby letters of credit and guarantees outstanding under the finance facilities. As of June 30, 2021 and December 31, 2020, there were $30 million and zero loans outstanding, respectively, under the finance facilities. Cheniere Marketing pays interest or fees on utilized commitments.

Cheniere Marketing also has an uncommitted letter of credit facility with no available credit as of June 30, 2021, for the issuance of letters of credit in the course of its operations. As of June 30, 2021, Cheniere Marketing had $35 million of letters of credit issued under the facility. Cheniere Marketing pays fees on utilized commitments.

Corporate and Other Activities

We are required to maintain corporate and general and administrative functions to serve our business activities described above. The development of our 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 an FID.

We have made an equity investment in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“the Midship Pipeline”). Midship Pipeline operates the Midship Project with current capacity of up to 1.1 million Dekatherms per day that connects new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the Liquefaction Projects. The Midship Project was placed in service in April 2020.

Restrictive Debt Covenants

As of June 30, 2021, each of our issuers was in compliance with all covenants related to their respective debt agreements.

LIBOR

The use of LIBOR is expected to be phased out by June 2023. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue working with our lenders and counterparties to pursue any amendments to our debt and derivative agreements that are currently subject to LIBOR following LIBOR cessation and will continue to monitor, assess and plan for the phase out of LIBOR.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the six months ended June 30, 2021 and 2020 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.


	Six Months Ended June 30,
	2021		2020
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	1,373	$	1,028
Proceeds from sale of fixed assets	68		—
Proceeds from issuances of debt	2,184		2,597
Other	8		—
	$	3,633	$	3,625
Uses of cash, cash equivalents and restricted cash:
Property, plant and equipment	$	(440)	$	(983)
Investment in equity method investment	—		(100)
Repayments of debt	(2,603)		(2,380)
Debt issuance and other financing costs	(20)		(59)
Debt modification or extinguishment costs	(41)		(40)

Distributions to non-controlling interest	(322)		(310)
Payments related to tax withholdings for share-based compensation	(43)		(41)
Repurchase of common stock	—		(155)
Other	(11)		(7)
	(3,480)		(4,075)
Net increase (decrease) in cash, cash equivalents and restricted cash	$	153	$	(450)

Operating Cash Flows

Our operating cash net inflows during the six months ended June 30, 2021 and 2020 were $1,373 million and $1,028 million, respectively. The $345 million increase in operating cash inflows in 2021 compared to 2020 was primarily related to increased cash receipts from the sale of LNG cargoes due to higher revenue per MMBtu and higher volume of LNG delivered, as well as from higher than normal contributions from LNG and natural gas portfolio optimization activities due to significant volatility in LNG and natural gas markets during the six months ended June 30, 2021. Partially offsetting these operating cash inflows were higher operating cash outflows due to higher natural gas feedstock costs and payment of paid-in-kind interest on our convertible notes.

Proceeds from Sale of Fixed Assets

During the six months ended June 30, 2021, we received proceeds from the sale of fixed assets of $68 million from divestment of non-core land holdings.

Proceeds from Issuance of Debt, Repayments of Debt, Debt Issuance and Other Financing Costs and Debt Modification or Extinguishment Costs

During the six months ended June 30, 2021, Cheniere Partners issued an aggregate principal amount of $1.5 billion of the 2031 CQP Senior Notes and incurred $20 million of debt issuance costs related to this issuance. The proceeds from this issuance, together with cash on hand, were used to redeem all of the outstanding 2025 CQP Senior Notes, and Cheniere Partners paid $40 million of debt extinguishment costs, mainly related to premiums associated with this redemption. Additionally, in line with our previously announced capital allocation priorities, we repaid $624 million of total outstanding indebtedness under the Cheniere Term Loan Facility and 2021 Cheniere Convertible Notes with $500 million of available cash and the remainder from borrowings under the Cheniere Revolving Credit Facility. We paid $2 million of debt extinguishment costs as a result of the repayment of the 2021 Cheniere Convertible Notes. Additionally, net repayments of $100 million were made on our credit facilities during the six months ended June 30, 2021.

During the six months ended June 30, 2020, SPL issued an aggregate principal amount of $2.0 billion of the 2030 SPL Senior Notes, which along with cash on hand was used to redeem all of the outstanding 2021 SPL Senior Notes. During the six months ended June 30, 2020, borrowings of $0.6 billion under our credit facilities were used to redeem the 11% Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes”), to fund our working capital requirements or for general corporate purposes. We incurred $59 million of debt issuance costs primarily related to up-front fees paid upon the closing of the 2020 SPL Working Capital Facility and 2030 SPL Senior Notes and premiums paid for partially redeeming the 2025 CCH HoldCo II Convertible Senior Notes. We incurred $40 million of debt extinguishment costs primarily related to the redemption of the 2021 SPL Senior Notes.

Property, Plant and Equipment

Cash outflows for property, plant and equipment were primarily for the construction costs for the Liquefaction Projects. These costs are capitalized as construction-in-process until achievement of substantial completion.

Distributions to Non-controlling Interest

We own a 48.6% limited partner interest in Cheniere Partners, with the remaining non-controlling interest held by The Blackstone Group Inc., Brookfield Asset Management Inc. and the public, to whom Cheniere Partners paid distributions during the three and six months ended June 30, 2021 and 2020.

Repurchase of Common Stock

During the six months ended June 30, 2020, we paid $155 million to repurchase approximately 2.9 million shares of our common stock under the share repurchase program. There were no share repurchases paid in cash during the six months ended June 30, 2021.

Off-Balance Sheet Arrangements

As of June 30, 2021, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

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, 2020.

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, the CCL Project and potential future development of Corpus Christi Stage 3 (“Liquefaction Supply Derivatives”). We have also entered into physical and financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):


	June 30, 2021				December 31, 2020
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(197)	$	246	$	240	$	204
LNG Trading Derivatives	(401)		49		(134)		44

See Note 6—Derivative Instruments for additional details about our derivative instruments.

Interest Rate Risk

We are exposed to interest rate risk primarily when we incur debt related to project financing. Interest rate risk is managed in part by replacing outstanding floating-rate debt with fixed-rate debt with varying maturities. CCH has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the CCH Credit Facility (“CCH Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the CCH Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward one-month LIBOR curve across the remaining terms of the CCH Interest Rate Derivatives as follows (in millions):


	June 30, 2021				December 31, 2020
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
CCH Interest Rate Derivatives	$	(91)	$	1	$	(140)	$	1

See Note 6—Derivative Instruments for additional details about our 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):


	June 30, 2021				December 31, 2020
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
FX Derivatives	$	(4)	$	—	$	(22)	$	2

See Note 6—Derivative Instruments for additional details about our derivative instruments.

ITEM 4. CONTROLS AND PROCEDURES

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

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

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, 2020.

In February 2018, the Pipeline and Hazardous Materials Safety Administration (“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. 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. We continue to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak, 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, 2020.

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 June 30, 2021:


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)
April 1 - 30, 2021	4,734	$72.83	—	$595,952,809
May 1 - 31, 2021	2,624	$77.52	—	$595,952,809
June 1 - 30, 2021	—	$—	—	$595,952,809
Total	7,358	$74.50	—

(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 June 3, 2019, we announced that our Board authorized a 3-year, $1 billion share repurchase program. For additional information, see Share Repurchase Program in Liquidity and Capital Resources.

ITEM 6. EXHIBITS

Exhibit No.

Description

10.1*†

Form of Restricted Stock Grant under the Cheniere 2020 Incentive Plan (Director)

10.2*

Fourth Amendment to Common Security and Account Agreement, dated as of April 1, 2021, among CCH, CCL, CCP and Corpus Christi Pipeline GP, LLC, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank.

10.3*

Sixth Amendment to the Amended and Restated Common Terms Agreement, dated as of April 1, 2021, by and among CCH, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as the Term Loan Facility Agent, The Bank of Nova Scotia as the Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent

10.4*

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-000 43 Third Berth SVT Loading Arm Spares , dated April 9 , 202 1 , (ii) the Change Order CO-000 44 Third Berth U/G Directional Drilling & Cathodic Protection Provisional Sum Closures , dated April 9 , 202 1 , (iii) the Change Order CO-000 45 Winter Storm Impacts , dated Ap ril 9 , 202 1, (i v ) the Change Order CO-00046 NGPL Security Provisional Sum Interim Adjustment, dated J une 15, 2021, (v) the Change Order CO-0004 7 80 Acres Bridge, dated June 15, 2021 and (vi) the Change Order CO-0004 8 A GRU Additions for Lean Solvent O verpressur e, dated June 15, 20 2 1

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.
†			Management contract or compensatory plan or arrangement.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		CHENIERE ENERGY, INC.







Date:	August 4, 2021	By:	/s/ Zach Davis
			Zach Davis
			Senior Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)

Date:	August 4, 2021	By:	/s/ Leonard E. Travis
			Leonard E. Travis
			Senior Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

Exhibit 10.1

CHENIERE ENERGY, INC.

2020 INCENTIVE PLAN

RESTRICTED STOCK GRANT

1. Grant of Restricted Shares. Cheniere Energy, Inc., a Delaware corporation (the “Company”), hereby grants to ________________ (“Participant”) all rights, title and interest in the record and beneficial ownership of ____________ (______) shares (the “Restricted Shares”) of common stock, $0.003 par value per share, of the Company (“Common Stock”), under the Company’s 2020 Incentive Plan (as amended or restated from time to time, the “Plan”), subject to the conditions described in this grant of Restricted Stock (the “Grant”) and the Plan. The Restricted Shares are granted, effective as of the ___ day of _____, 20__ (the “Grant Date”). Unless otherwise defined in this Grant, capitalized terms used herein shall have the meanings assigned to them in the Plan.

2. Effect of the Plan. The Restricted Shares granted to Participant are subject to all of the provisions of the Plan and this Grant, together with all of the rules and determinations from time to time issued by the Committees and by the Board pursuant to the Plan; provided, however, that in the event of a conflict between any provision of the Plan and this Grant document, the provisions of this Grant document shall control but only to the extent such conflict is permitted under the Plan. The Company hereby reserves the right to amend, modify, restate, supplement or terminate the Plan without the consent of Participant, so long as such amendment, modification, restatement or supplement shall not materially reduce the rights and benefits available to Participant hereunder, and this Grant shall be subject, without further action by the Company or Participant, to such amendment, modification, restatement or supplement unless provided otherwise therein.

3. Issuance and Transferability. The Restricted Shares may be evidenced in such manner as the Company shall deem appropriate, including, without limitation, book-entry registration with the Company’s transfer agent or issuance of a stock certificate or certificates. In the event any stock certificate is issued in respect of the Restricted Shares, such certificate shall be registered in the name of the Participant and shall bear an appropriate legend referring to the terms, conditions and restrictions applicable to such Restricted Shares and shall be held by the Company or by an escrow agent designated by the Company until the forfeiture restrictions described in Section 4 expire and all required withholding obligations as described in Section 11 of this Grant and the provisions of the Plan

have been satisfied. Except as otherwise provided in Section 6, the Participant shall have all the rights of a stockholder with respect to the Restricted Shares, including the right to vote and the right to receive dividends or other distributions paid or made with respect to such shares. The Restricted Shares are not transferable except by will or the laws of descent and distribution or as otherwise permitted under Section 16(g) of the Plan. References to Participant, to the extent relevant in the context, shall include references to authorized transferees. Any transfer in violation of this Section 3 shall be void and of no force or effect, and shall result in the immediate forfeiture of all unvested Restricted Shares. No right or benefit hereunder shall in any manner be subject to any debts, contracts, liabilities, or torts of Participant or otherwise made subject to execution, attachment or similar process except as provided in Section 16(g) of the Plan.

4. Risk of Forfeiture. Except as otherwise provided herein, Participant shall, without further action of any kind by the Company or Participant, immediately forfeit all rights to any non-vested portion of the Restricted Shares in the event Participant ceases to serve as a Director of the Company (whether due to resignation, removal, not being re-elected by the stockholders or not standing for re-election or otherwise). Restricted Shares that are forfeited shall be deemed to be immediately transferred to the Company without any payment by the Company or action by Participant, and the Company shall have the full and absolute right to cancel any evidence of Participant’s ownership of such forfeited Restricted Shares and to take any other action necessary to demonstrate the Participant no longer owns such forfeited Restricted Shares. Following any such forfeiture, Participant shall have no further rights with respect to the forfeited Restricted Shares. Participant, by his or her acceptance of this Grant, irrevocably grants to the Company a power of attorney to transfer Restricted Shares that are forfeited to the Company and agrees to execute any documents requested by the Company in connection with such forfeiture and transfer.

5. Vesting. The Restricted Shares shall vest and the forfeiture restrictions shall lapse as set forth on Exhibit A, provided that Participant remains continuously engaged as a Director of the Company. If Participant no longer serves as a Director of the Company, any Restricted Shares not then vested shall not vest (except as otherwise provided herein) and shall be forfeited back to the Company; provided, however, that any such Restricted Shares not then vested shall vest (i) in the event that on or within one (1) year after the effective date of a Change of Control, Participant ceases to serve as a Director of the

Company (whether due to resignation, removal, not being re-elected by the stockholders or not standing for re-election or otherwise) other than due to removal for Cause, (ii) upon the death or Disability of Participant, (iii) if Participant retires as a Director of the Company as a result of the mandatory director retirement policy adopted by the Board, as in effect from time to time, or (iv) as to a pro rata portion of such Restricted Shares if, other than on or within one (1) year after the effective date of a Change of Control, Participant’s service as a Director of the Company terminates (A) upon the request of the Board, including as a result of Board refreshment or retirement initiatives or (B) in the case of a Director designated to serve on the Board on behalf of a Company shareholder, upon the removal or replacement by, or upon the request of, such shareholder and, in each case, where the Director has not engaged in action that would result in removal for Cause, with such proration determined based on the number of days following the grant date during which the Participant served as a Director of the Company, relative to the total number of days in the applicable vesting period.

6. Ownership Rights. Subject to the restrictions set forth in this Grant and the Plan, Participant is entitled to all voting and ownership rights applicable to the Restricted Shares, including the right to receive any cash dividends that may be paid on the Restricted Shares. Notwithstanding the foregoing, (a) any cash dividends with respect to unvested Restricted Shares shall be payable upon and subject to the vesting of the underlying Restricted Shares (and Participant shall forfeit and not be paid any such dividends in respect of Restricted Shares which are forfeited back to the Company); (b) the Committee may direct that from the time of payment of any dividend to the Company's shareholders generally until payment that dividends be (i) held in cash, with or without interest accrual, or (ii) converted into restricted stock units; (c) the dividends may be paid in the form of cash or shares of Common Stock as determined by the Committee; and (d) the dividends are intended to be exempt from Section 409A of the Internal Revenue Code and this Grant shall be interpreted accordingly.

7. Reorganization of the Company. Subject to Section 15 of the Plan, the existence of this Grant shall not affect in any way the right or power of the Company or its stockholders to make or authorize any or all adjustments, recapitalizations, reorganizations or other changes in the Company’s capital structure or its business; any merger or consolidation of the Company; any issue of bonds, debentures, preferred or prior preference stock ahead of or affecting the Restricted Shares or the rights thereof; the

dissolution or liquidation of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding, whether of a similar character or otherwise.

8. Recapitalization Events. In the event of stock dividends, spin-offs of assets or other extraordinary dividends, stock splits, combinations of shares, recapitalizations, mergers, consolidations, reorganizations, liquidations, issuances of rights or warrants and similar transactions or events involving the Company as contemplated by the Plan (“Recapitalization Events”), adjustments shall be made with respect to the Restricted Shares to the extent provided for in the Plan and then for all purposes references herein to Common Stock or to Restricted Shares shall mean and include all securities or other property (other than cash) that holders of Common Stock of the Company are entitled to receive in respect of Common Stock by reason of each successive Recapitalization Event, which securities or other property (other than cash) shall be treated in the same manner and shall be subject to the same restrictions as the underlying Restricted Shares.

9. Certain Restrictions. By accepting this Grant, Participant acknowledges that he or she has received a copy of the Plan and agrees that Participant will enter into such written representations, warranties and agreements and execute such documents as the Company may reasonably request in order to comply with applicable securities and other applicable laws, rules or regulations, or with this document or the terms of the Plan.

10. Amendment and Termination; Waiver. This Grant, together with the Plan, constitutes the entire agreement by the Participant and the Company with respect to the subject matter hereof, and supersedes any and all prior agreements or understandings between the Participant and the Company with respect to the subject matter hereof, whether written or oral. Except as provided otherwise in Section 2, no amendment or termination of this Grant shall be made by the Company at any time without the written consent of Participant. Any provision for the benefit of the Company contained in this Grant may be waived in writing, either generally or in any particular instance, by the Company. A waiver on one occasion shall not be deemed to be a waiver of the same or any other breach on a future occasion.

11. Withholding of Taxes. All payments under the terms of the Grant shall be subject to, and

reduced by any amount of federal, state and local income, employment and other taxes, if any, required to be withheld by the Company in connection with such payments. Participant agrees that, if he or she makes a timely election under Section 83(b) of the Internal Revenue Code of 1986, as amended, with regard to the Restricted Shares, Participant will so notify the Company in writing at the time Participant makes such election and provide a copy thereof to the Company, so as to enable the Company to timely comply with any applicable governmental reporting requirements and any required withholding obligations. The Company shall have the right to take any action as may be necessary or appropriate to satisfy any required federal, state or local tax withholding obligations.

12. No Guarantee of Tax Consequences. The Grant is intended to be exempt from or to comply with the requirements of Section 409A of the Code and the Grant shall be interpreted accordingly. The Company makes no commitment or guarantee to Participant that any federal or state tax treatment will apply or be available to any person eligible for benefits under this Grant.

13. Severability; Interpretive Matters. In the event that any provision of this Grant shall be held illegal, invalid, or unenforceable for any reason, such provision shall be fully severable and shall not affect the remaining provisions of this Grant, and the Grant shall be construed and enforced as if the illegal, invalid, or unenforceable provision had never been included herein. Whenever required by the context, pronouns and any variation thereof shall be deemed to refer to the masculine, feminine, or neuter, and the singular shall include the plural, and vice versa. The captions and headings used in the Grant are inserted for convenience and shall not be deemed a part of the Grant granted hereunder for construction or interpretation.

14. Crediting Par Value. In connection with the issuance of the Restricted Shares pursuant to this Grant and as a result of the expectations of the Company and Participant of Participant’s performance of future services for the Company or an Affiliate, the Company will transfer from surplus to stated capital the aggregate par value of the Restricted Shares.

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

16. No Right To Continued Services. Nothing in this Grant shall confer upon the Participant any right to continued service with the Company (or its Affiliates or their respective successors) or to interfere in any way with the right of the Company (or its Affiliates or their

respective successors) to terminate the Participant’s service at any time.

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

[Remainder of Page Intentionally Blank]

IN WITNESS WHEREOF, the Company has executed the Grant as of the date first above written.


CHENIERE ENERGY, INC.


By:
			Name:
			Title:

Accepted the ______ day of , 20__.

PARTICIPANT:


By:
Address:

Exhibit 10.2

FOURTH AMENDMENT TO

COMMON SECURITY AND ACCOUNT AGREEMENT

This Fourth Amendment, dated as of April 1, 2021 (the “Fourth Amendment”), amends the Amended and Restated Common Security and Account Agreement, dated as of May 22, 2018 (as amended by the First Amendment, dated as of November 28, 2018, the Second Amendment, dated as of August 30, 2019, the Third Amendment, dated as of November 16, 2020, and as further amended, amended and restated, modified or supplemented from time to time, the “Common Security and Account Agreement”), by and among Cheniere Corpus Christi Holdings, LLC (the “Company”), Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P. and Corpus Christi Pipeline GP, LLC (the “Guarantors” and, together with the Company, the “Securing Parties”), the Senior Creditor Group Representatives party thereto and that accede thereto from time to time, for the benefit of all Senior Creditors, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Common Security and Account Agreement.

WHEREAS, pursuant to Schedule A (Common Definitions and Rules of Interpretation – Interpretation), any Gas Hedging Instrument entered into by a Loan Party must meet certain criteria to be permitted under the Finance Documents and, to reflect the needs of the Project, the Loan Parties wish to enter into this Fourth Amendment in order to increase the maximum term for Index Swaps for permitted Gas Hedging Instruments;

WHEREAS, pursuant to Section 12.14(a) (Amendments) of the Common Security and Account Agreement, the Security Trustee may execute this amendment with the consent of the Intercreditor Agent pursuant to Section 7.2(a)(i) (Modification Approval Levels – Modifications to this Agreement) thereof; and

WHEREAS, pursuant to the Intercreditor Agreement, the Requisite Intercreditor Parties have authorized the Intercreditor Agent to instruct the Security Trustee to amend the Common Security and Account Agreement as set forth herein.

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

Section 1. Amendment to Common Security and Account Agreement. The Company, the Guarantors and the Security Trustee each agree that the Common Security and Account Agreement is hereby amended by amending the following definition in Schedule A (Common Definitions and Rules of Interpretation – Interpretation) by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

Hedging Instrument, (ii) if secured, is of the type referred to in clause (a) or (b) of the definition of Hedging Instrument and (iii) is entered for non-speculative purposes and is on arm’s-length terms; provided that (a) if such Hedging Instrument is a Gas Hedging Instrument, Permitted Hedging Instruments are limited to the following: (1) Futures Contracts, Fixed-Floating Futures Swaps, NYMEX Natural Gas Futures Contracts and Swing Swaps for gas hedging purposes for up to a maximum of 72.5 TBtu of gas utilizing intra-month and up to three prompt month contracts, (2) Index Swaps for gas hedging purposes for up to a maximum of 34.9 TBtu per month of gas utilizing up to three twenty four prompt month contracts, and (3) Basis Swaps for gas hedging purposes for up to a maximum of 34.9 TBtu per month with a tenor up to 36 months, where the limitations in each of the categories described in sub-clauses (1), (2) and (3) are not aggregated, and (b) if such Hedging Instrument is a Power Hedging Instrument, the aggregate quantum under such Hedging Instrument does not exceed 3,650,000 megawatt hours and each such Hedging Instrument is for a period not to exceed sixty months where the first month is the month in which the power hedging contract is executed. “Permitted Hedging Instrument” includes any “Permitted Senior Debt Hedging Instrument.”

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

Section 3. Finance Document. This Fourth Amendment constitutes a Finance Document as such term is defined in, and for purposes of, the Amended and Restated Common Terms Agreement, dated as of May 22, 2018, as amended by the First Amendment, dated as of November 28, 2018, the Second Amendment, dated as of August 30, 2019, the Third Amendment, dated as of November 8, 2019, the Fourth Amendment, dated as of November 26, 2019, the Fifth Amendment, dated as of November 30, 2020, and as further amended, amended and restated, modified or supplemented from time to time, by and among the Securing Parties, Société Générale as the Term Loan Facility Agent, The Bank of Nova Scotia as the Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders and Société Générale as the Intercreditor Agent.

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

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

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

Section 7. Counterparts. This Fourth Amendment may be executed, manually or electronically, in multiple counterparts, each of which shall be deemed an original for all purposes, but all of which together shall constitute one and the same instrument. Delivery of an executed counterpart of a signature page of this Fourth Amendment by facsimile or in electronic document format (e.g., “pdf” or “tif”) shall be effective as delivery of a manually executed counterpart of this Fourth Amendment.

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

Section 9. Electronic Execution of Documents. The words “execution,” “execute”, “signed,” “signature,” and words of like import in or related to any document to be signed in connection with this Fourth Amendment and the transactions contemplated hereby shall be deemed to include electronic signatures, the electronic matching of assignment terms and contract formations on electronic platforms, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.

[Signature pages follow]

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


CHENIERE CORPUS CHRISTI HOLDINGS, LLC, as the Company


By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer


CORPUS CHRISTI LIQUEFACTION, LLC, as Guarantor


By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer


CHENIERE CORPUS CHRISTI PIPELINE, L.P., as Guarantor


By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer


CORPUS CHRISTI PIPELINE GP, LLC, as Guarantor


By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer

SIGNATURE PAGE TO FOURTH AMENDMENT TO

CCH A&R COMMON SECURITY AND ACCOUNT AGREEMENT

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


SOCIÉTÉ GÉNÉRALE, as Security Trustee


By:			/s/ Karla Navas
Name:			Karla Navas
Title:			Vice President

SIGNATURE PAGE TO FOURTH AMENDMENT TO

CCH A&R COMMON SECURITY AND ACCOUNT AGREEMENT

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


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


By:			/s/ Karla Navas
Name:			Karla Navas
Title:			Vice President

SIGNATURE PAGE TO FOURTH AMENDMENT TO

CCH A&R COMMON SECURITY AND ACCOUNT AGREEMENT

Exhibit 10.3

SIXTH AMENDMENT

TO COMMON TERMS AGREEMENT

This Sixth Amendment, dated as of April 1, 2021 (the “Sixth Amendment”), amends the Amended and Restated Common Terms Agreement, dated as of May 22, 2018 (as amended by the First Amendment, dated as of November 28, 2018, the Second Amendment, dated as of August 30, 2019, the Third Amendment, dated as of November 8, 2019, the Fourth Amendment, dated as of November 26, 2019, the Fifth Amendment, dated as of November 16, 2020 and as further amended, amended and restated, modified or supplemented from time to time, the “Common Terms Agreement”), by and among Cheniere Corpus Christi Holdings, LLC (the “Borrower”), Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P. and Corpus Christi Pipeline GP, LLC (the “Guarantors” and, together with the Borrower, the “Loan Parties”), Société Générale as the Term Loan Facility Agent, The Bank of Nova Scotia as the Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Common Terms Agreement.

WHEREAS, pursuant to Schedule A (Common Definitions and Rules of Interpretation – Interpretation) to the Common Terms Agreement, any Gas Hedging Instrument entered into by a Loan Party must meet certain criteria to be permitted under the Finance Documents and, to reflect the needs of the Project, the Loan Parties wish to enter into this Sixth Amendment in order to increase the maximum term for Index Swaps for gas hedging purposes;

WHEREAS, pursuant to Section 2.1 (Operational Property Damage Insurance) of Schedule L to the Common Terms Agreement, the Loan Parties are required to maintain, among other things, Operational Property Damage Insurance with a deductible for losses other than Windstorm not to exceed $50 million per occurrence;

WHEREAS, pursuant to that certain letter, dated March 16, 2021 from the Insurance Advisor to the Intercreditor Agent, Security Trustee, Term Loan Facility Agent, Working Capital Facility Agent and Indenture Trustee, it is the opinion of the Insurance Advisor that an increase of the allowable property damage deductible in respect of losses other than Windstorm from $50 million to $75 million per occurrence is consistent with deductibles customarily carried by companies engaged in similar businesses as the Borrower, and consequently the Loan Parties wish to enter into this Sixth Amendment to the Common Terms Agreement in order to increase the allowable property damage deductible in respect of losses other than Windstorm from $50 million to $75 million per occurrence; and

WHEREAS, the Intercreditor Agent is executing this amendment as set forth herein pursuant to Section 23.16 (Amendments) of the Common Terms Agreement, Section 10.01 (Decisions; Amendments, Etc.) of the Term Loan Facility Agreement, Section 11.01 (Decisions; Amendments, Etc.) of the Working Capital Facility Agreement, Section 3 (Voting and Decision Making) and Section 4 (Modifications; Instructions; Other Relationships) of the Intercreditor Agreement.

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

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

(a) amending the following definition in Schedule A (Common Definitions and Rules of Interpretation – Interpretation) by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

“Permitted Hedging Instrument” means a Hedging Instrument entered into by a Loan Party in the ordinary course of business and that (i) is with a Hedging Bank, a Gas Hedge Provider, a Power Hedge Provider or any other party that is a counterparty to a Hedging Instrument, (ii) if secured, is of the type referred to in clause (a) or (b) of the definition of Hedging Instrument and (iii) is entered for non-speculative purposes and is on arm’s-length terms; provided that (a) if such Hedging Instrument is a Gas Hedging Instrument, Permitted Hedging Instruments are limited to the following: (1) Futures Contracts, Fixed-Floating Futures Swaps, NYMEX Natural Gas Futures Contracts and Swing Swaps for gas hedging purposes for up to a maximum of 72.5 TBtu of gas utilizing intra-month and up to three prompt month contracts, (2) Index Swaps for gas hedging purposes for up to a maximum of 34.9 TBtu per month of gas utilizing up to three twenty four prompt month contracts, and (3) Basis Swaps for gas hedging purposes for up to a maximum of 34.9 TBtu per month with a tenor up to 36 months, where the limitations in each of the categories described in sub-clauses (1), (2) and (3) are not aggregated, and (b) if such Hedging Instrument is a Power Hedging Instrument, the aggregate quantum under such Hedging Instrument does not exceed 3,650,000 megawatt hours and each such Hedging Instrument is for a period not to exceed sixty months where the first month is the month in which the power hedging contract is executed. “Permitted Hedging Instrument” includes any “Permitted Senior Debt Hedging Instrument.”

(b) amending the “Deductible” section in Section 2.1 (Operational Property Damage Insurance) of Schedule L (Schedule of Minimum Insurance) by inserting the double-underlined text (example: double-underlined text) and deleting the stricken text (example: stricken text) as set forth below:

Deductible: Not to exceed:

(1) For Windstorm, 5% percent of the values at risk at time of loss subject to a maximum of $75 million; and

(2) In respect of all other losses, not exceeding $5075 million per occurrence.

Section 3. Effectiveness. This Sixth Amendment shall be effective upon (x) the receipt by the Intercreditor Agent of executed counterparts of this Sixth Amendment by the Borrower and each Guarantor and (y) the execution of this Sixth Amendment by the Intercreditor Agent.

Section 4. Finance Document. This Sixth Amendment constitutes a Finance Document as such term is defined in, and for purposes of, the Common Terms Agreement.

Section 5. GOVERNING LAW. THIS Sixth AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, UNITED STATES WITHOUT REGARD TO CONFLICTS OF LAWS PRINCIPLES THEREOF THAT WOULD RESULT IN THE APPLICATION OF THE LAW OF ANY OTHER JURISDICTION.

Section 6. Headings. All headings in this Sixth Amendment are included only for convenience and ease of reference and shall not be considered in the construction and interpretation of any provision hereof.

Section 7. Binding Nature and Benefit. This Sixth Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted transfers and assigns.

Section 8. Counterparts. This Sixth Amendment may be executed, manually or electronically, in multiple counterparts, each of which shall be deemed an original for all purposes, but all of which together shall constitute one and the same instrument. Delivery of an executed counterpart of a signature page of this Sixth Amendment by facsimile or in electronic document format (e.g., “pdf” or “tif”) shall be effective as delivery of a manually executed counterpart of this Sixth Amendment.

Section 9. No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Common Terms Agreement shall continue unchanged and shall remain in full force and effect. Each amendment granted herein shall apply solely to the matters set forth herein and such amendment shall not be deemed or construed as an amendment of any other matters, nor shall such amendment apply to any other matters.

Section 10. Electronic Execution of Documents. The words “execution,” “execute”, “signed,” “signature,” and words of like import in or related to any document to be signed in connection with this Sixth Amendment and the transactions contemplated hereby shall be deemed to include electronic signatures, the electronic matching of assignment terms and contract formations on electronic platforms, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the

New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.

[Signature pages follow]

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


CHENIERE CORPUS CHRISTI HOLDINGS, LLC, as the Borrower


By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer


CORPUS CHRISTI LIQUEFACTION, LLC, as Guarantor


By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer


CHENIERE CORPUS CHRISTI PIPELINE, L.P., as Guarantor


By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer


CORPUS CHRISTI PIPELINE GP, LLC, as Guarantor


By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer

SIGNATURE PAGE TO SIXTH AMENDMENT TO CCH A&R COMMON TERMS AGREEMENT

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


SOCIÉTÉ GÉNÉRALE, as Intercreditor Agent on behalf of itself, each Facility Agent and the Requisite Intercreditor Parties
By:			/s/ Karla Navas
Name:			Karla Navas
Title:			Vice President

SIGNATURE PAGE TO SIXTH AMENDMENT TO CCH A&R COMMON TERMS AGREEMENT

Exhibit 10.4

CHANGE ORDER

Third Berth SVT Loading Arm Spares


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-00043 DATE OF CHANGE ORDER: April 9, 2021

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

1.In accordance with Section 3.4 (Spare Parts) and Section 6.1 of the Agreement (Change Orders Requested by Owner), and pursuant to Owner's request via Letter No. SPL4-BE-C20-058, dated 24 November 2020, the Parties agree this Change Order includes Contractor's costs to engineer and procure SVT loading arm spares and associated one (1) Contractor-supplied pressure transmitter for the Third Berth Project. This Change Order excludes any ancillary bulks required to install the spare loading arms.

2.The SVT redacted proposal with equipment list is provided in Exhibit C of this Change Order.

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

4.Schedule C-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)	$	12,798,754
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,029,691,327
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	$	2,029,691,327

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)	$	(6,158,350)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	451,537,650
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	1,590,204
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	453,127,854

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)	$	2,481,228,977
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	1,590,204
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,482,819,181

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 of this Change Order.

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

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

Select either A or B:

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

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

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


/s/ David Craft						/s/ Kane McIntosh
Owner						Contractor
David Craft						Kane McIntosh
Name						Name
SVP E&C						Senior Project Manager
Title						Title
April 20, 2021						April 9, 2021
Date of Signing						Date of Signing

CHANGE ORDER

Third Berth U/G Directional Drilling & Cathodic Protection Provisional Sum Closures


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-00044 DATE OF CHANGE ORDER: April 9, 2021

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

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order removes the U/G Directional Drilling Provisional Sum and Cathodic Protection Provisional Sum from Contractor's Scope of Work as described in Sections 2.8 and 2.9 of Schedule EE-4 of Attachment EE of the Agreement (Provisional Sums to be Adjusted during Project Execution for Subproject 6(b)).

2.The original value of the U/G Directional Drilling Provisional Sum specified in Article 2.8 of Schedule EE-4 of Attachment EE of the Agreement was Three Hundred Thousand U.S. Dollars (U.S. $300,000). Actual costs for the U/G Directional Drilling Provisional Sum was Zero U.S. Dollars (U.S. $0.00). By way of this Change Order, the U/G Directional Drilling Provisional Sum and Contract Price will be decreased by Three Hundred Eighteen Thousand U.S. Dollars (U.S. $318,000), which reflects the closure of the U/G Directional Drilling Provisional Sum and credit for the six percent (6%) fee.

3.The original value of the Cathodic Protection Provisional Sum specified in Article 2.9 of Schedule EE-4 of Attachment EE of the Agreement was Fifty Thousand U.S. Dollars (U.S. $50,000). Actual costs for the Cathodic Protection Provisional Sum was Zero U.S. Dollars (U.S. $0.00). By way of this Change Order, the Cathodic Protection Provisional Sum and Contract Price will be decreased by Fifty-Three Thousand U.S. Dollars (U.S. $53,000), which reflects the closure of the Cathodic Protection Provisional Sum and credit for the six percent (6%) fee.

4.The Provisional Sum calculations for this Change Order are detailed in Exhibit A of this Change Order.

5.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)	$	12,798,754
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,029,691,327
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	$	2,029,691,327

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)	$	(4,568,146)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	453,127,854
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 decreased by this Change Order	$	(371,000)
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	452,756,854

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)	$	2,482,819,181
15.	The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	(371,000)
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,482,448,181

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 of this Change Order.

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:


/s/ David Craft						/s/ Kane McIntosh
Owner						Contractor
David Craft						Kane McIntosh
Name						Name
SVP E&C						Senior Project Manager
Title						Title
April 21, 2021						April 9, 2021
Date of Signing						Date of Signing

CHANGE ORDER

Winter Storm Impacts


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-00045 DATE OF CHANGE ORDER: April 9, 2021

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

1.In accordance with Section 6.2 of the Agreement (Change Orders Requested by Contractor), Parties agree this Change Order includes final and agreed-upon impacts to the Project caused by the February 2021 Winter Storm and Site shutdown.

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

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

Adjustment to Contract Price Applicable to Subproject 6(a)


1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42)	$	12,798,754
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,029,691,327
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	1,095,477
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	$	2,030,786,804

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)	$	(4,939,146)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	452,756,854
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 unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	452,756,854

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)....................................................	$	2,482,448,181
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	1,095,477
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,483,543,658

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:


/s/ David Craft						/s/ Kane McIntosh
Owner						Contractor
David Craft						Kane McIntosh
Name						Name
SVP E&C						Senior Project Manager
Title						Title
April 21, 2021						April 9, 2021
Date of Signing						Date of Signing

CHANGE ORDER

NGPL Security Provisional Sum Interim Adjustment


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-00046 DATE OF CHANGE ORDER: June 15, 2021

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

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order is an interim adjustment to the “NGPL Security Provisional Sum” Work as described in Section 2.4 of Schedule EE-2 of Attachment EE of the Agreement (Provisional Sums to be Adjusted during Project Execution for Subproject 6(a)). This interim adjustment includes actual costs through 5 April 2021 and forecast costs through 31 December 2021.

2.The original value of the NGPL Security Provisional Sum specified in Article 2.4 of Schedule EE-2 of Attachment EE of the Agreement was Two Hundred Thirty-Two Thousand, One Hundred Fifty-Eight U.S. Dollars (U.S. $232,158). The actual cost for the NGPL Security Provisional Sum through 5 April 2021 is One Hundred Eighty-Four Thousand, Two Hundred Fifty-Eight U.S. Dollars (U.S. $184,258). The forecast cost through 31 December 2021 is Sixty-Seven Thousand, Seven Hundred Fifty-Eight U.S. Dollars (U.S. $67,758). The interim adjustment in this Change Order (inclusive of fee) increases the NGPL Security Provisional Sum by Twenty-One Thousand, Forty-Nine U.S. Dollars (U.S. $21,049).

3. The Provisional Sum interim adjustment calculations for this Change Order are detailed in Exhibit A of this Change Order. The invoice reconciliation for costs to-date is detailed in Exhibit C of this Change Order. The timeline of events table is provided in Exhibit D 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)	$	13,894,231
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,030,786,804
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 increased by this Change Order in the amount of	$	21,049

6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,030,807,853

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)	$	(4,939,146)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	452,756,854
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 unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	452,756,854

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)....................................................	$	2,483,543,658
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	21,049
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,483,564,707

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 of this Change Order.

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:


/s/ David Craft						/s/ Kane McIntosh
Owner						Contractor
David Craft						Kane McIntosh
Name						Name
SVP E&C						Project Manager
Title						Title
June 17, 2021						June 15, 2021
Date of Signing						Date of Signing

CHANGE ORDER

80 Acres Bridge


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-00047 DATE OF CHANGE ORDER: June 15, 2021

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

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s engineering, procurement and construction costs to install a permanent beam bridge approximately 35-feet span and 60-feet width at the existing north bridge location between 80 Acres and Lighthouse Road. This Change Order includes demolition and removal of the existing north and south bridges currently in place.

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

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

Adjustment to Contract Price Applicable to Subproject 6(a)


1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-46)	$	13,915,280
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,030,807,853
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	1,033,706
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	$	2,031,841,559

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)	$	(4,939,146)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	452,756,854
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 unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	452,756,854

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)....................................................	$	2,483,564,707
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	1,033,706
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,484,598,413

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:


/s/ David Craft						/s/ Kane McIntosh
Owner						Contractor
David Craft						Kane McIntosh
Name						Name
SVP E&C						Project Manager
Title						Title
June 17, 2021						June 15, 2021
Date of Signing						Date of Signing

CHANGE ORDER

AGRU Additions for Lean Solvent Overpressure


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-00048 DATE OF CHANGE ORDER: June 15, 2021

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

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s procurement and construction costs to enhance the overpressure protection of the AGRU Lean Solvent System. Contractor’s engineering and procurement professional services are included in this Change Order free-of-charge.

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

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

Adjustment to Contract Price Applicable to Subproject 6(a)


1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-47)	$	14,948,986
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,031,841,559
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	600,743
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	$	2,032,442,302

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)	$	(4,939,146)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	452,756,854
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 unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	452,756,854

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)	$	2,484,598,413
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	600,743
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,485,199,156

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:


/s/ David Craft						/s/ Kane McIntosh
Owner						Contractor
David Craft						Kane McIntosh
Name						Name
SVP E&C						Project Manager
Title						Title
June 17, 2021						June 15, 2021
Date of Signing						Date of Signing

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Jack A. Fusco, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Cheniere Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 4, 2021


/s/ Jack A. Fusco
Jack A. Fusco Chief Executive Officer of
Cheniere Energy, Inc.

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.;

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 4, 2021


/s/ Zach Davis
Zach Davis Chief Financial Officer of
Cheniere Energy, Inc.

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: August 4, 2021


/s/ Jack A. Fusco
Jack A. Fusco Chief Executive Officer of
Cheniere Energy, Inc.

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Zach Davis, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: August 4, 2021


/s/ Zach Davis
Zach Davis Chief Financial Officer of
Cheniere Energy, Inc.