10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2018

or

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

For the transition period fromto

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	001-16383	95-4352386
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(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)

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  x   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 and post such files).  Yes  x   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  x	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. o

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

As of November 2, 2018, the issuer had 256,885,068 shares of Common Stock outstanding.

CHENIERE ENERGY, INC.

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations	4
	Consolidated Statement of Stockholders’ Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
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

i

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, an energy unit
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, an energy unit
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA	terminal use agreement

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of September 30, 2018, 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.

During the quarter ended September 30, 2018, we closed the previously announced merger of Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) with and into our wholly owned subsidiary. As a result of the merger, Cheniere Holdings is no longer a publicly-traded company.

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

2

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	September 30,			December 31,
	2018			2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	989		$	722
Restricted cash	1,943			1,880
Accounts and other receivables	243			369
Accounts receivable—related party	3			2
Inventory	298			243
Derivative assets	63			57
Other current assets	131			96
Total current assets	3,670			3,369
Non-current restricted cash	—			11
Property, plant and equipment, net	26,499			23,978
Debt issuance costs, net	78			149
Non-current derivative assets	121			34
Goodwill	77			77
Other non-current assets, net	295			288
Total assets	$	30,740		$	27,906
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	80		$	25
Accrued liabilities	987			1,078
Current debt	66			—
Deferred revenue	120			111
Derivative liabilities	96			37
Other current liabilities	1			—
Total current liabilities	1,350			1,251
Long-term debt, net	27,438			25,336
Non-current capital lease obligations	29			—
Non-current derivative liabilities	16			19
Other non-current liabilities	76			60
Commitments and contingencies (see Note 15)
Stockholders’ equity
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—			—
Common stock, $0.003 par value
Authorized: 480.0 million shares at September 30, 2018 and December 31, 2017
Issued: 269.7 million shares and 250.1 million shares at September 30, 2018 and December 31, 2017, respectively
Outstanding: 257.1 million shares and 237.6 million shares at September 30, 2018 and December 31, 2017, respectively	1			1
Treasury stock: 12.6 million shares and 12.5 million shares at September 30, 2018 and December 31, 2017, respectively, at cost	(396		)	(386		)
Additional paid-in-capital	4,009			3,248
Accumulated deficit	(4,223		)	(4,627		)
Total stockholders’ deficit	(609		)	(1,764		)
Non-controlling interest	2,440			3,004
Total equity	1,831			1,240
Total liabilities and equity	$	30,740		$	27,906

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

3

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues
LNG revenues	$	1,719		$	1,332		$	5,327		$	3,646
Regasification revenues	66			65			196			195
Other revenues	30			5			73			12
Other—related party	4			1			8			2
Total revenues	1,819			1,403			5,604			3,855
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	1,027			824			3,078			2,140
Operating and maintenance expense	170			114			457			309
Development expense	2			3			6			7
Selling, general and administrative expense	74			64			214			179
Depreciation and amortization expense	113			92			333			252
Restructuring expense	—			—			—			6
Impairment expense and loss on disposal of assets	8			9			8			15
Total operating costs and expenses	1,394			1,106			4,096			2,908
Income from operations	425			297			1,508			947
Other income (expense)
Interest expense, net of capitalized interest	(221		)	(186		)	(653		)	(539		)
Loss on modification or extinguishment of debt	(12		)	(25		)	(27		)	(100		)
Derivative gain (loss), net	23			(2		)	132			(37		)
Other income	15			4			32			11
Total other expense	(195		)	(209		)	(516		)	(665		)
Income before income taxes and non-controlling interest	230			88			992			282
Income tax benefit (provision)	(3		)	2			(15		)	1
Net income	227			90			977			283
Less: net income attributable to non-controlling interest	162			379			573			803
Net income (loss) attributable to common stockholders	$	65		$	(289	)	$	404		$	(520	)
Net income (loss) per share attributable to common stockholders—basic	$	0.26		$	(1.24	)	$	1.67		$	(2.24	)
Net income (loss) per share attributable to common stockholders—diluted	$	0.26		$	(1.24	)	$	1.65		$	(2.24	)
Weighted average number of common shares outstanding—basic	247.2			232.6			241.9			232.5
Weighted average number of common shares outstanding—diluted	250.2			232.6			244.6			232.5

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

4

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(in millions)

(unaudited)

	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, 2017	237.6		$	1	12.5	$	(386	)	$	3,248	$	(4,627	)	$	3,004		$	1,240
Vesting of restricted stock units	0.4		—		—	—			—		—			—			—
Issuance of stock to acquire additional interest in Cheniere Holdings and other merger related adjustments	19.2		—		—	—			694		—			(702		)	(8		)
Share-based compensation	—		—		—	—			65		—			—			65
Shares repurchased related to share-based compensation	(0.1	)	—		0.1	(10		)	—		—			—			(10		)
Net income attributable to non-controlling interest	—		—		—	—			—		—			573			573
Equity portion of convertible notes, net	—		—		—	—			2		—			—			2
Distributions to non-controlling interest	—		—		—	—			—		—			(435		)	(435		)
Net income	—		—		—	—			—		404			—			404
Balance at September 30, 2018	257.1		$	1	12.6	$	(396	)	$	4,009	$	(4,223	)	$	2,440		$	1,831

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

5

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Nine Months Ended September 30,
	2018			2017
Cash flows from operating activities
Net income	$	977		$	283
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	333			252
Share-based compensation expense	89			64
Non-cash interest expense	52			54
Amortization of debt issuance costs, deferred commitment fees, premium and discount	53			53
Loss on modification or extinguishment of debt	27			100
Total losses on derivatives, net	17			108
Net cash used for settlement of derivative instruments	(54		)	(59		)
Impairment expense and loss on disposal of assets	8			15
Other	(5		)	(2		)
Changes in operating assets and liabilities:
Accounts and other receivables	115			(33		)
Accounts receivable—related party	(1		)	(1		)
Inventory	(56		)	35
Other current assets	(35		)	(45		)
Accounts payable and accrued liabilities	(23		)	20
Deferred revenue	8			58
Other, net	(1		)	(7		)
Net cash provided by operating activities	1,504			895
Cash flows from investing activities
Property, plant and equipment, net	(2,712		)	(2,903		)
Investment in equity method investment	(25		)	(41		)
Other	15			18
Net cash used in investing activities	(2,722		)	(2,926		)
Cash flows from financing activities
Proceeds from issuances of debt	3,443			6,537
Repayments of debt	(1,385		)	(3,609		)
Debt issuance and deferred financing costs	(53		)	(85		)
Debt extinguishment costs	(16		)	—
Distributions and dividends to non-controlling interest	(435		)	(60		)
Payments related to tax withholdings for share-based compensation	(10		)	(4		)
Other	(7		)	—
Net cash provided by financing activities	1,537			2,779
Net increase in cash, cash equivalents and restricted cash	319			748
Cash, cash equivalents and restricted cash—beginning of period	2,613			1,827
Cash, cash equivalents and restricted cash—end of period	$	2,932		$	2,575

Balances per Consolidated Balance Sheet:

	September 30, 2018
Cash and cash equivalents	$	989
Restricted cash	1,943
Total cash, cash equivalents and restricted cash	$	2,932

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

6

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We are currently developing and constructing two natural gas liquefaction and export facilities. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “SPL Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities (described below) through a wholly owned subsidiary, SPL. Cheniere Partners plans to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is undergoing commissioning and Train 6 is being commercialized and has all necessary regulatory approvals in place. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, and a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines owned by Cheniere Partners’ wholly owned subsidiary, CTPL.

We are developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal near Corpus Christi, Texas, and a pipeline facility (collectively, the “CCL Project”) through wholly owned subsidiaries CCL and CCP, respectively. The CCL Project is being developed in stages. The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the CCL Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). The CCL Project also includes a 23-mile natural gas supply pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”). Stages 1 and 2 are currently under construction, and construction of the Corpus Christi Pipeline was completed in the second quarter of 2018. Train 1 has commenced commissioning activities.

Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project and filed an application with FERC in June 2018 for seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa and one LNG storage tank. We remain focused on leveraging infrastructure through the expansion of our existing sites. We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require 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 year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. The adoption of ASC 606 represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of ASC 606 did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings.

Results of operations for the three and nine months ended September 30, 2018 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2018.

7

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 2—RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2018 and December 31, 2017, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Current restricted cash
SPL Project	$	649	$	544
Cheniere Partners and cash held by guarantor subsidiaries	808		1,045
CCL Project	220		227
Cash held by our subsidiaries restricted to Cheniere	266		64
Total current restricted cash	$	1,943	$	1,880
Non-current restricted cash
Other	$	—	$	11

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 SPL Project and the CCL Project and other restricted payments.

Under Cheniere Partners’ credit facilities (the “CQP Credit Facilities”), Cheniere Partners and each of its subsidiaries other than SPL, as guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the CQP Credit Facilities and the related depositary agreement governing the extension of credit to Cheniere Partners. Specifically, Cheniere Partners may only withdraw funds from collateral accounts held at a designated depositary bank on a limited basis and for specific purposes, including for the payment of operating expenses of Cheniere Partners and its guarantor subsidiaries. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions.

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2018 and December 31, 2017, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Trade receivables
SPL	$	213	$	185
Cheniere Marketing	16		163
Other accounts receivable	14		21
Total accounts and other receivables	$	243	$	369

NOTE 4—INVENTORY

As of September 30, 2018 and December 31, 2017, inventory consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Natural gas	$	10	$	17
LNG	42		44
LNG in-transit	181		130
Materials and other	65		52
Total inventory	$	298	$	243

8

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

As of September 30, 2018 and December 31, 2017, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	13,162		$	12,687
LNG site and related costs	86			86
LNG terminal construction-in-process	14,269			11,932
Accumulated depreciation	(1,192		)	(882		)
Total LNG terminal costs, net	26,325			23,823
Fixed assets and other
Computer and office equipment	17			14
Furniture and fixtures	19			19
Computer software	97			92
Leasehold improvements	41			41
Land	59			59
Other	18			16
Accumulated depreciation	(107		)	(86		)
Total fixed assets and other, net	144			155
Tug vessels under capital lease	30			—
Property, plant and equipment, net	$	26,499		$	23,978

Depreciation expense was $112 million and $91 million during the three months ended September 30, 2018 and 2017, respectively, and $331 million and $250 million during the nine months ended September 30, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $82 million and $252 million in the three and nine months ended September 30, 2017, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the SPL Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three and nine months ended September 30, 2018.

NOTE 6—DERIVATIVE INSTRUMENTS

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

• interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under certain credit facilities (“Interest Rate Derivatives”);

• commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”);

• financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“LNG Trading Derivatives”); and

• foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with both LNG Trading Derivatives and operations in countries outside of the United States (“FX Derivatives”).

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 hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.

9

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2018											December 31, 2017
	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
CQP Interest Rate Derivatives asset	$	—		$	28		$	—	$	28		$	—		$	21		$	—	$	21
CCH Interest Rate Derivatives asset (liability)	—			94			—		94			—			(32		)	—		(32		)
Liquefaction Supply Derivatives asset (liability)	(1		)	4			26		29			2			10			43		55
LNG Trading Derivatives asset (liability)	(19		)	(71		)	—		(90		)	(13		)	5			—		(8		)
FX Derivatives asset (liability)	—			11			—		11			—			(1		)	—		(1		)

There have been no changes to our evaluation of and accounting for our derivative positions during the nine months ended September 30, 2018. See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information.

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 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 is predominantly driven by market commodity basis prices and, as applicable to our natural gas supply contracts, our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

We include 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 may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. As of September 30, 2018 and December 31, 2017, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow.

10

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2018:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$26	Market approach incorporating present value techniques	Basis Spread	$(0.748) - $0.079

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Balance, beginning of period	$	12		$	40		$	43		$	79
Realized and mark-to-market gains (losses):
Included in cost of sales	5			(8		)	(4		)	(43		)
Purchases and settlements:
Purchases	9			(1		)	14			1
Settlements	1			(2		)	(27		)	(8		)
Transfers out of Level 3 (1)	(1		)	—			—			—
Balance, end of period	$	26		$	29		$	26		$	29
Change in unrealized gains relating to instruments still held at end of period	$	5		$	(8	)	$	(4	)	$	(43	)

(1)    Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. 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, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

Cheniere Partners had entered into interest rate swaps (“CQP Interest Rate Derivatives”) to hedge a portion of the variable interest payments on its CQP Credit Facilities, based on a portion of the expected outstanding borrowings over the term of the CQP Credit Facilities. In September 2018, Cheniere Partners terminated approximately $1.2 billion of commitments under the CQP Credit Facilities, as discussed in Note 10—Debt. In October 2018, Cheniere Partners terminated the CQP Interest Rate Derivatives related to the CQP Credit Facilities, which resulted in a derivative gain of $28 million.

CCH has entered into interest rate swaps (“CCH Interest Rate Derivatives”) to hedge a portion of the variable interest payments on its credit facility (the “CCH Credit Facility”). In June 2018, CCH settled a portion of the CCH Interest Rate Derivatives and recognized a derivative gain of $5 million upon the termination of interest rate swaps associated with the amendment of the CCH Credit Facility, as discussed in Note 10—Debt. In May 2017, CCH settled a portion of the CCH Interest Rate Derivatives and recognized a derivative loss of $13 million in conjunction with the termination of approximately $1.4 billion of commitments under the CCH Credit Facility.

SPL had entered into interest rate swaps (“SPL Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “SPL Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the SPL Credit Facilities. In March 2017, SPL settled the SPL Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the SPL Credit Facilities.

11

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

As of September 30, 2018, we had the following Interest Rate Derivatives outstanding:

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
CQP Interest Rate Derivatives	$225 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR
CCH Interest Rate Derivatives	$29 million	$4.7 billion	May 20, 2015	May 31, 2022	2.30%	One-month LIBOR

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

	September 30, 2018						December 31, 2017
	CQP Interest Rate Derivatives		CCH Interest Rate Derivatives		Total		CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total
Consolidated Balance Sheet Location
Derivative assets	$	19	$	13	$	32	$	7	$	—		$	7
Non-current derivative assets	9		81		90		14		3			17
Total derivative assets	28		94		122		21		3			24
Derivative liabilities	—		—		—		—		(20		)	(20		)
Non-current derivative liabilities	—		—		—		—		(15		)	(15		)
Total derivative liabilities	—		—		—		—		(35		)	(35		)
Derivative asset (liability), net	$	28	$	94	$	122	$	21	$	(32	)	$	(11	)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
CQP Interest Rate Derivatives gain	$	2	$	1		$	13	$	—
CCH Interest Rate Derivatives gain (loss)	21		(3		)	119		(35		)
SPL Interest Rate Derivatives loss	—		—			—		(2		)

Commodity Derivatives

SPL and CCL have entered into index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the SPL Project and the CCL Project. The terms of the physical natural gas supply contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the fair value and location of our Liquefaction Supply Derivatives and LNG Trading Derivatives(collectively, “Commodity Derivatives”) on our Consolidated Balance Sheets (in millions, except notional amount):

	September 30, 2018									December 31, 2017
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total			Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total
Consolidated Balance Sheet Location
Derivative assets	$	13		$	7		$	20		$	41		$	9		$	50
Non-current derivative assets	27			4			31			17			—			17
Total derivative assets	40			11			51			58			9			67
Derivative liabilities	(6		)	(90		)	(96		)	—			(17		)	(17		)
Non-current derivative liabilities	(5		)	(11		)	(16		)	(3		)	—			(3		)
Total derivative liabilities	(11		)	(101		)	(112		)	(3		)	(17		)	(20		)
Derivative asset (liability), net	$	29		$	(90	)	$	(61	)	$	55		$	(8	)	$	47
Notional amount, net (in TBtu) (3)	4,769			20						2,539			25

(1) Does not include collateral calls of $3 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively.

(2) Does not include collateral of $58 million and $28 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively.

(3) SPL had secured up to approximately 2,755 TBtu and 2,214 TBtu and CCL had secured up to approximately 2,640 TBtu and 2,024 TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2018 and December 31, 2017, respectively.

The following table shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Consolidated Statements of Operations Location (1)	Three Months Ended September 30,						Nine Months Ended September 30,
		2018			2017			2018			2017
LNG Trading Derivatives loss	LNG revenues	$	(58	)	$	(16	)	$	(128	)	$	(20	)
Liquefaction Supply Derivatives gain (loss) (2)	Cost of sales	21			(11		)	(32		)	(51		)

(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

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

		Fair Value Measurements as of
	Consolidated Balance Sheet Location	September 30, 2018		December 31, 2017
FX Derivatives	Derivative assets	$	11	$	—
FX Derivatives	Non-current derivative liabilities	—		(1		)

The total notional amount of our FX Derivatives was $227 million and $27 million as of September 30, 2018 and December 31, 2017, respectively.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the changes in the fair value of our FX Derivatives recorded in LNG revenues on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
FX Derivatives gain	$	1	$	—	$	11	$	—

Consolidated Balance Sheet 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):

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2018
CQP Interest Rate Derivatives	$	28		$	—		$	28
CCH Interest Rate Derivatives	94			—			94
Liquefaction Supply Derivatives	46			(6		)	40
Liquefaction Supply Derivatives	(22		)	11			(11		)
LNG Trading Derivatives	50			(39		)	11
LNG Trading Derivatives	(154		)	53			(101		)
FX Derivatives	21			(10		)	11
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
CCH Interest Rate Derivatives	3			—			3
CCH Interest Rate Derivatives	(35		)	—			(35		)
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)
LNG Trading Derivatives	9			—			9
LNG Trading Derivatives	(37		)	20			(17		)
FX Derivatives	(1		)	—			(1		)

NOTE 7—OTHER NON-CURRENT ASSETS

As of September 30, 2018 and December 31, 2017, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	15	$	26
Advances made to municipalities for water system enhancements	90		97
Advances and other asset conveyances to third parties to support LNG terminals	48		48
Tax-related payments and receivables	21		29
Equity method investments	92		64
Other	29		24
Total other non-current assets, net	$	295	$	288

Equity Method Investments

Our equity method investments consist of interests in privately-held companies. In 2017, we acquired an equity interest in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”). Midship Pipeline is pursuing the development, construction, operation and maintenance of an approximately 200-mile natural gas pipeline project (the “Midship Project”) that connects new production in the Anadarko Basin to Gulf Coast markets. Midship Holdings entered into agreements with investment funds managed by EIG Global Energy Partners (“EIG”) under which EIG-managed funds committed to make an investment of up to $500 million (the “EIG Investment”) in the Midship Project, subject to the terms and conditions contained in the applicable agreements. The EIG Investment, when combined with

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

equity contributed by us, is intended to ensure the Midship Project has the equity funding expected to be required to develop and construct the project. Construction of the Midship Project will commence based upon, among other things, obtaining the required authorization from the FERC and adequate financing to construct the proposed project.

We have determined that Midship Holdings is a variable interest entity (“VIE”) because it is thinly capitalized at formation such that the total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support. We do not consolidate Midship Holdings because we do not have power to direct the activities that most significantly impact its economic performance. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause a change in our identification of a VIE or determination of the primary beneficiary to a VIE. We account for our investment in Midship Holdings under the equity method as we have the ability to exercise significant influence over the operating and financial policies of Midship Holdings through our non-controlling voting rights on its board of managers. Our investment in Midship Holdings was $84 million and $55 million at September 30, 2018 and December 31, 2017, respectively. Our obligations to make additional investments in Midship Holdings are not significant.

Cheniere LNG O&M Services, LLC (“O&M Services”), our wholly owned subsidiary, provides the development, construction, operation and maintenance services associated with the Midship Project pursuant to agreements in which O&M Services receives an agreed upon fee and reimbursement of costs incurred. O&M Services recorded $4 million and $1 million in the three months ended September 30, 2018 and 2017, respectively, and $8 million and $2 million in the nine months ended September 30, 2018 and 2017, respectively, of revenues in other—related party and $3 million and $2 million of accounts receivable—related party as of September 30, 2018 and December 31, 2017, respectively, for services provided to Midship Pipeline under these agreements. CCL has entered into a transportation precedent agreement with Midship Pipeline to secure firm pipeline transportation capacity for a period of 10 years following commencement of the Midship Project. In May 2018, CCL issued a letter of credit to Midship Pipeline for drawings up to an aggregate maximum amount of $16 million. Midship Pipeline had not made any drawings on this letter of credit as of September 30, 2018.

NOTE 8—NON-CONTROLLING INTEREST

During the three and nine months ended September 30, 2018, we acquired 8.1% and 17.3%, respectively, of additional interest in Cheniere Holdings previously held by the public, and closed the previously announced merger of Cheniere Holdings with and into our wholly owned subsidiary. As a result of the merger, all of the publicly-held shares of Cheniere Holdings not owned by us were canceled and shareholders other than Cheniere received shares of our common stock in a stock-for-share exchange. As of December 31, 2017, we owned 82.7% of Cheniere Holdings. Because the transactions represented a combination of ownership interests under common control, changes in Cheniere’s ownership interest in Cheniere Holdings were accounted for as an equity transaction and no gain or loss was recognized.

We own a 48.6% limited partner interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco LP 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 variable interest entity. See Note 9—Variable Interest Entities of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for further information.

NOTE 9—ACCRUED LIABILITIES

As of September 30, 2018 and December 31, 2017, accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2018		2017
Interest costs and related debt fees	$	252	$	397
Accrued natural gas purchases	251		298
LNG terminals and related pipeline costs	228		192
Compensation and benefits	113		141
Accrued LNG inventory	76		1
Other accrued liabilities	67		49
Total accrued liabilities	$	987	$	1,078

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—DEBT

As of September 30, 2018 and December 31, 2017, our debt consisted of the following (in millions): 

	September 30,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			—
CQP Credit Facilities	—			1,090
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250			1,250
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500			1,500
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500			1,500
CCH Credit Facility	4,492			2,485
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,416			1,305
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”)	1,189			1,161
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”)	625			625
$750 million Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	—			—
Unamortized premium, discount and debt issuance costs, net	(784		)	(730		)
Total long-term debt, net	27,438			25,336
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	—			—
Cheniere Marketing trade finance facilities	66			—
Total current debt	66			—
Total debt, net	$	27,504		$	25,336

2018 Debt Issuances and Redemptions

2026 CQP Senior Notes

In September 2018, Cheniere Partners issued an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (the “CQP Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP. Net proceeds of the offering of approximately $1.1 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay all of the outstanding indebtedness under the CQP Credit Facilities, resulting in the recognition of debt modification and extinguishment costs of $12 million for the three and nine months ended September 30, 2018 relating to the incurrence of third party fees and write off of

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

unamortized debt issuance costs. As of September 30, 2018, only a $115 million revolving credit facility, all of which is undrawn, remains as part of the CQP Credit Facilities.

Borrowings under the 2026 CQP Senior Notes accrue interest at a fixed rate of 5.625%, and interest on the 2026 CQP Senior Notes is payable semi-annually in arrears. The 2026 CQP Senior Notes are governed by the same base indenture as the 2025 CQP Senior Notes (the “CQP Base Indenture”), and are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”), which contains customary 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, Cheniere Partners may redeem all or a part of the 2026 CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the 2026 CQP Senior Notes redeemed, plus the “applicable premium” set forth in the 2026 CQP Notes Indenture, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2021, Cheniere Partners may redeem up to 35% of the aggregate principal amount of the 2026 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 redeemed, plus accrued and unpaid interest, if any, to the date of redemption. At any time on or after October 1, 2021 through the maturity date of October 1, 2026, Cheniere Partners may redeem the 2026 CQP Senior Notes, in whole or in part, at the redemption prices set forth in the 2026 CQP Notes Indenture.

The 2026 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. After applying the proceeds from the 2026 CQP Senior Notes, the 2026 CQP Senior Notes and the 2025 CQP Senior Notes(collectively, the “CQP Senior Notes”) became unsecured. 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 CQP Credit Facilities. The obligations under the CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) 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 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the CQP Credit Facilities).

In connection with the closing of the 2026 CQP Senior Notes offering, Cheniere Partners and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, Cheniere Partners and the CQP Guarantors have agreed to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2026 CQP Senior Notes for a like aggregate principal amount of debt securities of Cheniere Partners with terms identical in all material respects to the 2026 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after the notes issuance date of September 11, 2018. Under specified circumstances, Cheniere Partners and the CQP Guarantors have also agreed to cause to become effective a shelf registration statement relating to resales of the 2026 CQP Senior Notes. Cheniere Partners will be obligated to pay additional interest on the 2026 CQP Senior Notes if it fails to comply with its obligation to register the 2026 CQP Senior Notes within the specified time period.

CCH Credit Facility

In May 2018, CCH amended and restated the CCH Credit Facility to increase total commitments under the credit facility to $6.1 billion. Borrowings are used to fund a portion of the costs of developing, constructing and placing into service the three Trains and the related facilities of the CCL Project and for related business purposes.

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,

17

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

Loans under the CCH Credit Facility accrue interest at a variable rate per annum equal to, at CCH’s election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 1.75% and for base rate loans is 0.75%. Interest on LIBOR loans is due and payable at the end of each applicable interest period and interest on base rate loans is due and payable at the end of each quarter. CCH was required to pay certain upfront fees to the agents and lenders under the CCH Credit Facility together with additional transaction fees and expenses in the aggregate amount of $53 million.

All other terms of the CCH Credit Facility substantially remained the same to those described in Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017. The amendment and restatement of the CCH Credit Facility resulted in the recognition of $15 million of debt modification and extinguishment costs during the nine months ended September 30, 2018 relating to the incurrence of third party fees and write off of unamortized debt issuance costs.

CCH Working Capital Facility

In June 2018, CCH amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility to $1.2 billion. Borrowings will be used for certain working capital requirements related to developing and placing into operations the CCL Project and for related business purposes.

Loans under the CCH Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.25% to 1.75% per annum, and the applicable margin for base rate loans ranges from 0.25% to 0.75% per annum. CCH was required to pay certain upfront fees to the agents and lenders under the CCH Working Capital Facility together with additional transaction fees and expenses in the aggregate amount of $14 million.

The CCH Working Capital Facility matures on June 29, 2023. All other terms of the CCH Working Capital Facility substantially remained the same to those described in Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

2025 CCH HoldCo II Convertible Senior Notes

In May 2018, the amended and restated note purchase agreement under which the 2025 CCH HoldCo II Convertible Senior Notes were issued was subsequently amended in connection with commercialization and financing of Train 3 of the CCL Project.  All terms of the 2025 CCH HoldCo II Convertible Senior Notes substantially remained the same to those described in Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

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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 September 30, 2018 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Original facility size	$	1,200	$	2,800	$	8,404	$	350	$	750
Incremental commitments	—		—		1,566		850		—
Less:
Outstanding balance	—		—		4,492		—		—
Commitments prepaid or terminated	—		2,685		3,832		—		—
Letters of credit issued	494		—		—		316		—
Available commitment	$	706	$	115	$	1,646	$	884	$	750
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)		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 3.25% or base rate plus 2.25%
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020		June 30, 2024		June 29, 2023		March 2, 2021

(1) There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

Convertible Notes

Below is a summary of our convertible notes outstanding as of September 30, 2018 (in millions):

	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000		$	1,000		$	625
Debt component, net of discount and debt issuance costs	$	1,090		$	1,390		$	310
Equity component	$	207		$	—		$	194
Interest payment method	Paid-in-kind			Paid-in-kind (1)			Cash
Conversion by us (2)	—			(3)			(4)
Conversion by holders (2)	(5)			(6)			(7)
Conversion basis	Cash and/or stock			Stock			Cash and/or stock
Conversion value in excess of principal	$	—		$	—		$	—
Maturity date	May 28, 2021			May 13, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate (8)	8.4		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (9)	2.7 years			2.0 years			26.5 years

(1) Prior to the substantial completion of Train 2 of the CCL Project, interest will be paid entirely in kind. Following this date, the interest generally must be paid in cash; however, a portion of the interest may be paid in kind under certain specified circumstances.

(2) Conversion is subject to various limitations and conditions.

(3) Convertible on or after the later of March 1, 2020 and the substantial completion of Train 2 of the CCL Project, provided that our market capitalization is not less than $10.0 billion (“Eligible Conversion Date”). The conversion price is the lower of (1) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock for the 90 trading day period prior to the date notice is provided, and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date notice is provided.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

(4) Redeemable at any time after March 15, 2020 at a redemption price payable in cash 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.

(5) Initially convertible at $93.64 (subject to adjustment upon the occurrence of certain specified events), provided that the closing price of our common stock is greater than or equal to the conversion price on the conversion date.

(6) Convertible on or after the six-month anniversary of the Eligible Conversion Date, provided that our total market capitalization is not less than $10.0 billion, at a price equal to the average of the daily VWAP of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided.

(7) 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, 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).

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

(9) We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity except for the 2025 CCH HoldCo II Convertible Senior Notes, which are amortized through the date they are first convertible by holders into our common stock.

Restrictive Debt Covenants

As of September 30, 2018, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Interest cost on convertible notes:
Interest per contractual rate	$	60		$	55		$	176		$	162
Amortization of debt discount	9			8			25			22
Amortization of debt issuance costs	3			2			7			5
Total interest cost related to convertible notes	72			65			208			189
Interest cost on debt excluding convertible notes	354			324			1,034			931
Total interest cost	426			389			1,242			1,120
Capitalized interest	(205		)	(203		)	(589		)	(581		)
Total interest expense, net	$	221		$	186		$	653		$	539

20

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

The following table shows the carrying amount, which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in millions):

	September 30, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	19,457	$	20,552	$	18,350	$	20,075
2037 SPL Senior Notes (2)	791		831		790		871
Credit facilities (3)	4,466		4,466		3,574		3,574
2021 Cheniere Convertible Unsecured Notes (2)	1,090		1,267		1,040		1,136
2025 CCH HoldCo II Convertible Senior Notes (2)	1,390		1,597		1,273		1,535
2045 Cheniere Convertible Senior Notes (4)	310		497		309		447

(1) Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2026 CQP Senior Notes, 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes. 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) Includes SPL Working Capital Facility, CQP Credit Facilities, CCH Credit Facility, CCH Working Capital Facility, Cheniere Revolving Credit Facility and Cheniere Marketing trade finance facilities. 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.

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
LNG revenues	$	1,712	$	1,345		$	5,327	$	3,646
Regasification revenues	66		65			196		195
Other revenues	30		5			73		12
Other—related party	4		1			8		2
Total revenues from customers	1,812		1,416			5,604		3,855
Gains (losses) from derivative instruments (1)	7		(13		)	—		—
Total revenues	$	1,819	$	1,403		$	5,604	$	3,855

(1) Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at either the Sabine Pass or Corpus Christi LNG terminal) or delivered at terminal (“DAT”) (delivered to the customer at their LNG receiving terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal

21

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

We intend to primarily use LNG sourced from our Sabine Pass or Corpus Christi terminals to provide contracted volumes to our customers. However, we supplement this LNG with volumes procured from third parties. LNG revenues recognized from LNG that was procured from third parties was $208 million and $427 million for the three months ended September 30, 2018 and 2017, respectively, and $394 million and $631 million for the nine months ended September 30, 2018 and 2017, respectively.

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

When we sell LNG on a DAT basis, we consider all transportation costs, including vessel chartering, loading/unloading and canal fees, as fulfillment costs and not as separate services provided to the customer within the arrangement, regardless of whether or not such activities occur prior to or after the customer obtains control of the LNG. We expense fulfillment costs as incurred unless otherwise dictated by GAAP.

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

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the exception for allocating variable consideration to specific parts of the contract and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its 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 Trains 5 and 6.

22

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Upon substantial completion of Train 3 of the SPL Project, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. 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 and we continue to recognize the payments received from Total as revenue. During each of the three months ended September 30, 2018 and 2017, SPL recorded $7.5 million and during the nine months ended September 30, 2018 and 2017, SPL recorded $23 million and $15 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

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

	Nine Months Ended September 30, 2018
Deferred revenues, beginning of period	$	111
Cash received but not yet recognized	120
Revenue recognized from prior period deferral	(111		)
Deferred revenues, end of period	$	120

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the nine months ended September 30, 2018 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2018:

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	102.4	11.3
Regasification revenues	2.7		5.8
Total revenues	$	105.1

(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) 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 table above excludes all variable consideration under our SPAs and TUAs. 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. A portion of such variable consideration is considered constrained due to the uncertainty of ultimate pricing and receipt and we have not included such variable consideration in the transaction price. During each of the three and nine months ended September 30, 2018, approximately 55% of our LNG revenues from contracts with a duration of over one year and approximately 3% of our regasification revenues were related to variable consideration received from customers.

23

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

We have entered 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.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2017.

NOTE 12—INCOME TAXES

We recorded an income tax provision of $3 million and an income tax benefit of $2 million during the three months ended September 30, 2018 and 2017, respectively, and an income tax provision of $15 million and an income tax benefit of $1 million during the nine months ended September 30, 2018 and 2017, respectively. Changes in the income tax recorded between comparative periods are primarily attributable to fluctuations in the profitability of our U.K. integrated marketing function.

The effective tax rates during the three and nine months ended September 30, 2018 and 2017 were lower than the 21% and 35% federal statutory rates during the 2018 and 2017 interim periods, respectively, primarily as a result of maintaining a valuation allowance against our federal and state net deferred tax assets. Due to historical losses and other available evidence related to our ability to generate taxable income, we continue to maintain a valuation allowance against our federal and state net deferred tax assets at September 30, 2018.

NOTE 13—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 Amended and Restated 2003 Stock Incentive Plan, as amended, the 2011 Incentive Plan, as amended (the “2011 Plan”), the 2015 Employee Inducement Incentive Plan and the 2015 Long-Term Cash Incentive Plan.

For the nine months ended September 30, 2018, we granted 2.3 million restricted stock units and 0.2 million performance stock units at target performance under the 2011 Plan to certain employees. Restricted stock units are stock awards that vest over a two- to three-year service period 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 three-year cliff vesting with payouts based on our cumulative distributable cash flow per share from January 1, 2018 through December 31, 2020 compared to a pre-established performance target. The number of shares that may be earned at the end of the vesting period ranges from 50 to 200 percent of the target award amount if the threshold performance is met. 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.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Share-based compensation costs, pre-tax:
Equity awards	$	25		$	10		$	64		$	25
Liability awards	13			12			45			56
Total share-based compensation	38			22			109			81
Capitalized share-based compensation	(7		)	(4		)	(20		)	(17		)
Total share-based compensation expense	$	31		$	18		$	89		$	64
Tax benefit associated with share-based compensation expense	$	1		$	1		$	3		$	3

For further discussion of our equity incentive plans, see Note 16—Share-Based Compensation of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

24

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 14—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 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 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.

The following table reconciles basic and diluted weighted average common shares outstanding for the three and nine months ended September 30, 2018 and 2017 (in millions, except per share data):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
Weighted average common shares outstanding:
Basic	247.2		232.6			241.9		232.5
Dilutive unvested stock	3.0		—			2.7		—
Diluted	250.2		232.6			244.6		232.5
Basic net income (loss) per share attributable to common stockholders	$	0.26	$	(1.24	)	$	1.67	$	(2.24	)
Diluted net income (loss) per share attributable to common stockholders	$	0.26	$	(1.24	)	$	1.65	$	(2.24	)

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Unvested stock (1)	2.0	1.5	2.3	1.5
Convertible notes (2)	17.3	16.8	17.1	16.8
Total potentially dilutive common shares	19.3	18.3	19.4	18.3

(1) Does not include 0.4 million shares for each of the three and nine months ended September 30, 2018 and 5.1 million shares for each of the three and nine months ended September 30, 2017, of unvested stock because the performance conditions had not yet been satisfied as of September 30, 2018 and 2017, respectively.

(2) Includes number of shares in aggregate issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes. There were no shares included in the computation of diluted net income (loss) per share for the 2025 CCH HoldCo II Convertible Senior Notes because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of September 30, 2018.

NOTE 15—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of September 30, 2018, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

Obligations under Certain Guarantee Contracts

Cheniere and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate transactions with third parties. These arrangements include financial guarantees, letters of credit and debt guarantees. As of September 30, 2018 and December 31, 2017, there were no liabilities recognized under these guarantee arrangements.

25

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

Parallax Litigation

In 2015, our wholly owned subsidiary, Cheniere LNG Terminals, LLC (“CLNGT”), entered into discussions with Parallax Enterprises, LLC (“Parallax Enterprises”) regarding the potential joint development of two liquefaction plants in Louisiana (the “Potential Liquefaction Transactions”). While the parties negotiated regarding the Potential Liquefaction Transactions, CLNGT loaned Parallax Enterprises approximately $46 million, as reflected in a secured note dated April 23, 2015, as amended on June 30, 2015, September 30, 2015 and November 4, 2015 (the “Secured Note”). The Secured Note was secured by all assets of Parallax Enterprises and its subsidiary entities. On June 30, 2015, Parallax Enterprises’ parent entity, Parallax Energy LLC (“Parallax Energy”), executed a Pledge and Guarantee Agreement further securing repayment of the Secured Note by providing a parent guaranty and a pledge of all of the equity of Parallax Enterprises in satisfaction of the Secured Note (the “Pledge Agreement”). CLNGT and Parallax Enterprises never executed a definitive agreement to pursue the Potential Liquefaction Transactions. The Secured Note matured on December 11, 2015, and Parallax Enterprises failed to make payment. On February 3, 2016, CLNGT filed an action against Parallax Energy, Parallax Enterprises and certain of Parallax Enterprises’ subsidiary entities, styled Cause No. 4:16-cv-00286, Cheniere LNG Terminals, LLC v. Parallax Energy LLC, et al., in the United States District Court for the Southern District of Texas (the “Texas Federal Suit”). CLNGT asserted claims in the Texas Federal Suit for (1) recovery of all amounts due under the Secured Note and (2) declaratory relief establishing that CLNGT is entitled to enforce its rights under the Secured Note and Pledge Agreement in accordance with each instrument’s terms and that CLNGT has no obligations of any sort to Parallax Enterprises concerning the Potential Liquefaction Transactions. On March 11, 2016, Parallax Enterprises and the other defendants in the Texas Federal Suit moved to dismiss the suit for lack of subject matter jurisdiction. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery.

On March 11, 2016, Parallax Enterprises filed a suit against us and CLNGT styled Civil Action No. 62-810, Parallax Enterprises LLP v. Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC, in the 25th Judicial District Court of Plaquemines Parish, Louisiana (the “Louisiana Suit”), wherein Parallax Enterprises asserted claims for breach of contract, fraudulent inducement, negligent misrepresentation, detrimental reliance, unjust enrichment and violation of the Louisiana Unfair Trade Practices Act. Parallax Enterprises predicated its claims in the Louisiana Suit on an allegation that we and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises sought $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, we and CLNGT removed the Louisiana Suit to the United States District Court for the Eastern District of Louisiana, which subsequently transferred the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was assigned Civil Action No. 4:16-cv-01628 and transferred to the same judge presiding over the Texas Federal Suit for coordinated handling. On August 22, 2016, Parallax Enterprises voluntarily dismissed all claims asserted against CLNGT and us in the Louisiana Suit without prejudice to refiling.

On July 27, 2017, the Parallax entities named as defendants in the Texas Federal Suit reurged their motion to dismiss and simultaneously filed counterclaims against CLNGT and third party claims against us for breach of contract, breach of fiduciary duty, promissory estoppel, quantum meruit and fraudulent inducement of the Secured Note and Pledge Agreement, based on substantially the same factual allegations Parallax Enterprises made in the Louisiana Suit. These Parallax entities also simultaneously filed an action styled Cause No. 2017-49685, Parallax Enterprises, LLC, et al. v. Cheniere Energy, Inc., et al., in the 61st District Court of Harris County, Texas (the “Texas State Suit”), which asserts substantially the same claims these entities asserted in the Texas Federal Suit. On July 31, 2017, CLNGT withdrew its opposition to the dismissal of the Texas Federal Suit without prejudice on jurisdictional grounds and the federal court subsequently dismissed the Texas Federal Suit without prejudice. We and CLNGT simultaneously filed an answer and counterclaims in the Texas State Suit, asserting the same claims CLNGT had previously asserted in the Texas Federal Suit. Additionally, CLNGT filed third party claims against Parallax principals Martin Houston, Christopher Bowen Daniels, Howard Candelet and Mark Evans, as well as Tellurian Investments, Inc., Driftwood LNG, LLC, Driftwood LNG Pipeline LLC and Tellurian Services LLC, formerly known as Parallax Services LLC, including claims for tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement, fraudulent transfer, conspiracy/aiding and abetting. Discovery in the Texas State Suit is ongoing. Trial is currently set for June 2019.

We do not expect that the resolution of this litigation will have a material adverse impact on our financial results.

26

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 16—LEASES

In December 2015, we entered into a lease agreement for marine services related to the CCL Project that was classified as a capital lease. The service term of this lease commenced during the three months ended September 30, 2018, and we received two of the four tug vessels under this capital lease, which are recorded within property, plant and equipment, net on our Consolidated Balance Sheets. As of September 30, 2018, the total minimum lease payments related to the tug vessels received was $50 million, of which $20 million represents imputed interest, $1 million represents the current portion of capital lease obligations and $29 million represents the non-current portion of capital lease obligations.

NOTE 17—CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:

	Percentage of Total Third-Party Revenues				Percentage of Accounts Receivable from Third Parties
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2018	2017	2018	2017	2018	2017
Customer A	17%	19%	18%	25%	26%	28%
Customer B	15%	14%	15%	13%	24%	16%
Customer C	15%	20%	20%	10%	20%	14%
Customer D	18%	—%	13%	—%	18%	—%
Customer E	—%	20%	*	19%	—%	—%
Customer F	*	*	*	*	—%	15%

* Less than 10%

NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	552	$	360
Non-cash investing and financing activities:
Acquisition of non-controlling interest in Cheniere Holdings	702		—
Contribution of assets to equity method investee	—		14
Acquisition of assets under capital lease	30		—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $471 million and $426 million as of September 30, 2018 and 2017, respectively.

27

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 19—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of September 30, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We anticipate electing the optional transition method to initially apply the standard at the January 1, 2019 adoption date. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period:

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 11—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things: 

• statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all;

• statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;

• statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;

• statements relating to 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 such 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 our planned development and construction of additional Trains and pipelines, including the financing of such Trains;

• 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 marketing of volumes expected to be made available to our integrated marketing function; 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,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” 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 year ended December 31, 2017. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

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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 

• Liquidity and Capital Resources

• Results of Operations 

• Off-Balance Sheet Arrangements  

• Summary of Critical Accounting Estimates 

• Recent Accounting Standards

Overview of Business

Cheniere, a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. Our vision is to provide clean, secure and affordable energy to the world, while responsibly delivering a reliable, competitive and integrated source of LNG, in a safe and rewarding work environment. We own and operate the Sabine Pass LNG terminal in Louisiana 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 September 30, 2018, we owned 100% of the general partner interest and 48.6% of the limited partner interest in Cheniere Partners. We are currently developing and constructing two natural gas liquefaction and export facilities. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG.

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “SPL Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, SPL. Cheniere Partners plans to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is undergoing commissioning and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.5 to 4.9 mtpa of LNG. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. 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 a wholly owned subsidiary, CTPL.

We are developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal near Corpus Christi, Texas, and a pipeline facility (collectively, the “CCL Project”) through wholly owned subsidiaries CCL and CCP, respectively. The CCL Project is being developed for three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The CCL Project is being developed in stages. The first stage (“Stage 1”) includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the CCL Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, one LNG storage tank and the completion of the second partial berth. The CCL Project also includes a 23-mile natural gas supply pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the

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“Corpus Christi Pipeline”). Stages 1 and 2 are currently under construction, and construction of the Corpus Christi Pipeline was completed during the second quarter of 2018. Train 1 has commenced commissioning activities.

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”) and filed an application with FERC in June 2018 for seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa and one LNG storage tank. We remain focused on expansion of our existing sites by leveraging existing infrastructure. We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision (“FID”). We have made an equity investment in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”). Midship Pipeline is developing a pipeline (the “Midship Project”) with expected capacity of up to 1.44 million Dekatherms per day that will connect new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project. Construction of the Midship Project will commence based upon, among other things, obtaining the required authorization from the FERC and adequate financing to construct the proposed project.

Overview of Significant Events

Our significant accomplishments since January 1, 2018 and through the filing date of this Form 10-Q include the following:

Strategic

• In May 2018, our board of directors made a positive FID with respect to Stage 2 of the CCL Project and issued a full notice to proceed to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) under the EPC contract for Stage 2.

• In June 2018, we filed an application with the FERC with respect to Corpus Christi Stage 3, consisting of seven midscale liquefaction Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa and one LNG storage tank.

• We entered into the following agreements:

◦ In September 2018, we entered into a 15-year SPA with Vitol Inc. for the sale of approximately 0.7 mtpa of LNG beginning in 2018.

◦ In August 2018, we entered into a 25-year SPA with CPC Corporation, Taiwan for the sale of approximately 2.0 mtpa of LNG beginning in 2021.

◦ In February 2018, we entered into two SPAs with PetroChina International Company Limited, a subsidiary of China National Petroleum Corporation, for the sale of approximately 1.2 mtpa of LNG through 2043, with a portion of the supply beginning in 2018 and the balance beginning in 2023.

◦ In January 2018, we entered into a 15-year SPA with Trafigura Pte Ltd for the sale of approximately 1.0 mtpa of LNG beginning in 2019.

Operational

• As of October 31, 2018, more than 215 cargoes have been produced, loaded and exported from the SPL Project year to date. To date, over 475 cumulative LNG cargoes have been exported from the SPL Project, with deliveries to 29 countries and regions worldwide.

• In August 2018, feed gas was introduced to Train 1 of the CCL Project as part of the commissioning process. In September 2018, feed gas was introduced to Train 5 of the SPL Project as part of the commissioning process, and first LNG production from Train 5 occurred in October 2018.

Financial

• In September 2018, we closed the previously announced merger of Cheniere Holdings with our wholly owned subsidiary. As a result of the merger, all of the publicly-held shares of Cheniere Holdings not owned by us were canceled and shareholders received 0.4750 shares of our common stock for each publicly-held share of Cheniere Holdings.

• We completed the following debt transactions:

◦ In September 2018, Cheniere Partners issued an aggregate principal amount of $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”). Net proceeds of the offering of approximately $1.1 billion, after deducting commissions, fees and expenses, were used to prepay all of the outstanding indebtedness under

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Cheniere Partners’ credit facilities (the “CQP Credit Facilities”). As of September 30, 2018, only a $115 million revolving credit facility, which is currently undrawn, remains as part of the CQP Credit Facilities.

◦ In June 2018, CCH amended and restated its working capital facility (“CCH Working Capital Facility”) to increase total commitments under the CCH Working Capital Facility to $1.2 billion. Borrowings will be used for certain working capital requirements related to developing and placing into operations the CCL Project and for related business purposes.

◦ In May 2018, CCH amended and restated its existing credit facilities (the “CCH Credit Facility”) to increase total commitments under the CCH Credit Facility to $6.1 billion. Borrowings will be used to fund a portion of the costs of developing, constructing and placing into service the three Trains and the related facilities of the CCL Project and for related business purposes.

• We reached the following contractual milestones:

◦ In June 2018, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC (“BG”) relating to Train 3 of the SPL Project.

◦ In March 2018, the date of first commercial delivery was reached under the 20-year SPA with GAIL (India) Limited (“GAIL”) relating to Train 4 of the SPL Project.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, Cheniere, Cheniere Partners, SPL and the CCH Group operate with independent capital structures. 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 project debt and borrowings and operating cash flows;

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

• CCH Group through project debt and borrowings and equity contributions from Cheniere; and

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

The following table provides a summary of our liquidity position at September 30, 2018 and December 31, 2017 (in millions):

	September 30,		December 31,
	2018		2017
Cash and cash equivalents	$	989	$	722
Restricted cash designated for the following purposes:
SPL Project	649		544
Cheniere Partners and cash held by guarantor subsidiaries	808		1,045
CCL Project	220		227
Other	266		75
Available commitments under the following credit facilities:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	706		470
CQP Credit Facilities	115		220
CCH Credit Facility	1,646		2,087
CCH Working Capital Facility	884		186
$750 million Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	750		750

For additional information regarding our debt agreements, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

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Cheniere

Convertible Notes

In November 2014, we issued an aggregate principal amount of $1.0 billion of Convertible Unsecured Notes due 2021 (the “2021 Cheniere Convertible Unsecured Notes”). The 2021 Cheniere Convertible Unsecured Notes are convertible at the option of the holder into our common stock at the then applicable conversion rate, provided that the closing price of our common stock is greater than or equal to the conversion price on the date of conversion. In March 2015, we issued $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. We have the option to satisfy the conversion obligation for the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes with cash, common stock or a combination thereof.

Cheniere Revolving Credit Facility

In March 2017, we entered into the Cheniere Revolving Credit Facility that may be used 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.

The Cheniere Revolving Credit Facility matures on March 2, 2021 and contains representations, warranties and affirmative and negative covenants customary for companies like Cheniere 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) $100 million.

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).

Cash Receipts from Subsidiaries

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of September 30, 2018, we owned a 48.6% limited partner interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated 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 Cheniere Partners, SPLNG, SPL, CTPL, CCL and CCP. We received $57 million and $87 million in total service fees from these subsidiaries during the nine months ended September 30, 2018 and 2017, respectively.

Cheniere Partners

CQP Senior Notes

In September 2018, Cheniere Partners issued an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, in addition to the existing $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”), which are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (the “CQP Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP. The 2025 CQP Senior Notes and the 2026 CQP Senior Notes(collectively, the “CQP Senior Notes”) are governed by the same base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture (together with the CQP Base Indenture, the “2025 CQP Notes Indenture”) and the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”). The 2025 CQP Notes Indenture and the 2026 CQP Notes Indenture contain customary terms

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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, 2020 for the 2025 CQP Senior Notes and October 1, 2021 for the 2026 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 2025 CQP Notes Indenture and the 2026 CQP Notes Indenture, respectively, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020 for the 2025 CQP Senior Notes and October 1, 2021 for the 2026 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 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes and 105.625% of the aggregate principal amount of the 2026 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, 2020 through the maturity date of October 1, 2025 for the 2025 CQP Senior Notes and October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the 2025 CQP Notes Indenture and the 2026 CQP Notes Indenture, respectively.

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. After applying the proceeds from the 2026 CQP Senior Notes, the CQP Senior Notes became unsecured. 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 CQP Credit Facilities. The obligations under the CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) 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 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 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 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

CQP Credit Facilities

In February 2016, Cheniere Partners entered into the CQP Credit Facilities. The CQP Credit Facilities originally consisted of: (1) a $450 million CTPL tranche term loan that was used to prepay the $400 million term loan facility in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that was used to repay and redeem in November 2016 the approximately $2.1 billion of the senior notes previously issued by SPLNG, (3) a $125 million facility that could be used to satisfy a six-month debt service reserve requirement and (4) a $115 million revolving credit facility that may be used for general business purposes. In September 2017 and September 2018, Cheniere Partners issued the 2025 CQP Senior Notes and the 2026 CQP Senior Notes, respectively, and the net proceeds were used to prepay the outstanding term loans under the CQP Credit Facilities. As of September 30, 2018, only a $115 million revolving credit facility, which is currently undrawn, remains as part of the CQP Credit Facilities.

The CQP Credit Facilities mature on February 25, 2020. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 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 as long as certain conditions are satisfied. Under the CQP Credit Facilities, Cheniere Partners is required to hedge not less than 50% of the variable interest rate exposure on its projected aggregate outstanding balance, maintain a minimum debt service coverage ratio of at least 1.15x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55x in order to incur additional indebtedness to refinance a portion of the existing obligations.

The CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than (1) SPL and (2) certain subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

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Sabine Pass LNG Terminal

Liquefaction Facilities

We are developing, constructing and operating the SPL Project at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completion of Trains 1, 2, 3 and 4 of the SPL Project and commenced operating activities in May 2016, September 2016, March 2017 and October 2017, respectively. Train 5 of the SPL Project is undergoing commissioning and the following table summarizes the status as of September 30, 2018:

	SPL Train 5
Overall project completion percentage	98.5%
Completion percentage of:
Engineering	100%
Procurement	100%
Subcontract work	92.7%
Construction	97.8%
Date of expected substantial completion	1Q 2019

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

• Trains 1 through 4—FTA countries for a 30-year term, which commenced on May 15, 2016, and non-FTA countries for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).

• Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).

• Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from five to 10 years from the date the order was issued. In addition, SPL received an order providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes SPL was authorized but unable to export during any portion of the initial 20-year export period of such order.

In January 2018, the DOE issued orders authorizing SPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing January 2018, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).

Customers

SPL has entered into six fixed price SPAs with terms of at least 20 years (plus extension rights) with third parties to make available an aggregate amount of LNG that is between approximately 80% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 through 5. 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 equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, 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 sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs 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.

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Under SPL’s SPA with BG, BG has contracted for volumes related to Trains 3 and 4, for which the obligation to make volumes related to Train 3 available to BG has commenced and the obligation to make volumes related to Train 4 available to BG is expected to commence approximately one year after the date of first commercial delivery under SPL’s SPA with GAIL for Train 4.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.2 billion for Trains 1 through 3 and the SPA with GAIL for Train 4, increasing to $2.3 billion upon the date of first commercial delivery of Train 4 under the SPA with BG and to $2.9 billion upon the date of first commercial delivery of Train 5, with the applicable fixed fees starting from the date of first commercial delivery from the applicable Train, as specified in each SPA.

In addition, Cheniere Marketing has entered into an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers.

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 September 30, 2018, SPL had secured up to approximately 2,755TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts.

Construction

SPL entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 5 of the SPL Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk 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 5 of the SPL Project is approximately $3.1 billion reflecting amounts incurred under change orders through September 30, 2018. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.5 billion and $18.5 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Train 6

We will contemplate making an FID to commence construction of Train 6 of the SPL Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements and obtaining adequate financing to construct Train 6.

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 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 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually 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 2.0 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, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 3 of the SPL Project, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity.  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

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cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 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 September 30, 2018 and 2017, SPL recorded $7.5 million and during the nine months ended September 30, 2018 and 2017, SPL recorded $23 million and $15 million, respectively, 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 Trains 1 through 5 of the SPL Project will be financed through project debt and borrowings and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the SPL Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Train 5 of the SPL Project and to meet our currently anticipated capital, operating and debt service requirements. SPL began generating cash flows from operations from the SPL Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2, 3 and 4 subsequently achieved substantial completion in September 2016, March 2017 and October 2017, respectively. We realized offsets to LNG terminal costs of $82 million and $252 million in the three and nine months ended September 30, 2017, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations, during the testing phase for the construction of those Trains of the SPL Project. We did not realize any offsets to LNG terminal costs in the three and nine months ended September 30, 2018. 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 September 30, 2018 and December 31, 2017 (in millions):

	September 30,		December 31,
	2018		2017
Senior notes (1)	$	16,250	$	15,150
Credit facilities outstanding balance (2)	—		1,090
Letters of credit issued (3)	494		730
Available commitments under credit facilities (3)	706		470
Total capital resources from borrowings and available commitments (4)	$	17,450	$	17,440

(1) Includes SPL’s 5.625% Senior Secured Notes due 2021, 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”) and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”)(collectively, the “SPL Senior Notes”) and Cheniere Partners’ 2025 CQP Senior Notes and 2026 CQP Senior Notes.

(2) Includes outstanding balance under the SPL Working Capital Facility and CTPL and SPLNG tranche term loans outstanding under the CQP Credit Facilities.

(3) Consists of SPL Working Capital Facility. Does not include the letters of credit issued or available commitments under the CQP Credit Facilities, which are not specifically for the Sabine Pass LNG Terminal.

(4) Does not include Cheniere’s additional borrowings from the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes, which may be used for the Sabine Pass LNG Terminal.

For additional information regarding our debt agreements related to the Sabine Pass LNG Terminal, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

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SPL Senior Notes

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.

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 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 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.

Both the indenture governing the 2037 SPL Senior Notes (the “2037 SPL Senior Notes Indenture”) and the common indenture governing the remainder of the SPL Senior Notes(the “SPL Indenture”) include restrictive covenants. 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 SPL Working Capital Facility. Under the 2037 SPL Senior Notes Indenture and the SPL Indenture, 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. 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.

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“SPL Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“SPL Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the SPL Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the SPL Project, request an incremental increase in commitments of up to an additional $390 million. As of September 30, 2018 and December 31, 2017, SPL had $706 million and $470 million of available commitments and $494 million and $730 million aggregate amount of issued letters of credit under the SPL Working Capital Facility, respectively. SPL did not have any amounts outstanding under the SPL Working Capital Facility as of both September 30, 2018 and December 31, 2017.

The SPL Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. Loans deemed made in connection with a draw upon a letter of credit have a term of up to one year. SPL Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the SPL Working Capital Facility, (2) the date 15 days after such SPL Swing Line Loan is made and (3) the first borrowing date for a SPL Working Capital Loan or SPL Swing Line Loan occurring at least three business days following the date the SPL Swing Line Loan is made. SPL is required to reduce the aggregate outstanding principal amount of all SPL Working Capital Loans to zero for a period of five consecutive business days at least once each year.

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

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Corpus Christi LNG Terminal

Liquefaction Facilities

The CCL Project is being developed and constructed at the Corpus Christi LNG terminal. We have received authorization from the FERC to site, construct and operate Stages 1 and 2 of the CCL Project. The following table summarizes the overall project status of the CCL Project as of September 30, 2018:

	CCL Stage 1		CCL Stage 2
Overall project completion percentage	93.9%		36.3%
Completion percentage of:
Engineering	100%		79.2%
Procurement	100%		57.3%
Subcontract work	83.6%		5.8%
Construction	86.9%		5.9%
Expected date of substantial completion	Train 1	1Q 2019	Train 3	2H 2021
	Train 2	2H 2019

Separate from the CCH Group, we are also developing Corpus Christi Stage 3, adjacent to the CCL Project. We filed an application with FERC in June 2018 for seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa and one LNG storage tank. We remain focused on leveraging infrastructure through the expansion of our existing sites.

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 for a 25-year term and to non-FTA countries for a 20-year term up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas.

• Corpus Christi Stage 3—FTA countries for a 20-year term in an amount equivalent to 514 Bcf/yr (approximately 10 mtpa) of natural gas (the “Stage 3 FTA”). The application for authorization to export that same 514 Bcf/yr of domestically produced LNG by vessel to non-FTA countries is currently pending before the DOE (the “Stage 3 Non-FTA”).

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from seven to 10 years from the date the order was issued.

In June 2018, Cheniere requested that DOE vacate the Stage 3 FTA and permit Cheniere to withdraw the pending Stage 3 Non-FTA. These requests were made due to certain changes to Corpus Christi Stage 3.

In conjunction with the submission on June 28, 2018 of Cheniere’s FERC application for Corpus Christi Stage 3, Cheniere submitted a new application for long-term multi-contract authorization to export up to a combined total of 582.14 Bcf/yr (approximately 11.45 mtpa) of natural gas to FTA countries for a 25-year term and to non-FTA countries for a 20-year term. The term of each authorization is expected to begin on the earlier of the date of first commercial export of LNG produced by Corpus Christi Stage 3 or the date which is seven years from the issuance of such authorizations.

Customers

CCL entered into ten fixed-price SPAs generally with terms of 20 years (plus extension rights) with nine third parties to make available an aggregate amount of LNG that is between approximately 75% to 85% of the expected aggregate adjusted nominal production capacity of Trains 1 through 3. Under these ten SPAs, the customers will purchase LNG from CCL 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. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, 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

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related to, and operating and maintenance costs 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 fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1 and increasing to approximately $1.4 billion for Train 2, in each case upon the date of first commercial delivery for the respective Train, and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the CCL Project.

In addition, Cheniere Marketing has entered into SPAs with CCL to purchase 15 TBtu per annum of LNG and any LNG produced by CCL in excess of that required for other customers at Cheniere Marketing’s option.

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 September 30, 2018, CCL had secured up to approximately 2,640TBtu of natural gas feedstock through long-term natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.

Construction

CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Stages 1 and 2 of the CCL Project under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause CCL to enter into a change order, or CCL agrees with Bechtel to a change order.

The total contract prices of the EPC contract for Stage 1 and the EPC contract for Stage 2, which do not include the Corpus Christi Pipeline, are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through September 30, 2018. Total expected capital costs for Trains 1 through 3 are estimated to be between $11.0 billion and $12.0 billion before financing costs and between $15.0 billion and $16.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

Pipeline Facilities

In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended, authorizing CCP to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline is designed to transport 2.25 Bcf/d of natural gas feedstock required by the CCL Project from the existing regional natural gas pipeline grid. The construction of the Corpus Christi Pipeline commenced in January 2017 and was completed in the second quarter of 2018.

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Capital Resources

We expect to finance the construction costs of the CCL Project from one or more of the following: project financing, operating cash flows from CCL and CCP and equity contributions to our subsidiaries. The following table provides a summary of our capital resources from borrowings and available commitments for the CCL Project, excluding equity contributions to our subsidiaries, at September 30, 2018 and December 31, 2017 (in millions):

	September 30,		December 31,
	2018		2017
Senior notes (1)	$	4,250	$	4,250
11% Convertible Senior Secured Notes due 2025 (2)	1,000		1,000
Credit facilities outstanding balance (3)	4,492		2,485
Letters of credit issued (3)	316		164
Available commitments under credit facilities (3)	2,530		2,273
Total capital resources from borrowings and available commitments (4)	$	12,588	$	10,172

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

(2) Aggregate original principal amount before debt discount and debt issuance costs.

(3) Includes CCH Credit Facility and CCH Working Capital Facility.

(4) Does not include Cheniere’s additional borrowings from 2021 Cheniere Convertible Unsecured Notes, 2045 Cheniere Convertible Senior Notes and Cheniere Revolving Credit Facility, which may be used for the CCL Project.

For additional information regarding our debt agreements related to the CCL Project, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

2025 CCH HoldCo II Convertible Senior Notes

In May 2015, CCH HoldCo II issued $1.0 billion aggregate principal amount of 11% Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes”) on a private placement basis. The 2025 CCH HoldCo II Convertible Senior Notes are convertible at the option of CCH HoldCo II or the holders, provided that various conditions are met. CCH HoldCo II is restricted from making distributions to Cheniere under agreements governing its indebtedness generally until, among other requirements, Trains 1 and 2 of the CCL Project are in commercial operation and a historical debt service coverage ratio and a projected fixed debt service coverage ratio of 1.20:1.00 are achieved.

In May 2018, the amended and restated note purchase agreement under which the 2025 CCH HoldCo II Convertible Senior Notes were issued was subsequently amended in connection with commercialization and financing of Train 3 of the CCL Project.  All terms of the 2025 CCH HoldCo II Convertible Senior Notes substantially remained the same to those described in Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

CCH Senior Notes

The CCH Senior Notes are jointly and severally guaranteed by its subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (the “CCH Guarantors”).

The indenture governing the CCH Senior Notes(the “CCH Indenture”) contains 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.

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At any time prior to six months before the respective dates of maturity for each series 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 CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. CCH also may at any time within six months of the respective dates of maturity for each series of the CCH Senior Notes, 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

In May 2018, CCH amended and restated the CCH Credit Facility to increase total commitments under the CCH Credit Facility to $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 September 30, 2018 and December 31, 2017, CCH had $1.6 billion and $2.1 billion of available commitments and $4.5 billion and $2.5 billion loans outstanding under the CCH Credit Facility, respectively.

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 distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of Trains 1 and 2 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

In June 2018, CCH amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility to $1.2 billion. The CCH Working Capital Facility is intended to be used for loans to CCH (“CCH Working Capital Loans”), the issuance of letters of credit on behalf of CCH, as well as for swing line loans to CCH (“CCH Swing Line Loans”) for certain working capital requirements related to developing and placing into operations 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 under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility. As of September 30, 2018 and December 31, 2017, CCH had $884 million and $186 million of available commitments and $316 million and $164 million aggregate amount of issued letters of credit under the CCH Working Capital Facility, respectively. CCH did not have any amounts outstanding under the CCH Working Capital Facility as of both September 30, 2018 and December 31, 2017.

The CCH Working Capital Facility matures on June 29, 2023, and CCH may prepay the CCH Working Capital Loans, CCH Swing Line 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 Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the CCH Working Capital Facility, (2) the date that is 15 days after such CCH Swing Line Loan is made and (3) the first borrowing date for a CCH Working Capital Loan or CCH Swing Line Loan occurring at least four business days following the date the CCH Swing Line Loan is made. 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.

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Restrictive Debt Covenants

As of September 30, 2018, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Marketing

We market and sell LNG produced by the SPL Project and the CCL Project that is not required for other customers through our integrated marketing function. We are developing a portfolio of long-, medium- and short-term SPAs to transport and unload commercial LNG cargoes to locations worldwide, which is primarily sourced by LNG produced by the SPL Project and the CCL Project but supplemented by volume procured from other locations worldwide, as needed. As of September 30, 2018, we have sold or have options to sell approximately 3,958 TBtu of LNG to be delivered to customers between 2018 and 2045.  The cargoes have been sold either on a free on board (“FOB”) basis (delivered to the customer at the Sabine Pass LNG terminal) or a delivered at terminal (“DAT”) basis (delivered to the customer at their LNG receiving terminal). We have chartered LNG vessels to be utilized in DAT transactions. In addition, we have entered into a long-term agreement to sell LNG cargoes on a DAT basis that is conditioned upon the buyer achieving certain milestones.

Cheniere Marketing entered into uncommitted trade finance facilities with available commitments of $370 million as of September 30, 2018, 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 September 30, 2018 and December 31, 2017, Cheniere Marketing had $129 million and $2 million, respectively, in standby letters of credit and guarantees outstanding under the finance facilities. As of September 30, 2018 and December 31, 2017, Cheniere Marketing had $66 million and zero, respectively, in loans outstanding under the finance facilities. Cheniere Marketing pays interest or 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.  We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require acceptable commercial and financing arrangements before we make an FID. We have made an equity investment in Midship Pipeline, which is developing a pipeline with expected capacity of up to 1.44 million Dekatherms per day that will connect new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the nine months ended September 30, 2018 and 2017 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table. 

	Nine Months Ended September 30,
	2018			2017
Operating cash flows	$	1,504		$	895
Investing cash flows	(2,722		)	(2,926		)
Financing cash flows	1,537			2,779
Net increase in cash, cash equivalents and restricted cash	319			748
Cash, cash equivalents and restricted cash—beginning of period	2,613			1,827
Cash, cash equivalents and restricted cash—end of period	$	2,932		$	2,575

Operating Cash Flows

Our operating cash inflows during the nine months ended September 30, 2018 and 2017 were $1.5 billion and $895 million, respectively. The $609 million increase in operating cash inflows in 2018 compared to 2017 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the of additional Trains that were operating at the SPL Project in 2018. During the nine months ended September 30, 2018, Trains 1 through 4 were

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operational, whereas during the nine months ended September 30, 2017, Trains 1 and 2 were operational for nine months and Train 3 was operational for six months.

Investing Cash Flows

Investing cash outflows during the nine months ended September 30, 2018 and 2017 were $2.7 billion and $2.9 billion, respectively, and were primarily used to fund the construction costs for the SPL Project and the CCL Project. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, during the during the nine months ended September 30, 2018, we invested an additional $25 million in our equity method investment Midship Holdings, offset by proceeds of $12 million from the sale of our cost method investments. During the nine months ended September 30, 2017, we invested an additional $41 million in our equity method investment Midship Holdings and made payments of $18 million primarily for infrastructure to support the CCL Project, which was partially offset by the receipt of $36 million from the return of collateral payments previously paid for the CCL Project.

Financing Cash Flows

Financing cash inflows during the nine months ended September 30, 2018 were $1.5 billion, primarily as a result of:

• issuance of an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which was used to prepay $1.1 billion of the outstanding borrowings under the CQP Credit Facilities;

• $2.3 billion of borrowings and $281 million in repayments under the CCH Credit Facility;

• $14 million of borrowings and $14 million in repayments under the CCH Working Capital Facility;

• $66 million of net borrowings related to our Cheniere Marketing trade financing facilities;

• $53 million of debt issuance costs related to up-front fees paid upon the closing of these transactions;

• $16 million in debt extinguishment costs related to the prepayments of the CQP Credit Facilities and the CCH Credit Facility;

• $435 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings;

• $10 million paid for tax withholdings for share-based compensation; and

• $7 million of transaction costs to acquire additional interest of Cheniere Holdings.

Financing cash inflows during the nine months ended September 30, 2017 were $2.8 billion, primarily as a result of:

• issuances of SPL’s senior notes for an aggregate principal amount $2.15 billion;

• $55 million of borrowings and $369 million of repayments made under the credit facilities SPL entered into in June 2015;

• $110 million of borrowings and $334 million of repayments made under the SPL Working Capital Facility;

• $1.2 billion of borrowings under the CCH Credit Facility;

• issuance of aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, which was used to prepay $1.4 billion of outstanding borrowings under the CCH Credit Facility;

• $24 million of borrowings and $24 million of repayments made under the CCH Working Capital Facility;

• issuance of an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which was used to prepay $1.5 billion of the outstanding borrowings under the CQP Credit Facilities;

• $17 million in net borrowings under the Cheniere Marketing trade finance facilities;

• $85 million of debt issuance costs related to up-front fees paid upon the closing of these transactions;

• $60 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; and

• $4 million paid for tax withholdings for share-based compensation.

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Results of Operations

The following table summarizes the volumes of operational and commissioning LNG cargoes that were loaded from the SPL Project and recognized on our Consolidated Financial Statements during the three and nine months ended September 30, 2018:

	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
(in TBtu)	Operational		Commissioning	Operational		Commissioning
Volumes loaded during the current period	228		—	691		—
Volumes loaded during the prior period but recognized during the current period	3		—	43		—
Less: volumes loaded during the current period and in transit at the end of the period	(3	)	—	(3	)	—
Total volumes recognized in the current period	228		—	731		—

Our consolidated net income attributable to common stockholders was $65 million, or $0.26 per share (basic and diluted), in the three months ended September 30, 2018, compared to net loss attributable to common stockholders of $289 million, or $1.24 per share (basic and diluted), in the three months ended September 30, 2017. This $354 million increase in net income attributable to common stockholders in 2018 was primarily attributable to the nonrecurrence of non-cash amortization of the beneficial conversion feature on Cheniere Partners’ Class B units that occurred during the comparable period in 2017, partially offset by increased allocation of Cheniere Partners’ net income allocated to non-controlling interest holders. Further contributing to the increase was increased income from operations due to additional Trains operating between periods, increased derivative gain, net and decreased loss on modification or extinguishment of debt, partially offset by increased interest expense, net of amounts capitalized.

Our consolidated net income attributable to common stockholders was $404 million, or $1.67 per share—basic and $1.65 per share—diluted, in the nine months ended September 30, 2018, compared to net loss attributable to common stockholders of $520 million, or $2.24 per share (basic and diluted), in the nine months ended September 30, 2017. This $924 million increase in net income attributable to common stockholders in 2018 primarily attributable to the nonrecurrence of non-cash amortization of the beneficial conversion feature on Cheniere Partners’ Class B units that occurred during the comparable period in 2017, partially offset by increased allocation of Cheniere Partners’ net income allocated to non-controlling interest holders. Further contributing to the increase was increased income from operations due to additional Trains operating between the periods, increased derivative gain, net and decreased loss on modification or extinguishment of debt, which were partially offset by increased interest expense, net of amounts capitalized.

Revenues

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2018		2017		Change		2018		2017		Change
LNG revenues	$	1,719	$	1,332	$	387	$	5,327	$	3,646	$	1,681
Regasification revenues	66		65		1		196		195		1
Other revenues	30		5		25		73		12		61
Other—related party	4		1		3		8		2		6
Total revenues	$	1,819	$	1,403	$	416	$	5,604	$	3,855	$	1,749

We begin recognizing LNG revenues from the SPL Project following the substantial completion and the commencement of operating activities of the respective Trains. During the nine months ended September 30, 2018, Trains 1 through 4 were operational, whereas during the nine months ended September 30, 2017, Trains 1 and 2 were operational for nine months and Train 3 was operational for six months. The increase in revenues for the three and nine months ended September 30, 2018 from the comparable periods in 2017 was primarily attributable to the increased volume of LNG sold following the achievement of substantial completion of these Trains. We expect our LNG revenues to increase in the future upon Train 5 of the SPL Project and Trains 1 through 3 of the CCL Project becoming operational.

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. We realized offsets to LNG terminal costs of $82 million corresponding to 14 TBtu of LNG in the

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three months ended September 30, 2017 and $252 million corresponding to 40 TBtu of LNG in the nine months ended September 30, 2017 that were related to the sale of commissioning cargoes. There were no commissioning cargoes sold that were realized as offsets to LNG terminal costs in the three and nine months ended September 30, 2018.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
LNG revenues (in millions):
LNG from the SPL Project sold under SPL’s third party long-term SPAs	$	1,182	$	715		$	3,293	$	1,669
LNG from the SPL Project sold by our integrated marketing function	316		200			1,619		1,337
LNG procured from third parties	208		427			394		631
Other revenues and derivative gains (losses)	13		(10		)	21		9
Total LNG revenues	$	1,719	$	1,332		$	5,327	$	3,646
Volumes sold as LNG revenues (in TBtu):
LNG from the SPL Project sold under SPL’s third party long-term SPAs	196		118			550		275
LNG from the SPL Project sold by our integrated marketing function	32		33			181		176
LNG procured from third parties	23		45			44		64
Total volumes sold as LNG revenues	251		196			775		515

Operating costs and expenses

	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions)	2018		2017		Change			2018		2017		Change
Cost of sales	$	1,027	$	824	$	203		$	3,078	$	2,140	$	938
Operating and maintenance expense	170		114		56			457		309		148
Development expense	2		3		(1		)	6		7		(1		)
Selling, general and administrative expense	74		64		10			214		179		35
Depreciation and amortization expense	113		92		21			333		252		81
Restructuring expense	—		—		—			—		6		(6		)
Impairment expense and loss on disposal of assets	8		9		(1		)	8		15		(7		)
Total operating costs and expenses	$	1,394	$	1,106	$	288		$	4,096	$	2,908	$	1,188

Our total operating costs and expenses increased during the three and nine months ended September 30, 2018 from the three and nine months ended September 30, 2017, primarily as a result of additional Trains that were operating between the periods. There were four Trains operating during the nine months ended September 30, 2018, whereas two Trains were operating for nine months and a third Train was operating for six months during the comparable period in 2017.

Cost of sales increased during the three and nine months ended September 30, 2018 from the comparable periods in 2017, primarily as a result of the increase in operating Trains during 2018. Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project, to the extent those costs are not utilized for the commissioning process. The increase during the three and nine months ended September 30, 2018 from the comparable periods in 2017 was primarily related to the increase in the volume of natural gas feedstock, partially offset by lower prices of natural gas feedstock between the periods. Cost of sales also includes vessel charter costs, gains and losses from derivatives associated with economic hedges to secure natural gas feedstock for the SPL Project and CCL Project, port and canal fees, variable transportation and storage costs and other costs to convert natural gas into LNG.

Operating and maintenance expense increased during the three and nine months ended September 30, 2018 from the comparable periods in 2017, as a result of the increase in operating Trains during 2018. Operating and maintenance expense primarily includes costs associated with operating and maintaining the SPL Project and CCL Project. The increase during the three and nine months ended September 30, 2018 from the comparable periods in 2017 was primarily related to payroll and benefit

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costs of operations personnel, natural gas transportation and storage capacity demand charges and third-party service and maintenance contract costs. Operating and maintenance expense also includes TUA reservation charges as a result of payments under the partial TUA assignment agreement with Total, insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the three and nine months ended September 30, 2018 from the three and nine months ended September 30, 2017 as a result of an increased number of operational Trains, as the assets related to the Trains of the SPL Project began depreciating upon reaching substantial completion.

Impairment expense and loss on disposal of assets decreased during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. The impairment expense and loss on disposal of assets recognized during the nine months ended September 30, 2018 related to the write down of prepaid assets. The impairment expense and loss on disposal of assets recognized during the nine months ended September 30, 2017 related to write down of assets used in non-core operations outside of our liquefaction activities.

We expect our operating costs and expenses to generally increase in the future upon Train 5 achieving substantial completion, although certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized, as well as upon Trains 1 through 3 of the CCL Project becoming operational.

Other expense (income)

	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions)	2018			2017			Change			2018			2017			Change
Interest expense, net of capitalized interest	$	221		$	186		$	35		$	653		$	539		$	114
Loss on modification or extinguishment of debt	12			25			(13		)	27			100			(73		)
Derivative loss (gain), net	(23		)	2			(25		)	(132		)	37			(169		)
Other income	(15		)	(4		)	(11		)	(32		)	(11		)	(21		)
Total other expense	$	195		$	209		$	(14	)	$	516		$	665		$	(149	)

Interest expense, net of capitalized interest, increased during the three and nine months ended September 30, 2018 compared to the three and nine months ended September 30, 2017, as a result of increased outstanding debt (before unamortized premium, discount and debt issuance costs, net) from $25.7 billion as of September 30, 2017 to $28.3 billion as of September 30, 2018 primarily due to increased borrowings under the CCH Credit Facility, as well as a decrease in the portion of total interest costs that could be capitalized as additional Trains of the SPL Project completed construction between the periods. For the three months ended September 30, 2018 and 2017, we incurred $426 million and $389 million of total interest cost, respectively, of which we capitalized $205 million and $203 million, respectively, which was primarily related to the construction of the SPL Project and the CCL Project. For the nine months ended September 30, 2018 and 2017, we incurred $1.2 billion and $1.1 billion of total interest cost, respectively, of which we capitalized $589 million and $581 million, respectively, which was primarily related to the construction of the SPL Project and the CCL Project.

Loss on modification or extinguishment of debt decreased during the three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017. Loss on modification or extinguishment of debt of $12 million recognized in 2018 was attributable to the incurrence of third party fees and write off of unamortized debt issuance costs in September 2018 as a result of the termination of approximately $1.2 billion of commitments under the CQP Credit Facilities in connection with the issuance of the 2026 CQP Senior Notes. Additionally, loss on modification or extinguishment of debt of $15 million was recognized in June 2018 relating to the incurrence of third party fees and write off of unamortized debt issuance costs as a result of the amendment and restatement of the CCH Credit Facility. Loss on modification or extinguishment of debt recognized in 2017 was attributable to the write-offs of debt issuance costs of (1) $42 million in March 2017 upon termination of the remaining available balance of $1.6 billion under SPL’s previous credit facilities in connection with the issuance of the 2028 SPL Senior Notes and the 2037 SPL Senior Notes; (2) the write-off of $33 million in May 2017 upon the prepayment of approximately $1.4 billion of outstanding borrowings under the CCH Credit Facility in connection with the issuance of the 2027 CCH Senior Notes; and (3) $25 million in September 2017 related to the prepayment of $1.5 billion of the outstanding indebtedness under the CQP Credit Facilities in connection with the issuance of the 2025 CQP Senior Notes.

Derivative gain, net increased during the three and nine months ended September 30, 2018 compared to the three and nine months ended September 30, 2017, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods.

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During the nine months ended September 30, 2018, we also recognized a $5 million gain in June 2018 upon the termination of interest rate swaps associated with the amendment and restatement of the CCH Credit Facility. During the nine months ended September 30, 2017, we recognized a $7 million loss upon the termination of interest rate swaps associated with the termination of SPL’s previous credit facilities and a $13 million loss in May 2017 in conjunction with the termination of approximately $1.4 billion of commitments under the CCH Credit Facility.

Other

	Three Months Ended September 30,								Nine Months Ended September 30,
(in millions)	2018			2017		Change			2018			2017		Change
Income tax benefit (provision)	$	(3	)	$	2	$	(5	)	$	(15	)	$	1	$	(16	)
Net income attributable to non-controlling interest	162			379		(217		)	573			803		(230		)

Changes in the income tax recorded between comparative periods are primarily attributable to fluctuations in the profitability of our U.K. integrated marketing function. The effective tax rates during the three and nine months ended September 30, 2018 and 2017 were lower than the 21% and 35% federal statutory rates during the 2018 and 2017 interim periods primarily as a result of maintaining a valuation allowance against our federal and state net deferred tax assets.

Net income attributable to non-controlling interest decreased during the three and nine months ended September 30, 2018 from the three and nine months ended September 30, 2017 due to the nonrecurrence of non-cash amortization of the beneficial conversion feature on Cheniere Partners’ Class B units that occurred during the comparable periods in 2017, which was partially offset by the increase in consolidated net income recognized by Cheniere Partners in which the non-controlling interests are held, adjusting for the increase in the share of Cheniere Partners’ net income that is attributed to non-controlling interest holders as a result of changes in ownership percentages between years. Net income attributable to non-controlling interest during the three and nine months ended September 30, 2017 included approximately $370 million and $748 million due to amortization of the beneficial conversion feature on Cheniere Partners’ Class B units, which ceased upon the conversion of Cheniere Partners’ Class B units into common units. The consolidated net income recognized by Cheniere Partners increased from $23 million to $307 million in the three months ended September 30, 2017 to three months ended September 30, 2018 and from $116 million to $923 million in the nine months ended September 30, 2017 to nine months ended September 30, 2018, primarily as a result of the additional Trains that were operating at the SPL Project between the periods. Partially offsetting the decrease in net income attributable to non-controlling interest was an increase due to the increase in ownership percentage by non-controlling interest holders between the periods as a result of the conversion of Cheniere Partners’ Class B units into common units on August 2, 2017.

We expect the portion of our net income attributable to non-controlling interest to generally decrease in the future as a result of our merger with Cheniere Holdings, in which all publicly-held shares of Cheniere Holdings were canceled and the non-controlling interest in Cheniere Holdings was reduced to zero.

Off-Balance Sheet Arrangements

We have interests in an unconsolidated variable interest entity (“VIE”) as discussed in Note 7—Other Non-Current Assets of our Notes to Consolidated Financial Statements in this quarterly report, which we consider to be an off-balance sheet arrangement. We believe that this VIE does not have a current or future material effect on our consolidated financial position or operating results. 

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the year ended December 31, 2017.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 19—Recent Accounting Standards of our Notes to Consolidated Financial Statements.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Cash Investments

We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets.

Marketing and Trading Commodity Price Risk

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

	September 30, 2018					December 31, 2017
	Fair Value			Change in Fair Value		Fair Value			Change in Fair Value
Liquefaction Supply Derivatives	$	29		$	7	$	55		$	5
LNG Trading Derivatives	(90		)	33		(8		)	2

Interest Rate Risk

Cheniere Partners and CCH have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the CQP Credit Facilities(“CQP Interest Rate Derivatives”) and the CCH Credit Facility (“CCH Interest Rate Derivatives” and collectively with the CQP Interest Rate Derivatives, “Interest Rate Derivatives”), respectively. In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining terms of the Interest Rate Derivatives as follows (in millions):

	September 30, 2018				December 31, 2017
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
CQP Interest Rate Derivatives	$	28	$	5	$	21		$	5
CCH Interest Rate Derivatives	94		42		(32		)	44

Foreign Currency Exchange Risk

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

	September 30, 2018				December 31, 2017
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
FX Derivatives	$	11	$	1	$	(1	)	$	—

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

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ITEM 4. CONTROLS AND PROCEDURES

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

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

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PART II. OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

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

Please see Part II, Item 1, “Legal Proceedings” in our Quarterly Report on Form 10-Q for the period ended June 30, 2018.

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 year ended December 31, 2017.

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

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended September 30, 2018:

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	Maximum Number of Units That May Yet Be Purchased Under the Plans
July 1 - 31, 2018	29,160	$65.01	—	—
August 1 - 31, 2018	3,121	$62.22	—	—
September 1 - 30, 2018	1,628	$67.44	—	—

(1) Represents shares surrendered to us by participants in our share-based compensation plans to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under these plans.

(2) The price paid per share was based on the closing trading price of our common stock on the dates on which we repurchased shares from the participants under our share-based compensation plans.

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ITEM 6. EXHIBITS

Exhibit No.	Description
4.1	Second Supplemental Indenture, dated as of September 11, 2018, among Cheniere Partners, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 12, 2018)
10.1*	Fourth Omnibus Amendment, dated as of September 17, 2018, to (a) the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, by and among SPL, as Borrower, Société Générale, as the Common Security Trustee and as the Intercreditor Agent, The Bank of Nova Scotia, as the Secured Debt Holder Group Representative for the Working Capital Debt and other Secured Debt Holder Group Representatives party thereto from time to time, the Secured Hedge Representatives and the Secured Gas Hedge Representatives party thereto from time to time and (b) the Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated as of September 4, 2015, by and among SPL, as Borrower, Société Générale as the Swing Line Lender and as the Common Security Trustee, The Bank of Nova Scotia as the Senior Issuing Bank and Senior Facility Agent and the other agents and lenders from time to time party thereto
10.2	Registration Rights Agreement, dated as of September 11, 2018, among Cheniere Partners, the guarantors party thereto and J.P. Morgan Securities LLC (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 12, 2018)
10.3*	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Stage 2 EPC Agreement Revised Table A-2, dated May 18, 2018, (ii) the Change Order CO-00002 Stage 2 EPC Agreement Amended and Restated Attachment C, dated May 18, 2018, (iii) the Change Order CO-00003 Fuel Provisional Sum Adjustment, dated May 24, 2018, (iv) the Change Order CO-00004 Currency Provisional Sum Adjustment, dated May 29, 2018, (v) the Change Order CO-00005 JT Valve Modifications, dated July 10, 2018 and (vi) the Change Order CO-00006 Tank B Soil Conditions, International Building Code, and East Jetty Marine Facility Schedule Acceleration, dated September 5, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
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

*	Filed herewith.
**	Furnished herewith.

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SIGNATURES

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

		CHENIERE ENERGY, INC.
Date:	November 7, 2018	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	November 7, 2018	By:	/s/ Leonard E. Travis
			Leonard E. Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

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EX-10.1

Exhibit 10.1

Execution Version

FOURTH OMNIBUS AMENDMENT

This Fourth Omnibus Amendment (this “Amendment”), dated as of September 17, 2018 amends (a) the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015 (as it may be further amended, restated, supplemented or otherwise modified from time to time, the “Common Terms Agreement”), by and among Sabine Pass Liquefaction, LLC, a Delaware limited liability company (the “Borrower”), Société Générale, as the Common Security Trustee (in such capacity, the “Common Security Trustee”) and as the Intercreditor Agent (in such capacity, the “Intercreditor Agent”), The Bank of Nova Scotia, as the Secured Debt Holder Group Representative for the Working Capital Debt and other Secured Debt Holder Group Representatives party thereto from time to time, the Secured Hedge Representatives and the Secured Gas Hedge Representatives party thereto from time to time and (b) the Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated as of September 4, 2015 (as it may be further amended, restated, supplemented or otherwise modified from time to time, the “Working Capital Facility”), by and among the Borrower, Société Générale as the Swing Line Lender and as the Common Security Trustee (in such capacity, the “Common Security Trustee”), The Bank of Nova Scotia as the Senior Issuing Bank and Senior Facility Agent (the “Facility Agent”) and the other agents and lenders from time to time party thereto. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Common Terms Agreement and, if not defined therein, the Working Capital Facility.

WHEREAS, the Borrower has requested that the Common Security Trustee, the Intercreditor Agent, the Secured Debt Holder Group Representative for the Working Capital Debt and the Working Capital Lenders (collectively, the “Lenders” and each individually, a “Lender”) constituting the Required Senior Lenders under the Working Capital Facility agree to amend the Common Terms Agreement and Working Capital Facility as set forth in Section 1 and Section 2 herein, respectively; and

WHEREAS, (a) the Secured Debt Holder Group Representative for the Working Capital Debt, the Common Security Trustee and the Intercreditor Agent are willing to amend the Common Terms Agreement as set forth in Section 1 herein and (b) the Facility Agent, each Lender party hereto and the Common Security Trustee are willing to amend the Working Capital Facility as set forth in Section 2 herein;

NOW, THEREFORE, in consideration of the foregoing premises and the agreements, provisions and covenants herein contained, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto agree as follows:

Section 1.Amendments to the Common Terms Agreement. Pursuant to Section 10.1 of the Common Terms Agreement and Section 4.1(i) of the Intercreditor Agreement, the Borrower, the Common Security Trustee, the Intercreditor Agent and the Secured Debt Holder

Group Representative for the Working Capital Debt hereby consent to the following amendments to the Common Terms Agreement:

1.1Clause (B) of the proviso of clause (c) of the definition of “Additional Material Project Document” in the Common Terms Agreement is hereby amended by replacing “until Train 6 Debt has been incurred” with “until the Train 6 FID Date”.

1.2Clause (C) of the proviso of clause (c) of the definition of “Additional Material Project Document” in the Common Terms Agreement is hereby amended and restated in its entirety as follows:

“(C)     until the Train 6 FID Date, any agreement containing obligations or liabilities of the Borrower which are not effective by their terms unless and until Train 6 FID has occurred (other than reimbursement obligations under any precedent agreement with a transporter not exceeding $25,000,000 in the aggregate for all precedent agreements entered into under this clause (C))”.

1.3The definition of “Train 6 FOB Sale and Purchase Agreement” in the Common Terms Agreement is hereby amended and restated in its entirety as follows:

““Train 6 FOB Sale and Purchase Agreement” means any LNG sale and purchase agreement entered into by the Borrower with respect to Train 6.”

1.4The following definition of “Train 6 FID” is hereby added to Schedule 1 of the Common Terms Agreement in the appropriate alphabetical order:

““Train 6 FID” means a positive final investment decision approved by the Borrower in accordance with all applicable requirements under the Borrower's Organic Documents in respect of the Train 6 Development to construct the liquefaction facilities and any other required facilities, or modify existing facilities, comprising Train 6.”

1.5The following definition of “Train 6 FID Date” is hereby added to Schedule 1 of the Common Terms Agreement in the appropriate alphabetical order:

““Train 6 FID Date” means the date on which Train 6 FID has occurred, as evidenced by copies of any resolution or other written documentation approving Train 6 FID delivered by or on behalf of the Borrower to the Common Security Trustee and Intercreditor Agent.”

1.6Each occurrence of the phrase “Train 6 Debt has been incurred” in the Common Terms Agreement is hereby replaced with the phrase “Train 6 Debt has been incurred or the Train 6 FID Date has occurred”.

1.7Clause (iii) of Section 4.12 in the Common Terms Agreement is hereby amended by replacing “and, to the extent incurred, Train 6 Debt” with “amounts available to make Restricted Payments pursuant to Section 5.01(c)(iii)(B) of the Accounts Agreement and, to the extent the Train 6 FID Date has occurred, Train 6 Debt or other Indebtedness permitted to be incurred by the Borrower under the Financing Documents”.

1.8The definition of “Construction Budget” in the Common Terms Agreement is hereby amended by replacing “the date on which Train 6 Debt is incurred” with “the date on which Train 6 Debt has been incurred or the Train 6 FID has occurred” in each of the two places such phrase appears.

1.9The definition of “Construction Schedule” in the Common Terms Agreement is hereby amended by replacing “the date on which Train 6 Debt is incurred” with “the date on which Train 6 Debt has been incurred or the Train 6 FID has occurred” in each of the two places such phrase appears.

1.10The definition of “Permitted Completion Costs” in the Common Terms Agreement is hereby amended by replacing “the revised Construction Budget delivered pursuant to Section 2.7(a)(xi) (Train 6 Debt)” with “the revised Construction Budget delivered pursuant to Section 2.7(a)(xi) (Train 6 Debt) or otherwise delivered on the Train 6 FID Date”.

Section 2.Amendments to the Working Capital Facility. Pursuant to Section 11.01 of the Working Capital Facility Agreement and Section 4.1(i) of the Intercreditor Agreement, the Borrower, the Common Security Trustee, the Intercreditor Agent and the Facility Agent (as the Secured Debt Holder Group Representative for the Working Capital Debt) hereby consent to the following modifications to the Common Terms Agreement:

2.1Each occurrence of the phrase “Train 6 Debt has been incurred” in the Working Capital Facility Agreement is hereby replaced with the phrase “Train 6 Debt has been incurred or the Train 6 FID Date has occurred”.

2.2Other than as specifically noted in Section 2.4 and Section 2.5 below, each occurrence of the phrase “Train 6 Debt Effective Date” in the Working Capital Facility Agreement is hereby replaced with the phrase “earlier of the Train 6 Debt Effective Date or the Train 6 FID Date”.

2.3Section 7.02(b)(i)(z)(G) of the Working Capital Facility Agreement is hereby amended by replacing the phrase “Train 6 Debt is incurred” with the phrase “Train 6 Debt is incurred or the Train 6 FID Date has occurred”.

2.4Section 9.01(b)(ix)(D)(III) of the Working Capital Facility Agreement is hereby amended by replacing the phrase “Train 6 Debt Effective Date” with “Train 6 Debt Effective Date or the Train 6 FID Date”.

2.5Section 2.13(a)(iv) of Schedule 8.01 of the Working Capital Facility Agreement is hereby amended by replacing each occurrence of the phrase “Train 6 Debt Effective Date” with “Train 6 Debt Effective Date or the Train 6 FID Date”.

Section 3.Effectiveness. This Amendment shall become effective as of the date hereof only upon the execution of this Amendment by the Common Security Trustee and receipt by the Common Security Trustee of executed counterparts of this Amendment by each of (a) the Borrower, (b) the Intercreditor Agent, (c) the Secured Debt Holder Group Representative for the Working Capital Debt (who constitutes the Majority Aggregate Secured Credit Facilities Debt Participants (as defined in the Intercreditor Agreement)), and (d) Lenders constituting the Required Senior Lenders under the Working Capital Facility.

Section 4.Representations and Warranties. The Borrower hereby represents and warrants to the Lenders that:

4.1no Default or Event of Default has occurred and is continuing as of the date hereof or will result from the consummation of the transactions contemplated by the Amendment; and

4.2each of the representations and warranties of the Borrower in the Common Terms Agreement, the Working Capital Facility and the other Financing Documents is true and correct in all material respects except for (A) those representations and warranties that are qualified by materiality, which shall be true and correct in all respects, on and as of the date hereof (or, if stated to have been made solely as of an earlier date, as of such earlier date) and (B) the representations and warranties that, pursuant to Section 4.1(b) (General) of the Common Terms Agreement, are not deemed repeated.

Section 5.Financing Document. This Amendment constitutes a Financing Document as such term is defined in, and for purposes of, the Common Terms Agreement.

Section 6.Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, UNITED STATES OF AMERICA, WITHOUT ANY REFERENCE TO THE CONFLICT OF LAW PRINCIPLES THEREOF (OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).

Section 7.Headings. All headings in this 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 8.Binding Nature and Benefit. This Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted assigns.

Section 9.Counterparts. This Amendment may be executed 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 Amendment by facsimile or portable document format (“pdf”) shall be effective as delivery of a manually executed counterpart of this Amendment.

Section 10.No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Common Terms Agreement and the Working Capital Facility Agreement shall continue unchanged and shall remain in full force and effect. Each amendment granted herein shall apply solely to the matters set forth herein and such amendment shall not be deemed or construed as an amendment of any other matters, nor shall such amendment apply to any other matters.

Section 11.Direction to Secured Credit Facilities Debt Holder Group Representatives, Intercreditor Agent and Common Security Trustee.

a.by their signature below, each of the undersigned Lenders instructs the Secured Debt Holder Group Representative for the Working Capital Debt to (i) execute this Amendment and (ii) direct the Intercreditor Agent to execute this Amendment;

b.based on the instructions above, the Secured Debt Holder Group Representative for the Working Capital Debt, constituting the Majority Aggregate Secured Credit Facilities Debt Participants (as defined in the Intercreditor Agreement), hereby directs the Intercreditor Agent to (i) execute this Amendment and (ii) direct the Common Security Trustee to execute this Amendment; and

c.by its signature below, the Intercreditor Agent, in such capacity, hereby directs the Common Security Trustee to execute this Amendment.

[Remainder of the page left intentionally blank.]

IN WITNESS WHEREOF,the Parties have caused this Amendment to be duly executed by their officers thereunto duly authorized as of the day and year first above written.

SABINE PASS LIQUEFACTION, LLC,
as the Borrower
By:	/s/ Lisa C. Cohen
Name: Lisa C. Cohen
Title: Treasurer

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

SOCIÉTÉ GÉNÉRALE,
as Common Security Trustee and Secured
Debt Holder Group Representative for the
Commercial Banks Facility
By:	/s/ Ellen Turkel
Name: Ellen Turkel
Title: Director
SOCIÉTÉ GÉNÉRALE,
as the Intercreditor Agent
By:	/s/ Ellen Turkel
Name: Ellen Turkel
Title: Director
SOCIÉTÉ GÉNÉRALE,
as Commercial Bank Lender, Swing Line Lender
and Working Capital Lender
By:	/s/ Ellen Turkel
Name: Ellen Turkel
Title: Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

THE BANK OF NOVA SCOTIA, HOUSTON BRANCH
as the Secured Debt Holder Group Representative for the Working Capital Facility
By:	/s/ Alfredo Brahim
Name: Alfredo Brahim
Title: Director
THE BANK OF NOVA SCOTIA, HOUSTON BRANCH
as Senior Issuing Bank and Working Capital Lender
By:	/s/ Alfredo Brahim
Name: Alfredo Brahim
Title: Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

ABN AMRO CAPITAL USA LLC,
as Senior Issuing Bank and Working Capital Lender
By:	/s/ Casey Lowary
Name: Casey Lowary
Title: Managing Director
By:	/s/ Darrell Holley
Name: Darrell Holley
Title: Managing Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

MUFG BANK, LTD.,
as Working Capital Lender
By:	/s/ Saad Iqbal
Name: Saad Iqbal
Title: Managing Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

INDUSTRIAL AND COMMERCIAL BANK
OF CHINA LIMITED, NEW YORK BANK,
as Working Capital Lender
By:	/s/ Michael Fabisiak
Name: Michael Fabisiak
Title: Head of Project Finance, Americas
By:	/s/ N/A
Name:
Title:

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

ING CAPITAL LLC,
as Working Capital Lender
By:	/s/ Subha Pasumarti
Name: Subha Pasumarti
Title: Managing Director
By:	/s/ Hans Beekmans
Name: Hans Beekmans
Title: Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

LANDESBANK BADEN­-WÜRTTEMBERG,
NEW YORK BRANCH,
as Working Capital Lender
By:	/s/ Adam Rahal
Name: Adam Rahal
Title: Legal Counsel
By:	/s/ Michael Thier
Name: Michael Thier
Title: Senior Risk Manager

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

LLOYDS BANK PLC,
as Working Capital Lender
By:	/s/ Kamala Basdeo
Name: Kamala Basdeo
Title: Assistant Manager
	Transaction Execution
	Category A
	B002
By:	/s/ Jennifer Larrow
Name: Jennifer Larrow
Title: Assistant Manager
	Transaction Execution
	Category A
	L003

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

MORGAN STANLEY BANK, N.A.,
as Working Capital Lender
By:	/s/ Jake Dowden
Name: Jake Dowden
Title: Authorized Signatory

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

SUMITOMO MITSUI BANKING
CORPORATION,
as Working Capital Lender
By:	/s/ Juan Kreutz
Name: Juan Kreutz
Title: Managing Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

COMMONWEALTH BANK OF AUSTRALIA,
as Working Capital Lender
By its attorney under Power of Attorney dated
24 June 2013:
Signature of Attorney:	/s/ Annette Tomoski
Name of Attorney:	Annette Tomoski
Signed by its duly constituted attorney in the
presence of:
Signature of Witness:	/s/ Daniel Sardelic
Name of Witness:	Daniel Sardelic

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

WELLS FARGO BANK, N.A.,
as Working Capital Lender
By:	/s/ J. Michael Quigley
Name: J. Michael Quigley
Title: Assistant Vice President

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

EX-10.3

Exhibit 10.3

*** indicates material has been omitted pursuant to a Confidential Treatment Request filed with the Securities and Exchange Commission. A complete copy of this agreement has been filed separately with the Securities and Exchange Commission.

CHANGE ORDER

Revised Table A-2

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: CO-00001 DATE OF CHANGE ORDER: May 18, 2018

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

1. Pursuant to Article 6 and Table A-2 of the Agreement, the Parties have agreed to amend Table A-2 by adding Table A-2-1 to the previous Table A-2. Table A-2-l incorporates (i) certain numbered correspondence issued between Contractor and Owner in connection with the Stage 1 EPC Agreement, and (ii) certain numbered conference notes between Contractor and Owner in connection with the Stage 1 EPC Agreement.

2. Table A-2-1 is attached as Exhibit 1 hereto.

3. Only those specified portions of the numbered correspondence and numbered conference notes are incorporated by Table A-2-1. No other portions of the numbered correspondence or numbered conference notes set forth in Table A-2-1 nor any other correspondence, conference notes or meeting minutes (including any compensation or other relief specified therein) are incorporated into the Agreement.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders........................................................................................	$	0.00
The Contract Price prior to this Change Order was...........................................................................................	$	0.00
The Aggregate Equipment Price will be (increased) (decreased) (unchanged) by this Change Order in the amount of...........................................................................................................................................................	$	Unchanged
The Aggregate Labor and Skills Price will be (increased) (decreased) (unchanged) by this Change Order in the amount of.....................................................................................................................................................	$	Unchanged
The Aggregate Provisional Sum will be (increased) (decreased) (unchanged) by this Change Order in the amount of...........................................................................................................................................................	$	Unchanged
The new Contract Price including this Change Order will be...........................................................................	$	2,360,000,000

Adjustment to dates in Project Schedule

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

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

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

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

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/ SB Contractor /s/ EL 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/ Ed Lehotsky	/s/ Sergio Buoncristiano
Owner	Contractor
Ed Lehotsky	Sergio Buoncristiano
Name	Name
SVP E&C	SVP
Title	Title
May 18, 2018	May 18, 2018
Date of Signing	Date of Signing

CHANGE ORDER

Amended and Restated Attachment C

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: CO-00002 DATE OF CHANGE ORDER: May 18, 2018

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

1. Pursuant to Article 6, the Parties have agreed to amend and restate Attachment C - Payment Schedule for Stage 2.

2. The amended and restated Attachment C is attached as Exhibit 1 hereto.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (#00001)........................................................................	$	0.00
The Contract Price prior to this Change Order was...........................................................................................	$	0.00
The Aggregate Equipment Price will be (increased) (decreased) (unchanged) by this Change Order in the amount of...........................................................................................................................................................	$	Unchanged
The Aggregate Labor and Skills Price will be (increased) (decreased) (unchanged) by this Change Order in the amount of.....................................................................................................................................................	$	Unchanged
The Aggregate Provisional Sum will be (increased) (decreased) (unchanged) by this Change Order in the amount of...........................................................................................................................................................	$	Unchanged
The new Contract Price including this Change Order will be...........................................................................	$	2,360,000,000

Adjustment to dates in Project Schedule

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

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

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

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

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

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/ SB Contractor /s/ EL 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/ Ed Lehotsky	/s/ Sergio Buoncristiano
Owner	Contractor
Ed Lehotsky	Sergio Buoncristiano
Name	Name
SVP E&C	SVP
Title	Title
May 18, 2018	May 18, 2018
Date of Signing	Date of Signing

CHANGE ORDER

Fuel Provisional Sum Adjustment

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: CO-00003 DATE OF CHANGE ORDER: May 24, 2018

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

1. The Fuel Provisional Sum in Section 1.2 of Attachment EE, Schedule EE-1 of the Agreement prior to this Change Order was Ten Million, Seven Hundred Eighty Four Thousand, Four Hundred Sixty Six U.S. Dollars (U.S. $10,784,466). The Fuel Provisional Sum is hereby decreased by Two Million, Thirty Six Thousand, Six Hundred Two U. S. Dollars (U.S. $2,036,602) and the new value as amended by this Change Order shall be Eight Million, Seven Hundred Forty Seven Thousand, Eight Hundred Sixty Four U.S. Dollars $8,747,864.

2. Pursuant to instructions in Section 1.2 of Attachment EE, Schedule EE-1 of the Agreement, Exhibit 1 to this Change Order illustrates the calculation of the final fuel costs in the Agreement.

3. Schedules C-1 Aggregate Labor and Skills Price Milestone Payment Schedule of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit 2 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (0001-00002).................................................................	$	—
The Contract Price prior to this Change Order was...........................................................................................	$	2,360,000,000
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	***
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	***
The new Contract Price including this Change Order will be...........................................................................	$	2,357,963,398

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	***
Net change by previously authorized Change Orders (0001-00002).................................................................	$	***
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	***
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	***
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	***

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	***
Net change by previously authorized Change Orders (0001-00002).................................................................	$	***
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	***
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	***
The new Contract Price including this Change Order will be...........................................................................	$	***

Adjustment to Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (0001-00002).................................................................	$	—
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	295,549,906
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................	$	(2,036,602	)
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	293,513,304

Adjustment to dates in Project Schedule

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

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

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: 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/ SB Contractor /s/ EL 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/ Ed Lehotsky	/s/ Sergio Buoncristiano
For Owner	Contractor
Ed Lehotsky	Sergio Buoncristiano
Name	Name
SVP E&C	SVP
Title	Title
June 13, 2018	May 24, 2018
Date of Signing	Date of Signing

CHANGE ORDER

Currency Provisional Sum Adjustment

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: CO-00004 DATE OF CHANGE ORDER: May 29, 2018

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

1. The Currency Provisional Sum in Section 1.1 of Attachment EE, Schedule EE-1 of the Agreement prior to this Change Order was Two Hundred Twelve Million, Four Hundred Fifty Three Thousand, Four Hundred Forty Nine U.S. Dollars (U.S. $212,453,449). The Currency Provisional Sum is hereby increased by Five Hundred Seventy Three Thousand, Seventy One U. S. Dollars (U.S. $573,071) and the new value as amended by this Change Order shall be Two Hundred Thirteen Million, Twenty Six Thousand, Five Hundred Twenty U.S. Dollars (U.S. $213,026,520).

2. Pursuant to instructions in Section 1.1 of Attachment EE, Schedule EE-1 of the Agreement, Exhibit 1 to this Change Order illustrates the calculation of the final currency costs in the Agreement.

3. Schedules C-3 Aggregate Equipment Price Milestone Payment Schedule of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit 2 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (0001-00003).................................................................	$	(2,036,602	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,357,963,398
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	***
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	***
The new Contract Price including this Change Order will be...........................................................................	$	2,358,536,469

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	***
Net change by previously authorized Change Orders (0001-00003).................................................................	$	***
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	***
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	***
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	***

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	***
Net change by previously authorized Change Orders (0001-00003).................................................................	$	***
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	***
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	***
The new Contract Price including this Change Order will be...........................................................................	$	***

Adjustment to Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (0001-00003).................................................................	$	(2,036,602	)
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	293,513,304
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................	$	573,071
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	294,086,375

Adjustment to dates in Project Schedule

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

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

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

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

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/ SB Contractor /s/ EL 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/ Ed Lehotsky	/s/ Sergio Buoncristiano
For Owner	Contractor
Ed Lehotsky	Sergio Buoncristiano
Name	Name
SVP E&C	SVP
Title	Title
June 13, 2018	May 30, 2018
Date of Signing	Date of Signing

CHANGE ORDER

JT Valve Modifications

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: CO-00005 DATE OF CHANGE ORDER: July 10, 2018

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

1. Pursuant to Article 6 of the Agreement, the Parties agree Contractor will implement changes to the trim on the JT valve 13PV-16002, located in the methane cold box of Train 3.

2. The scope of this Change Order is further detailed in Exhibit 1.

3. The cost breakdowns for the scope of work described in this Change Order are detailed in Exhibit 2.

4. Schedules C-1 and C-3 (Milestone Payment Schedules) of Exhibit C of the Agreement will be amended by including the Milestones listed in Exhibit 3 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (0001-00003).................................................................	$	(1,463,531	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,358,536,469
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	***
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	***
The new Contract Price including this Change Order will be...........................................................................	$	2,358,747,493

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	***
Net change by previously authorized Change Orders (0001-00003).................................................................	$	***
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	***
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	***
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	***

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	***
Net change by previously authorized Change Orders (0001-00003).................................................................	$	***
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	***
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	***
The new Contract Price including this Change Order will be...........................................................................	$	***

Adjustment to Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (0001-00003).................................................................	$	(1,463,531	)
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	294,086,375
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................	$	—
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	294,086,375

Adjustment to dates in Project Schedule

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

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

Adjustment to Payment Schedule: Yes. See Exhibit 3 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

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

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/ BT Contractor /s/ EL 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/ Ed Lehotsky	/s/ Bhupesh Thakkar
For Owner	Contractor
Ed Lehotsky	Bhupesh Thakkar
Name	Name
SVP E&C	Senior Project Manager
Title	Title
July 16, 2018	July 10, 2018
Date of Signing	Date of Signing

CHANGE ORDER

Tank B Soil Conditions, International Building Code, and East Jetty Marine Facility Schedule Acceleration

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: CO-00006 DATE OF CHANGE ORDER: September 5, 2018

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

A) Pursuant to Article 6 of the Agreement, Parties agree Contractor will be compensated for costs incurred during performance of the Work while encountering soil conditions in Tank B area that differ from the Basic Engineering Design Data. The scope of this item is further detailed in Exhibit 1.

B) Pursuant to Article 6 of the Agreement, Parties agree Contractor will be compensated for costs associated with the Change in the Law (2015 International Building Code) affecting the 23A-4010 Compressor Substation, the 23A-4011 Propane Substation and the 20A-4038 East Jetty Substation. The scope of this item is further detailed in Exhibit 1.

C) Pursuant to Article 6 of the Agreement, Parties agree Contractor shall turnover the East Jetty Marine Facility to Owner no later than July 24, 2020or as soon as reasonably practicable thereafter if the Parties mutually agree (both acting reasonably). The scope of this item is further detailed in Exhibit 1.

Contractor agrees that Owner may occupy and use the East Jetty Marine Facility during Phase 2, subject to the following conditions:

1. “Phase 1” means the time period beginning upon the date this Change Order is executed and ending on the date the East Jetty Marine Facility is turned over to Owner.

2. “Phase 2” means the time period beginning the date the East Jetty Marine Facility is turned over to Owner and ending on the date of Substantial Completion of Subproject 3.

3. During Phase 1:

a) Contractor shall perform the Work to complete the East Jetty Marine Facility in accordance with the Agreement.

b) Contractor shall perform preventive maintenance on the East Jetty Marine Facility and its systems according to the operating and maintenance manuals.

c) On or before July 24, 2020, Owner and Contractor shall jointly inspect the East Jetty Marine Facility to determine and record whether the Work for the East Jetty Marine Facility is completed for its safe operation, other than any punchlist items that may be completed after turnover to Owner (such punchlist items that may be completed after turnover is hereinafter referred to as “Remaining Work”). The Parties shall agree on the Remaining Work needing to be completed or corrected as a result of such inspection. Contractor shall complete the Work on the East Jetty Marine Facility other than the agreed upon Remaining Work.

d) On or before July 24, 2020, or as soon as reasonably practicable thereafter if the Parties mutually agree (both acting reasonably), Contractor shall turn over to Owner the East Jetty Marine Facility. Upon such turnover, Owner shall maintain access control and security to and inside the East Jetty Marine Facility. Upon such turn over, Owner shall (i) immediately take care, custody and control of the East Jetty Marine Facility and (ii) provide Contractor, within one (1) day, a Turnover Certificate with respect to the East Jetty Marine Facility.

4. During Phase 2:

a) Owner shall have the right to occupy and use the East Jetty Marine Facility.

b) Owner shall provide Contractor with reasonable access to complete Remaining Work so long as such access does not materially interfere with Owner’s use of the East Jetty Marine Facility.

c) Owner will transport its personnel to the East Jetty Marine Facility.

d) Owner will perform preventive maintenance on the East Jetty Marine Facility.

5. Commencing on the commencement of Phase 2, Owner shall bear the full risk of physical loss and damage to the East

Jetty Marine Facility; provided, however, notwithstanding the foregoing, Contractor shall remain fully responsible and liable to Owner for its Warranty and Corrective Work obligations under this Agreement.

6. The Defect Correction Period for the East Jetty Marine Facility shall commence upon the commencement of Phase 2 and end eighteen (18) months thereafter, as may be extended pursuant to Section 12.3 of the Agreement.

7. Contractor shall maintain in full force and effect until turnover of the East Jetty Marine Facility all coverages under Attachment O of the Agreement. Owner’s operational insurance shall cover the East Jetty Marine Facility upon commencement of Phase 2.

8. Section 13.1 of the Agreement shall not apply to the East Jetty Marine Facility unless Substantial Completion of Subproject 3 (including the East Jetty Marine Facility, as part of Subproject 3), occurs after the Guaranteed Substantial Completion Date.

9. Owner shall manage Environmental, Safety & Health incidents involving Owner’s work within the East Jetty Marine Facility, with Contractor’s reasonable assistance as needed on a cost reimbursable basis.

10. The Parties selection of item [A] on page 2 of this Change Order, which states this Change Order shall constitute full and final settlement and accord 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, shall not prejudice Contractor’s right to a Change Order in accordance with Section 6.2A.2 and 8.2C(ii) arising from Owner’s occupation or use of the East Jetty Marine Facility.

The cost breakdowns for the scopes of work described in this Change Order are detailed in Exhibit 2.

Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 3 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (0001-00005).................................................................	$	(1,252,507	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,358,747,493
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	***
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	***
The new Contract Price including this Change Order will be...........................................................................	$	2,365,356,684

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	***
Net change by previously authorized Change Orders (0001-00005).................................................................	$	***
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	***
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	***
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	***

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	***
Net change by previously authorized Change Orders (0001-00005).................................................................	$	***
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	***
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	***
The new Contract Price including this Change Order will be...........................................................................	$	***

Adjustment to Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (0001-00005).................................................................	$	(1,463,531	)
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	294,086,375
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................	$	—
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	294,086,375

Adjustment to dates in Project Schedule

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

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

Adjustment to Payment Schedule: Yes. See Exhibit 3 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

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

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/ BT Contractor /s/ EL 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/ Ed Lehotsky	/s/ Bhupesh Thakkar
For Owner	Contractor
Ed Lehotsky	Bhupesh Thakkar
Name	Name
SVP E&C	Senior Project Manager
Title	Title
September 12, 2018	September 15, 2018
Date of Signing	Date of Signing

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

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

I, Jack A. Fusco, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 7, 2018

/s/ Jack A. Fusco

Jack A. Fusco
Chief Executive Officer of

Cheniere Energy, Inc.

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

I, Michael J. Wortley, 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 that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

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

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

Date: November 7, 2018

/s/ Michael J. Wortley

Michael J. Wortley
Chief Financial Officer of

Cheniere Energy, Inc.

EX-32.1

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: November 7, 2018

/s/ Jack A. Fusco

Jack A. Fusco
Chief Executive Officer of

Cheniere Energy, Inc.

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Wortley, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: November 7, 2018

/s/ Michael J. Wortley

Michael J. Wortley
Chief Financial Officer of

Cheniere Energy, Inc.

XML

Document and Entity Information Document - shares	9 Months Ended
	Sep. 30, 2018	Nov. 02, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	CHENIERE ENERGY INC
Entity Central Index Key	0000003570
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		256,885,068

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 989	$ 722
Restricted cash	1,943	1,880
Accounts and other receivables	243	369
Accounts receivable—related party	3	2
Inventory	298	243
Derivative assets	63	57
Other current assets	131	96
Total current assets	3,670	3,369
Non-current restricted cash	0	11
Property, plant and equipment, net	26,499	23,978
Debt issuance costs, net	78	149
Non-current derivative assets	121	34
Goodwill	77	77
Other non-current assets, net	295	288
Total assets	30,740	27,906
Current liabilities
Accounts payable	80	25
Accrued liabilities	987	1,078
Current debt	66	0
Deferred revenue	120	111
Derivative liabilities	96	37
Other current liabilities	1	0
Total current liabilities	1,350	1,251
Long-term debt, net	27,438	25,336
Non-current capital lease obligations	29	0
Non-current derivative liabilities	16	19
Other non-current liabilities	76	60
Commitments and contingencies (see Note 15)
Stockholders’ equity
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	0	0
Common Stock, $0.003 par value, Authorized: 480.0 million shares at September 30, 2018 and December 31, 2017; Issued: 269.7 million shares and 250.1 million shares at September 30, 2018 and December 31, 2017, respectively
Outstanding: 257.1 million shares and 237.6 million shares at September 30, 2018 and December 31, 2017, respectively	1	1
Treasury stock: 12.6 million shares and 12.5 million shares at September 30, 2018 and December 31, 2017, respectively, at cost	(396)	(386)
Additional paid-in-capital	4,009	3,248
Accumulated deficit	(4,223)	(4,627)
Total stockholders’ deficit	(609)	(1,764)
Non-controlling interest	2,440	3,004
Total equity	1,831	1,240
Total liabilities and equity	$ 30,740	$ 27,906

XML

Consolidated Balance Sheets Parentheticals - $ / shares shares in Millions	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Preferred Stock, Par Value	$ 0.0001	$ 0.0001
Preferred Stock, Shares Authorized	5.0	5.0
Preferred Stock, Shares Issued	0.0	0.0
Common Stock, Par Value Per Share	$ 0.003	$ 0.003
Common Stock, Shares Authorized	480.0	480.0
Common Stock, Shares, Issued	269.7	250.1
Common Stock, Shares, Outstanding	257.1	237.6
Treasury Stock, Shares	12.6	12.5

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues
Revenue earned from contracts with customers	$ 1,812	$ 1,416	$ 5,604	$ 3,855
Revenues	1,819	1,403	5,604	3,855
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	1,027	824	3,078	2,140
Operating and maintenance expense	170	114	457	309
Development expense	2	3	6	7
Selling, general and administrative expense	74	64	214	179
Depreciation and amortization expense	113	92	333	252
Restructuring expense	0	0	0	6
Impairment expense and loss on disposal of assets	8	9	8	15
Total operating costs and expenses	1,394	1,106	4,096	2,908
Income from operations	425	297	1,508	947
Other income (expense)
Interest expense, net of capitalized interest	(221)	(186)	(653)	(539)
Loss on modification or extinguishment of debt	(12)	(25)	(27)	(100)
Derivative gain (loss), net	23	(2)	132	(37)
Other income	15	4	32	11
Total other expense	(195)	(209)	(516)	(665)
Income before income taxes and non-controlling interest	230	88	992	282
Income tax benefit (provision)	(3)	2	(15)	1
Net income	227	90	977	283
Less: net income attributable to non-controlling interest	162	379	573	803
Net income (loss) attributable to common stockholders	$ 65	$ (289)	$ 404	$ (520)
Net income (loss) per share attributable to common stockholders—basic	$ 0.26	$ (1.24)	$ 1.67	$ (2.24)
Net income (loss) per share attributable to common stockholders—diluted	$ 0.26	$ (1.24)	$ 1.65	$ (2.24)
Weighted average number of common shares outstanding—basic	247.2	232.6	241.9	232.5
Weighted average number of common shares outstanding—diluted	250.2	232.6	244.6	232.5
LNG [Member]
Revenues
Revenue earned from contracts with customers	$ 1,712	$ 1,345	$ 5,327	$ 3,646
Revenues	1,719	1,332	5,327	3,646
Regasification [Member]
Revenues
Revenue earned from contracts with customers	66	65	196	195
Other [Member]
Revenues
Revenue earned from contracts with customers	30	5	73	12
Other, Related Party [Member]
Revenues
Revenue earned from contracts with customers	$ 4	$ 1	$ 8	$ 2

XML

Consolidated Statement of Stockholders' Equity - 9 months ended Sep. 30, 2018 - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Accumulated Deficit	Non-controlling Interest
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2017	237.6	237.6
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2017	12.5		12.5
Stockholders' Equity, Beginning of Period at Dec. 31, 2017	$ 1,240	$ 1	$ (386)	$ 3,248	$ (4,627)	$ 3,004
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of restricted stock units, shares		0.4	0.0
Vesting of restricted stock units	0	$ 0	$ 0	0	0	0
Issuance of stock to acquire additional interest in Cheniere Holdings and other merger related adjustments, shares		19.2	0.0
Issuance of stock to acquire additional interest in Cheniere Holdings and other merger related adjustments	(8)	$ 0	$ 0	694	0	(702)
Share-based compensation	65	$ 0	$ 0	65	0	0
Shares repurchased related to share-based compensation, shares		(0.1)	0.1
Shares repurchased related to share-based compensation	(10)	$ 0	$ (10)	0	0	0
Net income attributable to non-controlling interest	573	0	0	0	0	573
Equity portion of convertible notes, net	2	0	0	2	0	0
Distributions to non-controlling interest	(435)	0	0	0	0	(435)
Net income	$ 404	$ 0	$ 0	0	404	0
Common Stock, Shares, Outstanding, End of Period at Sep. 30, 2018	257.1	257.1
Treasury Stock, Shares, End of Period at Sep. 30, 2018	12.6		12.6
Stockholders' Equity, End of Period at Sep. 30, 2018	$ 1,831	$ 1	$ (396)	$ 4,009	$ (4,223)	$ 2,440

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities
Net income	$ 977	$ 283
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	333	252
Share-based compensation expense	89	64
Non-cash interest expense	52	54
Amortization of debt issuance costs, deferred commitment fees, premium and discount	53	53
Loss on modification or extinguishment of debt	27	100
Total losses on derivatives, net	17	108
Net cash used for settlement of derivative instruments	(54)	(59)
Impairment expense and loss on disposal of assets	8	15
Other	(5)	(2)
Changes in operating assets and liabilities:
Accounts and other receivables	115	(33)
Accounts receivable—related party	(1)	(1)
Inventory	(56)	35
Other current assets	(35)	(45)
Accounts payable and accrued liabilities	(23)	20
Deferred revenue	8	58
Other, net	(1)	(7)
Net cash provided by operating activities	1,504	895
Cash flows from investing activities
Property, plant and equipment, net	(2,712)	(2,903)
Investment in equity method investment	(25)	(41)
Other	15	18
Net cash used in investing activities	(2,722)	(2,926)
Cash flows from financing activities
Proceeds from issuances of debt	3,443	6,537
Repayments of debt	(1,385)	(3,609)
Debt issuance and deferred financing costs	(53)	(85)
Debt extinguishment costs	(16)	0
Distributions and dividends to non-controlling interest	(435)	(60)
Payments related to tax withholdings for share-based compensation	(10)	(4)
Other	(7)	0
Net cash provided by financing activities	1,537	2,779
Net increase in cash, cash equivalents and restricted cash	319	748
Cash, cash equivalents and restricted cash—beginning of period	2,613	1,827
Cash, cash equivalents and restricted cash—end of period	$ 2,932	$ 2,575

XML

Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheet - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	$ 989	$ 722
Restricted cash	1,943	1,880
Total cash, cash equivalents and restricted cash	$ 2,932	$ 2,613	$ 2,575	$ 1,827

XML

Nature of Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We are currently developing and constructing two natural gas liquefaction and export facilities. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “SPL Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities (described below) through a wholly owned subsidiary, SPL. Cheniere Partners plans to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is undergoing commissioning and Train 6 is being commercialized and has all necessary regulatory approvals in place. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, and a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines owned by Cheniere Partners’ wholly owned subsidiary, CTPL.

We are developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal near Corpus Christi, Texas, and a pipeline facility (collectively, the “CCL Project”) through wholly owned subsidiaries CCL and CCP, respectively. The CCL Project is being developed in stages. The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the CCL Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). The CCL Project also includes a 23-mile natural gas supply pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”). Stages 1 and 2 are currently under construction, and construction of the Corpus Christi Pipeline was completed in the second quarter of 2018. Train 1 has commenced commissioning activities.

Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project and filed an application with FERC in June 2018 for seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa and one LNG storage tank. We remain focused on leveraging infrastructure through the expansion of our existing sites. We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require 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 year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. The adoption of ASC 606 represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of ASC 606 did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings.

Results of operations for the three and nine months ended September 30, 2018 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2018.

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Restricted Cash

9 Months Ended

Sep. 30, 2018

Restricted Cash [Abstract]

Restricted Cash

RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2018 and December 31, 2017, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Current restricted cash
SPL Project	$	649	$	544
Cheniere Partners and cash held by guarantor subsidiaries	808		1,045
CCL Project	220		227
Cash held by our subsidiaries restricted to Cheniere	266		64
Total current restricted cash	$	1,943	$	1,880
Non-current restricted cash
Other	$	—	$	11

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 SPL Project and the CCL Project and other restricted payments.

Under Cheniere Partners’ credit facilities (the “CQP Credit Facilities”), Cheniere Partners and each of its subsidiaries other than SPL, as guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the CQP Credit Facilities and the related depositary agreement governing the extension of credit to Cheniere Partners. Specifically, Cheniere Partners may only withdraw funds from collateral accounts held at a designated depositary bank on a limited basis and for specific purposes, including for the payment of operating expenses of Cheniere Partners and its guarantor subsidiaries. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions.

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Accounts and Other Receivables

9 Months Ended

Sep. 30, 2018

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2018 and December 31, 2017, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Trade receivables
SPL	$	213	$	185
Cheniere Marketing	16		163
Other accounts receivable	14		21
Total accounts and other receivables	$	243	$	369

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Inventory

9 Months Ended

Sep. 30, 2018

Inventory Disclosure [Abstract]

Inventory

INVENTORY

As of September 30, 2018 and December 31, 2017, inventory consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Natural gas	$	10	$	17
LNG	42		44
LNG in-transit	181		130
Materials and other	65		52
Total inventory	$	298	$	243

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

As of September 30, 2018 and December 31, 2017, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	13,162		$	12,687
LNG site and related costs	86			86
LNG terminal construction-in-process	14,269			11,932
Accumulated depreciation	(1,192		)	(882		)
Total LNG terminal costs, net	26,325			23,823
Fixed assets and other
Computer and office equipment	17			14
Furniture and fixtures	19			19
Computer software	97			92
Leasehold improvements	41			41
Land	59			59
Other	18			16
Accumulated depreciation	(107		)	(86		)
Total fixed assets and other, net	144			155
Tug vessels under capital lease	30			—
Property, plant and equipment, net	$	26,499		$	23,978

Depreciation expense was $112 million and $91 million during the three months ended September 30, 2018 and 2017, respectively, and $331 million and $250 million during the nine months ended September 30, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $82 million and $252 million in the three and nine months ended September 30, 2017, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the SPL Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three and nine months ended September 30, 2018.

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Derivative Instruments

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

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

• interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under certain credit facilities (“Interest Rate Derivatives”);

• commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”);

• financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“LNG Trading Derivatives”); and

• foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with both LNG Trading Derivatives and operations in countries outside of the United States (“FX Derivatives”).

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 hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.

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 September 30, 2018 and December 31, 2017, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2018											December 31, 2017
	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
CQP Interest Rate Derivatives asset	$	—		$	28		$	—	$	28		$	—		$	21		$	—	$	21
CCH Interest Rate Derivatives asset (liability)	—			94			—		94			—			(32		)	—		(32		)
Liquefaction Supply Derivatives asset (liability)	(1		)	4			26		29			2			10			43		55
LNG Trading Derivatives asset (liability)	(19		)	(71		)	—		(90		)	(13		)	5			—		(8		)
FX Derivatives asset (liability)	—			11			—		11			—			(1		)	—		(1		)

There have been no changes to our evaluation of and accounting for our derivative positions during the nine months ended September 30, 2018. See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information.

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 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 is predominantly driven by market commodity basis prices and, as applicable to our natural gas supply contracts, our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

We include 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 may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. As of September 30, 2018 and December 31, 2017, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow.

The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2018:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$26	Market approach incorporating present value techniques	Basis Spread	$(0.748) - $0.079

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Balance, beginning of period	$	12		$	40		$	43		$	79
Realized and mark-to-market gains (losses):
Included in cost of sales	5			(8		)	(4		)	(43		)
Purchases and settlements:
Purchases	9			(1		)	14			1
Settlements	1			(2		)	(27		)	(8		)
Transfers out of Level 3 (1)	(1		)	—			—			—
Balance, end of period	$	26		$	29		$	26		$	29
Change in unrealized gains relating to instruments still held at end of period	$	5		$	(8	)	$	(4	)	$	(43	)

(1)    Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. 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, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

Cheniere Partners had entered into interest rate swaps (“CQP Interest Rate Derivatives”) to hedge a portion of the variable interest payments on its CQP Credit Facilities, based on a portion of the expected outstanding borrowings over the term of the CQP Credit Facilities. In September 2018, Cheniere Partners terminated approximately $1.2 billion of commitments under the CQP Credit Facilities, as discussed in Note 10—Debt. In October 2018, Cheniere Partners terminated the CQP Interest Rate Derivatives related to the CQP Credit Facilities, which resulted in a derivative gain of $28 million.

CCH has entered into interest rate swaps (“CCH Interest Rate Derivatives”) to hedge a portion of the variable interest payments on its credit facility (the “CCH Credit Facility”). In June 2018, CCH settled a portion of the CCH Interest Rate Derivatives and recognized a derivative gain of $5 million upon the termination of interest rate swaps associated with the amendment of the CCH Credit Facility, as discussed in Note 10—Debt. In May 2017, CCH settled a portion of the CCH Interest Rate Derivatives and recognized a derivative loss of $13 million in conjunction with the termination of approximately $1.4 billion of commitments under the CCH Credit Facility.

SPL had entered into interest rate swaps (“SPL Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “SPL Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the SPL Credit Facilities. In March 2017, SPL settled the SPL Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the SPL Credit Facilities.

As of September 30, 2018, we had the following Interest Rate Derivatives outstanding:

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
CQP Interest Rate Derivatives	$225 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR
CCH Interest Rate Derivatives	$29 million	$4.7 billion	May 20, 2015	May 31, 2022	2.30%	One-month LIBOR

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

	September 30, 2018						December 31, 2017
	CQP Interest Rate Derivatives		CCH Interest Rate Derivatives		Total		CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total
Consolidated Balance Sheet Location
Derivative assets	$	19	$	13	$	32	$	7	$	—		$	7
Non-current derivative assets	9		81		90		14		3			17
Total derivative assets	28		94		122		21		3			24
Derivative liabilities	—		—		—		—		(20		)	(20		)
Non-current derivative liabilities	—		—		—		—		(15		)	(15		)
Total derivative liabilities	—		—		—		—		(35		)	(35		)
Derivative asset (liability), net	$	28	$	94	$	122	$	21	$	(32	)	$	(11	)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
CQP Interest Rate Derivatives gain	$	2	$	1		$	13	$	—
CCH Interest Rate Derivatives gain (loss)	21		(3		)	119		(35		)
SPL Interest Rate Derivatives loss	—		—			—		(2		)

Commodity Derivatives

SPL and CCL have entered into index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the SPL Project and the CCL Project. The terms of the physical natural gas supply contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent.

The following table shows the fair value and location of our Liquefaction Supply Derivatives and LNG Trading Derivatives(collectively, “Commodity Derivatives”) on our Consolidated Balance Sheets (in millions, except notional amount):

	September 30, 2018									December 31, 2017
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total			Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total
Consolidated Balance Sheet Location
Derivative assets	$	13		$	7		$	20		$	41		$	9		$	50
Non-current derivative assets	27			4			31			17			—			17
Total derivative assets	40			11			51			58			9			67
Derivative liabilities	(6		)	(90		)	(96		)	—			(17		)	(17		)
Non-current derivative liabilities	(5		)	(11		)	(16		)	(3		)	—			(3		)
Total derivative liabilities	(11		)	(101		)	(112		)	(3		)	(17		)	(20		)
Derivative asset (liability), net	$	29		$	(90	)	$	(61	)	$	55		$	(8	)	$	47
Notional amount, net (in TBtu) (3)	4,769			20						2,539			25

(1) Does not include collateral calls of $3 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively.

(2) Does not include collateral of $58 million and $28 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively.

(3) SPL had secured up to approximately 2,755 TBtu and 2,214 TBtu and CCL had secured up to approximately 2,640 TBtu and 2,024 TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2018 and December 31, 2017, respectively.

The following table shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Consolidated Statements of Operations Location (1)	Three Months Ended September 30,						Nine Months Ended September 30,
		2018			2017			2018			2017
LNG Trading Derivatives loss	LNG revenues	$	(58	)	$	(16	)	$	(128	)	$	(20	)
Liquefaction Supply Derivatives gain (loss) (2)	Cost of sales	21			(11		)	(32		)	(51		)

(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

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

		Fair Value Measurements as of
	Consolidated Balance Sheet Location	September 30, 2018		December 31, 2017
FX Derivatives	Derivative assets	$	11	$	—
FX Derivatives	Non-current derivative liabilities	—		(1		)

The total notional amount of our FX Derivatives was $227 million and $27 million as of September 30, 2018 and December 31, 2017, respectively.

The following table shows the changes in the fair value of our FX Derivatives recorded in LNG revenues on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
FX Derivatives gain	$	1	$	—	$	11	$	—

Consolidated Balance Sheet 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):

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2018
CQP Interest Rate Derivatives	$	28		$	—		$	28
CCH Interest Rate Derivatives	94			—			94
Liquefaction Supply Derivatives	46			(6		)	40
Liquefaction Supply Derivatives	(22		)	11			(11		)
LNG Trading Derivatives	50			(39		)	11
LNG Trading Derivatives	(154		)	53			(101		)
FX Derivatives	21			(10		)	11
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
CCH Interest Rate Derivatives	3			—			3
CCH Interest Rate Derivatives	(35		)	—			(35		)
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)
LNG Trading Derivatives	9			—			9
LNG Trading Derivatives	(37		)	20			(17		)
FX Derivatives	(1		)	—			(1		)

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Other Non-Current Assets

9 Months Ended

Sep. 30, 2018

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

As of September 30, 2018 and December 31, 2017, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	15	$	26
Advances made to municipalities for water system enhancements	90		97
Advances and other asset conveyances to third parties to support LNG terminals	48		48
Tax-related payments and receivables	21		29
Equity method investments	92		64
Other	29		24
Total other non-current assets, net	$	295	$	288

Equity Method Investments

Our equity method investments consist of interests in privately-held companies. In 2017, we acquired an equity interest in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”). Midship Pipeline is pursuing the development, construction, operation and maintenance of an approximately 200-mile natural gas pipeline project (the “Midship Project”) that connects new production in the Anadarko Basin to Gulf Coast markets. Midship Holdings entered into agreements with investment funds managed by EIG Global Energy Partners (“EIG”) under which EIG-managed funds committed to make an investment of up to $500 million (the “EIG Investment”) in the Midship Project, subject to the terms and conditions contained in the applicable agreements. The EIG Investment, when combined with equity contributed by us, is intended to ensure the Midship Project has the equity funding expected to be required to develop and construct the project. Construction of the Midship Project will commence based upon, among other things, obtaining the required authorization from the FERC and adequate financing to construct the proposed project.

We have determined that Midship Holdings is a variable interest entity (“VIE”) because it is thinly capitalized at formation such that the total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support. We do not consolidate Midship Holdings because we do not have power to direct the activities that most significantly impact its economic performance. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause a change in our identification of a VIE or determination of the primary beneficiary to a VIE. We account for our investment in Midship Holdings under the equity method as we have the ability to exercise significant influence over the operating and financial policies of Midship Holdings through our non-controlling voting rights on its board of managers. Our investment in Midship Holdings was $84 million and $55 million at September 30, 2018 and December 31, 2017, respectively. Our obligations to make additional investments in Midship Holdings are not significant.

Cheniere LNG O&M Services, LLC (“O&M Services”), our wholly owned subsidiary, provides the development, construction, operation and maintenance services associated with the Midship Project pursuant to agreements in which O&M Services receives an agreed upon fee and reimbursement of costs incurred. O&M Services recorded $4 million and $1 million in the three months ended September 30, 2018 and 2017, respectively, and $8 million and $2 million in the nine months ended September 30, 2018 and 2017, respectively, of revenues in other—related party and $3 million and $2 million of accounts receivable—related party as of September 30, 2018 and December 31, 2017, respectively, for services provided to Midship Pipeline under these agreements. CCL has entered into a transportation precedent agreement with Midship Pipeline to secure firm pipeline transportation capacity for a period of 10 years following commencement of the Midship Project. In May 2018, CCL issued a letter of credit to Midship Pipeline for drawings up to an aggregate maximum amount of $16 million. Midship Pipeline had not made any drawings on this letter of credit as of September 30, 2018.

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Non-Controlling Interest

9 Months Ended

Sep. 30, 2018

Noncontrolling Interest [Abstract]

Non-Controlling Interest

NON-CONTROLLING INTEREST

During the three and nine months ended September 30, 2018, we acquired 8.1% and 17.3%, respectively, of additional interest in Cheniere Holdings previously held by the public, and closed the previously announced merger of Cheniere Holdings with and into our wholly owned subsidiary. As a result of the merger, all of the publicly-held shares of Cheniere Holdings not owned by us were canceled and shareholders other than Cheniere received shares of our common stock in a stock-for-share exchange. As of December 31, 2017, we owned 82.7% of Cheniere Holdings. Because the transactions represented a combination of ownership interests under common control, changes in Cheniere’s ownership interest in Cheniere Holdings were accounted for as an equity transaction and no gain or loss was recognized.

We own a 48.6% limited partner interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco LP 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 variable interest entity. See Note 9—Variable Interest Entities of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for further information.

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Accrued Liabilities

9 Months Ended

Sep. 30, 2018

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

As of September 30, 2018 and December 31, 2017, accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2018		2017
Interest costs and related debt fees	$	252	$	397
Accrued natural gas purchases	251		298
LNG terminals and related pipeline costs	228		192
Compensation and benefits	113		141
Accrued LNG inventory	76		1
Other accrued liabilities	67		49
Total accrued liabilities	$	987	$	1,078

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Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Debt

DEBT

As of September 30, 2018 and December 31, 2017, our debt consisted of the following (in millions): 

	September 30,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			—
CQP Credit Facilities	—			1,090
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250			1,250
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500			1,500
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500			1,500
CCH Credit Facility	4,492			2,485
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,416			1,305
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”)	1,189			1,161
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”)	625			625
$750 million Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	—			—
Unamortized premium, discount and debt issuance costs, net	(784		)	(730		)
Total long-term debt, net	27,438			25,336
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	—			—
Cheniere Marketing trade finance facilities	66			—
Total current debt	66			—
Total debt, net	$	27,504		$	25,336

2018 Debt Issuances and Redemptions

2026 CQP Senior Notes

In September 2018, Cheniere Partners issued an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (the “CQP Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP. Net proceeds of the offering of approximately $1.1 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay all of the outstanding indebtedness under the CQP Credit Facilities, resulting in the recognition of debt modification and extinguishment costs of $12 million for the three and nine months ended September 30, 2018 relating to the incurrence of third party fees and write off of unamortized debt issuance costs. As of September 30, 2018, only a $115 million revolving credit facility, all of which is undrawn, remains as part of the CQP Credit Facilities.

Borrowings under the 2026 CQP Senior Notes accrue interest at a fixed rate of 5.625%, and interest on the 2026 CQP Senior Notes is payable semi-annually in arrears. The 2026 CQP Senior Notes are governed by the same base indenture as the 2025 CQP Senior Notes (the “CQP Base Indenture”), and are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”), which contains customary 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, Cheniere Partners may redeem all or a part of the 2026 CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the 2026 CQP Senior Notes redeemed, plus the “applicable premium” set forth in the 2026 CQP Notes Indenture, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2021, Cheniere Partners may redeem up to 35% of the aggregate principal amount of the 2026 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 redeemed, plus accrued and unpaid interest, if any, to the date of redemption. At any time on or after October 1, 2021 through the maturity date of October 1, 2026, Cheniere Partners may redeem the 2026 CQP Senior Notes, in whole or in part, at the redemption prices set forth in the 2026 CQP Notes Indenture.

The 2026 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. After applying the proceeds from the 2026 CQP Senior Notes, the 2026 CQP Senior Notes and the 2025 CQP Senior Notes(collectively, the “CQP Senior Notes”) became unsecured. 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 CQP Credit Facilities. The obligations under the CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) 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 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the CQP Credit Facilities).

In connection with the closing of the 2026 CQP Senior Notes offering, Cheniere Partners and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, Cheniere Partners and the CQP Guarantors have agreed to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2026 CQP Senior Notes for a like aggregate principal amount of debt securities of Cheniere Partners with terms identical in all material respects to the 2026 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after the notes issuance date of September 11, 2018. Under specified circumstances, Cheniere Partners and the CQP Guarantors have also agreed to cause to become effective a shelf registration statement relating to resales of the 2026 CQP Senior Notes. Cheniere Partners will be obligated to pay additional interest on the 2026 CQP Senior Notes if it fails to comply with its obligation to register the 2026 CQP Senior Notes within the specified time period.

CCH Credit Facility

In May 2018, CCH amended and restated the CCH Credit Facility to increase total commitments under the credit facility to $6.1 billion. Borrowings are used to fund a portion of the costs of developing, constructing and placing into service the three Trains and the related facilities of the CCL Project and for related business purposes.

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.

Loans under the CCH Credit Facility accrue interest at a variable rate per annum equal to, at CCH’s election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 1.75% and for base rate loans is 0.75%. Interest on LIBOR loans is due and payable at the end of each applicable interest period and interest on base rate loans is due and payable at the end of each quarter. CCH was required to pay certain upfront fees to the agents and lenders under the CCH Credit Facility together with additional transaction fees and expenses in the aggregate amount of $53 million.

All other terms of the CCH Credit Facility substantially remained the same to those described in Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017. The amendment and restatement of the CCH Credit Facility resulted in the recognition of $15 million of debt modification and extinguishment costs during the nine months ended September 30, 2018 relating to the incurrence of third party fees and write off of unamortized debt issuance costs.

CCH Working Capital Facility

In June 2018, CCH amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility to $1.2 billion. Borrowings will be used for certain working capital requirements related to developing and placing into operations the CCL Project and for related business purposes.

Loans under the CCH Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.25% to 1.75% per annum, and the applicable margin for base rate loans ranges from 0.25% to 0.75% per annum. CCH was required to pay certain upfront fees to the agents and lenders under the CCH Working Capital Facility together with additional transaction fees and expenses in the aggregate amount of $14 million.

The CCH Working Capital Facility matures on June 29, 2023. All other terms of the CCH Working Capital Facility substantially remained the same to those described in Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

2025 CCH HoldCo II Convertible Senior Notes

In May 2018, the amended and restated note purchase agreement under which the 2025 CCH HoldCo II Convertible Senior Notes were issued was subsequently amended in connection with commercialization and financing of Train 3 of the CCL Project.  All terms of the 2025 CCH HoldCo II Convertible Senior Notes substantially remained the same to those described in Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2018 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Original facility size	$	1,200	$	2,800	$	8,404	$	350	$	750
Incremental commitments	—		—		1,566		850		—
Less:
Outstanding balance	—		—		4,492		—		—
Commitments prepaid or terminated	—		2,685		3,832		—		—
Letters of credit issued	494		—		—		316		—
Available commitment	$	706	$	115	$	1,646	$	884	$	750
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)		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 3.25% or base rate plus 2.25%
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020		June 30, 2024		June 29, 2023		March 2, 2021

(1) There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

Convertible Notes

Below is a summary of our convertible notes outstanding as of September 30, 2018 (in millions):

	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000		$	1,000		$	625
Debt component, net of discount and debt issuance costs	$	1,090		$	1,390		$	310
Equity component	$	207		$	—		$	194
Interest payment method	Paid-in-kind			Paid-in-kind (1)			Cash
Conversion by us (2)	—			(3)			(4)
Conversion by holders (2)	(5)			(6)			(7)
Conversion basis	Cash and/or stock			Stock			Cash and/or stock
Conversion value in excess of principal	$	—		$	—		$	—
Maturity date	May 28, 2021			May 13, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate (8)	8.4		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (9)	2.7 years			2.0 years			26.5 years

(1) Prior to the substantial completion of Train 2 of the CCL Project, interest will be paid entirely in kind. Following this date, the interest generally must be paid in cash; however, a portion of the interest may be paid in kind under certain specified circumstances.

(2) Conversion is subject to various limitations and conditions.

(3) Convertible on or after the later of March 1, 2020 and the substantial completion of Train 2 of the CCL Project, provided that our market capitalization is not less than $10.0 billion (“Eligible Conversion Date”). The conversion price is the lower of (1) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock for the 90 trading day period prior to the date notice is provided, and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date notice is provided.

(4) Redeemable at any time after March 15, 2020 at a redemption price payable in cash 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.

(5) Initially convertible at $93.64 (subject to adjustment upon the occurrence of certain specified events), provided that the closing price of our common stock is greater than or equal to the conversion price on the conversion date.

(6) Convertible on or after the six-month anniversary of the Eligible Conversion Date, provided that our total market capitalization is not less than $10.0 billion, at a price equal to the average of the daily VWAP of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided.

(7) 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, 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).

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

(9) We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity except for the 2025 CCH HoldCo II Convertible Senior Notes, which are amortized through the date they are first convertible by holders into our common stock.

Restrictive Debt Covenants

As of September 30, 2018, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Interest cost on convertible notes:
Interest per contractual rate	$	60		$	55		$	176		$	162
Amortization of debt discount	9			8			25			22
Amortization of debt issuance costs	3			2			7			5
Total interest cost related to convertible notes	72			65			208			189
Interest cost on debt excluding convertible notes	354			324			1,034			931
Total interest cost	426			389			1,242			1,120
Capitalized interest	(205		)	(203		)	(589		)	(581		)
Total interest expense, net	$	221		$	186		$	653		$	539

Fair Value Disclosures

The following table shows the carrying amount, which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in millions):

	September 30, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	19,457	$	20,552	$	18,350	$	20,075
2037 SPL Senior Notes (2)	791		831		790		871
Credit facilities (3)	4,466		4,466		3,574		3,574
2021 Cheniere Convertible Unsecured Notes (2)	1,090		1,267		1,040		1,136
2025 CCH HoldCo II Convertible Senior Notes (2)	1,390		1,597		1,273		1,535
2045 Cheniere Convertible Senior Notes (4)	310		497		309		447

(1) Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2026 CQP Senior Notes, 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes. 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) Includes SPL Working Capital Facility, CQP Credit Facilities, CCH Credit Facility, CCH Working Capital Facility, Cheniere Revolving Credit Facility and Cheniere Marketing trade finance facilities. 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.

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Revenues from Contracts with Customers

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenues from Contracts with Customers

REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
LNG revenues	$	1,712	$	1,345		$	5,327	$	3,646
Regasification revenues	66		65			196		195
Other revenues	30		5			73		12
Other—related party	4		1			8		2
Total revenues from customers	1,812		1,416			5,604		3,855
Gains (losses) from derivative instruments (1)	7		(13		)	—		—
Total revenues	$	1,819	$	1,403		$	5,604	$	3,855

(1) Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

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

We intend to primarily use LNG sourced from our Sabine Pass or Corpus Christi terminals to provide contracted volumes to our customers. However, we supplement this LNG with volumes procured from third parties. LNG revenues recognized from LNG that was procured from third parties was $208 million and $427 million for the three months ended September 30, 2018 and 2017, respectively, and $394 million and $631 million for the nine months ended September 30, 2018 and 2017, respectively.

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

When we sell LNG on a DAT basis, we consider all transportation costs, including vessel chartering, loading/unloading and canal fees, as fulfillment costs and not as separate services provided to the customer within the arrangement, regardless of whether or not such activities occur prior to or after the customer obtains control of the LNG. We expense fulfillment costs as incurred unless otherwise dictated by GAAP.

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

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the exception for allocating variable consideration to specific parts of the contract and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its 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 Trains 5 and 6.

Upon substantial completion of Train 3 of the SPL Project, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. 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 and we continue to recognize the payments received from Total as revenue. During each of the three months ended September 30, 2018 and 2017, SPL recorded $7.5 million and during the nine months ended September 30, 2018 and 2017, SPL recorded $23 million and $15 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

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

	Nine Months Ended September 30, 2018
Deferred revenues, beginning of period	$	111
Cash received but not yet recognized	120
Revenue recognized from prior period deferral	(111		)
Deferred revenues, end of period	$	120

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the nine months ended September 30, 2018 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2018:

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	102.4	11.3
Regasification revenues	2.7		5.8
Total revenues	$	105.1

(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) 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 table above excludes all variable consideration under our SPAs and TUAs. 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. A portion of such variable consideration is considered constrained due to the uncertainty of ultimate pricing and receipt and we have not included such variable consideration in the transaction price. During each of the three and nine months ended September 30, 2018, approximately 55% of our LNG revenues from contracts with a duration of over one year and approximately 3% of our regasification revenues were related to variable consideration received from customers.

We have entered 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.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2017.

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

We recorded an income tax provision of $3 million and an income tax benefit of $2 million during the three months ended September 30, 2018 and 2017, respectively, and an income tax provision of $15 million and an income tax benefit of $1 million during the nine months ended September 30, 2018 and 2017, respectively. Changes in the income tax recorded between comparative periods are primarily attributable to fluctuations in the profitability of our U.K. integrated marketing function.

The effective tax rates during the three and nine months ended September 30, 2018 and 2017 were lower than the 21% and 35% federal statutory rates during the 2018 and 2017 interim periods, respectively, primarily as a result of maintaining a valuation allowance against our federal and state net deferred tax assets. Due to historical losses and other available evidence related to our ability to generate taxable income, we continue to maintain a valuation allowance against our federal and state net deferred tax assets at September 30, 2018.

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Share-Based Compensation

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

SHARE-BASED COMPENSATION

We have granted restricted stock shares, restricted stock units, performance stock units and phantom units to employees and non-employee directors under the Amended and Restated 2003 Stock Incentive Plan, as amended, the 2011 Incentive Plan, as amended (the “2011 Plan”), the 2015 Employee Inducement Incentive Plan and the 2015 Long-Term Cash Incentive Plan.

For the nine months ended September 30, 2018, we granted 2.3 million restricted stock units and 0.2 million performance stock units at target performance under the 2011 Plan to certain employees. Restricted stock units are stock awards that vest over a two- to three-year service period 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 three-year cliff vesting with payouts based on our cumulative distributable cash flow per share from January 1, 2018 through December 31, 2020 compared to a pre-established performance target. The number of shares that may be earned at the end of the vesting period ranges from 50 to 200 percent of the target award amount if the threshold performance is met. 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.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Share-based compensation costs, pre-tax:
Equity awards	$	25		$	10		$	64		$	25
Liability awards	13			12			45			56
Total share-based compensation	38			22			109			81
Capitalized share-based compensation	(7		)	(4		)	(20		)	(17		)
Total share-based compensation expense	$	31		$	18		$	89		$	64
Tax benefit associated with share-based compensation expense	$	1		$	1		$	3		$	3

For further discussion of our equity incentive plans, see Note 16—Share-Based Compensation of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

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Net Income (Loss) Per Share Attributable to Common Stockholders

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Net Income (Loss) Per Share Attributable to Common Stockholders

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 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 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.

The following table reconciles basic and diluted weighted average common shares outstanding for the three and nine months ended September 30, 2018 and 2017 (in millions, except per share data):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
Weighted average common shares outstanding:
Basic	247.2		232.6			241.9		232.5
Dilutive unvested stock	3.0		—			2.7		—
Diluted	250.2		232.6			244.6		232.5
Basic net income (loss) per share attributable to common stockholders	$	0.26	$	(1.24	)	$	1.67	$	(2.24	)
Diluted net income (loss) per share attributable to common stockholders	$	0.26	$	(1.24	)	$	1.65	$	(2.24	)

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Unvested stock (1)	2.0	1.5	2.3	1.5
Convertible notes (2)	17.3	16.8	17.1	16.8
Total potentially dilutive common shares	19.3	18.3	19.4	18.3

(1) Does not include 0.4 million shares for each of the three and nine months ended September 30, 2018 and 5.1 million shares for each of the three and nine months ended September 30, 2017, of unvested stock because the performance conditions had not yet been satisfied as of September 30, 2018 and 2017, respectively.

(2) Includes number of shares in aggregate issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes. There were no shares included in the computation of diluted net income (loss) per share for the 2025 CCH HoldCo II Convertible Senior Notes because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of September 30, 2018.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of September 30, 2018, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

Obligations under Certain Guarantee Contracts

Cheniere and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate transactions with third parties. These arrangements include financial guarantees, letters of credit and debt guarantees. As of September 30, 2018 and December 31, 2017, there were no liabilities recognized under these guarantee arrangements.

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.

Parallax Litigation

In 2015, our wholly owned subsidiary, Cheniere LNG Terminals, LLC (“CLNGT”), entered into discussions with Parallax Enterprises, LLC (“Parallax Enterprises”) regarding the potential joint development of two liquefaction plants in Louisiana (the “Potential Liquefaction Transactions”). While the parties negotiated regarding the Potential Liquefaction Transactions, CLNGT loaned Parallax Enterprises approximately $46 million, as reflected in a secured note dated April 23, 2015, as amended on June 30, 2015, September 30, 2015 and November 4, 2015 (the “Secured Note”). The Secured Note was secured by all assets of Parallax Enterprises and its subsidiary entities. On June 30, 2015, Parallax Enterprises’ parent entity, Parallax Energy LLC (“Parallax Energy”), executed a Pledge and Guarantee Agreement further securing repayment of the Secured Note by providing a parent guaranty and a pledge of all of the equity of Parallax Enterprises in satisfaction of the Secured Note (the “Pledge Agreement”). CLNGT and Parallax Enterprises never executed a definitive agreement to pursue the Potential Liquefaction Transactions. The Secured Note matured on December 11, 2015, and Parallax Enterprises failed to make payment. On February 3, 2016, CLNGT filed an action against Parallax Energy, Parallax Enterprises and certain of Parallax Enterprises’ subsidiary entities, styled Cause No. 4:16-cv-00286, Cheniere LNG Terminals, LLC v. Parallax Energy LLC, et al., in the United States District Court for the Southern District of Texas (the “Texas Federal Suit”). CLNGT asserted claims in the Texas Federal Suit for (1) recovery of all amounts due under the Secured Note and (2) declaratory relief establishing that CLNGT is entitled to enforce its rights under the Secured Note and Pledge Agreement in accordance with each instrument’s terms and that CLNGT has no obligations of any sort to Parallax Enterprises concerning the Potential Liquefaction Transactions. On March 11, 2016, Parallax Enterprises and the other defendants in the Texas Federal Suit moved to dismiss the suit for lack of subject matter jurisdiction. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery.

On March 11, 2016, Parallax Enterprises filed a suit against us and CLNGT styled Civil Action No. 62-810, Parallax Enterprises LLP v. Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC, in the 25th Judicial District Court of Plaquemines Parish, Louisiana (the “Louisiana Suit”), wherein Parallax Enterprises asserted claims for breach of contract, fraudulent inducement, negligent misrepresentation, detrimental reliance, unjust enrichment and violation of the Louisiana Unfair Trade Practices Act. Parallax Enterprises predicated its claims in the Louisiana Suit on an allegation that we and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises sought $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, we and CLNGT removed the Louisiana Suit to the United States District Court for the Eastern District of Louisiana, which subsequently transferred the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was assigned Civil Action No. 4:16-cv-01628 and transferred to the same judge presiding over the Texas Federal Suit for coordinated handling. On August 22, 2016, Parallax Enterprises voluntarily dismissed all claims asserted against CLNGT and us in the Louisiana Suit without prejudice to refiling.

On July 27, 2017, the Parallax entities named as defendants in the Texas Federal Suit reurged their motion to dismiss and simultaneously filed counterclaims against CLNGT and third party claims against us for breach of contract, breach of fiduciary duty, promissory estoppel, quantum meruit and fraudulent inducement of the Secured Note and Pledge Agreement, based on substantially the same factual allegations Parallax Enterprises made in the Louisiana Suit. These Parallax entities also simultaneously filed an action styled Cause No. 2017-49685, Parallax Enterprises, LLC, et al. v. Cheniere Energy, Inc., et al., in the 61st District Court of Harris County, Texas (the “Texas State Suit”), which asserts substantially the same claims these entities asserted in the Texas Federal Suit. On July 31, 2017, CLNGT withdrew its opposition to the dismissal of the Texas Federal Suit without prejudice on jurisdictional grounds and the federal court subsequently dismissed the Texas Federal Suit without prejudice. We and CLNGT simultaneously filed an answer and counterclaims in the Texas State Suit, asserting the same claims CLNGT had previously asserted in the Texas Federal Suit. Additionally, CLNGT filed third party claims against Parallax principals Martin Houston, Christopher Bowen Daniels, Howard Candelet and Mark Evans, as well as Tellurian Investments, Inc., Driftwood LNG, LLC, Driftwood LNG Pipeline LLC and Tellurian Services LLC, formerly known as Parallax Services LLC, including claims for tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement, fraudulent transfer, conspiracy/aiding and abetting. Discovery in the Texas State Suit is ongoing. Trial is currently set for June 2019.

We do not expect that the resolution of this litigation will have a material adverse impact on our financial results.

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Leases

9 Months Ended

Sep. 30, 2018

Leases [Abstract]

Leases

LEASES

In December 2015, we entered into a lease agreement for marine services related to the CCL Project that was classified as a capital lease. The service term of this lease commenced during the three months ended September 30, 2018, and we received two of the four tug vessels under this capital lease, which are recorded within property, plant and equipment, net on our Consolidated Balance Sheets. As of September 30, 2018, the total minimum lease payments related to the tug vessels received was $50 million, of which $20 million represents imputed interest, $1 million represents the current portion of capital lease obligations and $29 million represents the non-current portion of capital lease obligations.

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Customer Concentration

9 Months Ended

Sep. 30, 2018

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:

	Percentage of Total Third-Party Revenues				Percentage of Accounts Receivable from Third Parties
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2018	2017	2018	2017	2018	2017
Customer A	17%	19%	18%	25%	26%	28%
Customer B	15%	14%	15%	13%	24%	16%
Customer C	15%	20%	20%	10%	20%	14%
Customer D	18%	—%	13%	—%	18%	—%
Customer E	—%	20%	*	19%	—%	—%
Customer F	*	*	*	*	—%	15%

* Less than 10%

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	552	$	360
Non-cash investing and financing activities:
Acquisition of non-controlling interest in Cheniere Holdings	702		—
Contribution of assets to equity method investee	—		14
Acquisition of assets under capital lease	30		—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $471 million and $426 million as of September 30, 2018 and 2017, respectively.

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Recent Accounting Standards

9 Months Ended

Sep. 30, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards

RECENT ACCOUNTING STANDARDS

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of September 30, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We anticipate electing the optional transition method to initially apply the standard at the January 1, 2019 adoption date. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period:

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 11—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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Nature of Operations and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere have been prepared in accordance with GAAP for interim financial information and 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 year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

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Restricted Cash (Tables)

9 Months Ended

Sep. 30, 2018

Restricted Cash [Abstract]

Schedule of Restricted Cash

As of September 30, 2018 and December 31, 2017, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Current restricted cash
SPL Project	$	649	$	544
Cheniere Partners and cash held by guarantor subsidiaries	808		1,045
CCL Project	220		227
Cash held by our subsidiaries restricted to Cheniere	266		64
Total current restricted cash	$	1,943	$	1,880
Non-current restricted cash
Other	$	—	$	11

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Accounts and Other Receivables (Tables)

9 Months Ended

Sep. 30, 2018

Receivables [Abstract]

Schedule of Accounts and Other Receivables

As of September 30, 2018 and December 31, 2017, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Trade receivables
SPL	$	213	$	185
Cheniere Marketing	16		163
Other accounts receivable	14		21
Total accounts and other receivables	$	243	$	369

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Inventory (Tables)

9 Months Ended

Sep. 30, 2018

Inventory Disclosure [Abstract]

Schedule of Inventory

As of September 30, 2018 and December 31, 2017, inventory consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Natural gas	$	10	$	17
LNG	42		44
LNG in-transit	181		130
Materials and other	65		52
Total inventory	$	298	$	243

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

As of September 30, 2018 and December 31, 2017, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	13,162		$	12,687
LNG site and related costs	86			86
LNG terminal construction-in-process	14,269			11,932
Accumulated depreciation	(1,192		)	(882		)
Total LNG terminal costs, net	26,325			23,823
Fixed assets and other
Computer and office equipment	17			14
Furniture and fixtures	19			19
Computer software	97			92
Leasehold improvements	41			41
Land	59			59
Other	18			16
Accumulated depreciation	(107		)	(86		)
Total fixed assets and other, net	144			155
Tug vessels under capital lease	30			—
Property, plant and equipment, net	$	26,499		$	23,978

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2018											December 31, 2017
	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
CQP Interest Rate Derivatives asset	$	—		$	28		$	—	$	28		$	—		$	21		$	—	$	21
CCH Interest Rate Derivatives asset (liability)	—			94			—		94			—			(32		)	—		(32		)
Liquefaction Supply Derivatives asset (liability)	(1		)	4			26		29			2			10			43		55
LNG Trading Derivatives asset (liability)	(19		)	(71		)	—		(90		)	(13		)	5			—		(8		)
FX Derivatives asset (liability)	—			11			—		11			—			(1		)	—		(1		)

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2018:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$26	Market approach incorporating present value techniques	Basis Spread	$(0.748) - $0.079

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

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Balance, beginning of period	$	12		$	40		$	43		$	79
Realized and mark-to-market gains (losses):
Included in cost of sales	5			(8		)	(4		)	(43		)
Purchases and settlements:
Purchases	9			(1		)	14			1
Settlements	1			(2		)	(27		)	(8		)
Transfers out of Level 3 (1)	(1		)	—			—			—
Balance, end of period	$	26		$	29		$	26		$	29
Change in unrealized gains relating to instruments still held at end of period	$	5		$	(8	)	$	(4	)	$	(43	)

(1)    Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative Net Presentation on Consolidated Balance Sheets

The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2018
CQP Interest Rate Derivatives	$	28		$	—		$	28
CCH Interest Rate Derivatives	94			—			94
Liquefaction Supply Derivatives	46			(6		)	40
Liquefaction Supply Derivatives	(22		)	11			(11		)
LNG Trading Derivatives	50			(39		)	11
LNG Trading Derivatives	(154		)	53			(101		)
FX Derivatives	21			(10		)	11
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
CCH Interest Rate Derivatives	3			—			3
CCH Interest Rate Derivatives	(35		)	—			(35		)
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)
LNG Trading Derivatives	9			—			9
LNG Trading Derivatives	(37		)	20			(17		)
FX Derivatives	(1		)	—			(1		)

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of September 30, 2018, we had the following Interest Rate Derivatives outstanding:

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
CQP Interest Rate Derivatives	$225 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR
CCH Interest Rate Derivatives	$29 million	$4.7 billion	May 20, 2015	May 31, 2022	2.30%	One-month LIBOR

Fair Value of Derivative Instruments by Balance Sheet Location

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

	September 30, 2018						December 31, 2017
	CQP Interest Rate Derivatives		CCH Interest Rate Derivatives		Total		CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total
Consolidated Balance Sheet Location
Derivative assets	$	19	$	13	$	32	$	7	$	—		$	7
Non-current derivative assets	9		81		90		14		3			17
Total derivative assets	28		94		122		21		3			24
Derivative liabilities	—		—		—		—		(20		)	(20		)
Non-current derivative liabilities	—		—		—		—		(15		)	(15		)
Total derivative liabilities	—		—		—		—		(35		)	(35		)
Derivative asset (liability), net	$	28	$	94	$	122	$	21	$	(32	)	$	(11	)

Derivative Instruments, Gain (Loss)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
CQP Interest Rate Derivatives gain	$	2	$	1		$	13	$	—
CCH Interest Rate Derivatives gain (loss)	21		(3		)	119		(35		)
SPL Interest Rate Derivatives loss	—		—			—		(2		)

Commodity Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Instruments by Balance Sheet Location

The following table shows the fair value and location of our Liquefaction Supply Derivatives and LNG Trading Derivatives(collectively, “Commodity Derivatives”) on our Consolidated Balance Sheets (in millions, except notional amount):

	September 30, 2018									December 31, 2017
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total			Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total
Consolidated Balance Sheet Location
Derivative assets	$	13		$	7		$	20		$	41		$	9		$	50
Non-current derivative assets	27			4			31			17			—			17
Total derivative assets	40			11			51			58			9			67
Derivative liabilities	(6		)	(90		)	(96		)	—			(17		)	(17		)
Non-current derivative liabilities	(5		)	(11		)	(16		)	(3		)	—			(3		)
Total derivative liabilities	(11		)	(101		)	(112		)	(3		)	(17		)	(20		)
Derivative asset (liability), net	$	29		$	(90	)	$	(61	)	$	55		$	(8	)	$	47
Notional amount, net (in TBtu) (3)	4,769			20						2,539			25

(1) Does not include collateral calls of $3 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively.

(2) Does not include collateral of $58 million and $28 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively.

(3) SPL had secured up to approximately 2,755 TBtu and 2,214 TBtu and CCL had secured up to approximately 2,640 TBtu and 2,024 TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2018 and December 31, 2017, respectively.

Derivative Instruments, Gain (Loss)

The following table shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Consolidated Statements of Operations Location (1)	Three Months Ended September 30,						Nine Months Ended September 30,
		2018			2017			2018			2017
LNG Trading Derivatives loss	LNG revenues	$	(58	)	$	(16	)	$	(128	)	$	(20	)
Liquefaction Supply Derivatives gain (loss) (2)	Cost of sales	21			(11		)	(32		)	(51		)

(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 [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Instruments by Balance Sheet Location

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

		Fair Value Measurements as of
	Consolidated Balance Sheet Location	September 30, 2018		December 31, 2017
FX Derivatives	Derivative assets	$	11	$	—
FX Derivatives	Non-current derivative liabilities	—		(1		)

Derivative Instruments, Gain (Loss)

The following table shows the changes in the fair value of our FX Derivatives recorded in LNG revenues on our Consolidated Statements of Operations during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
FX Derivatives gain	$	1	$	—	$	11	$	—

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Other Non-Current Assets (Tables)

9 Months Ended

Sep. 30, 2018

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

As of September 30, 2018 and December 31, 2017, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	15	$	26
Advances made to municipalities for water system enhancements	90		97
Advances and other asset conveyances to third parties to support LNG terminals	48		48
Tax-related payments and receivables	21		29
Equity method investments	92		64
Other	29		24
Total other non-current assets, net	$	295	$	288

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Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2018

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

As of September 30, 2018 and December 31, 2017, accrued liabilities consisted of the following (in millions): 

	September 30,		December 31,
	2018		2017
Interest costs and related debt fees	$	252	$	397
Accrued natural gas purchases	251		298
LNG terminals and related pipeline costs	228		192
Compensation and benefits	113		141
Accrued LNG inventory	76		1
Other accrued liabilities	67		49
Total accrued liabilities	$	987	$	1,078

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Debt (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Schedule of Debt Instruments

As of September 30, 2018 and December 31, 2017, our debt consisted of the following (in millions): 

	September 30,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			—
CQP Credit Facilities	—			1,090
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250			1,250
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500			1,500
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500			1,500
CCH Credit Facility	4,492			2,485
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,416			1,305
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”)	1,189			1,161
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”)	625			625
$750 million Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	—			—
Unamortized premium, discount and debt issuance costs, net	(784		)	(730		)
Total long-term debt, net	27,438			25,336
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	—			—
Cheniere Marketing trade finance facilities	66			—
Total current debt	66			—
Total debt, net	$	27,504		$	25,336

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2018 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Original facility size	$	1,200	$	2,800	$	8,404	$	350	$	750
Incremental commitments	—		—		1,566		850		—
Less:
Outstanding balance	—		—		4,492		—		—
Commitments prepaid or terminated	—		2,685		3,832		—		—
Letters of credit issued	494		—		—		316		—
Available commitment	$	706	$	115	$	1,646	$	884	$	750
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)		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 3.25% or base rate plus 2.25%
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020		June 30, 2024		June 29, 2023		March 2, 2021

(1) There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

Schedule of Convertible Debt

Below is a summary of our convertible notes outstanding as of September 30, 2018 (in millions):

	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000		$	1,000		$	625
Debt component, net of discount and debt issuance costs	$	1,090		$	1,390		$	310
Equity component	$	207		$	—		$	194
Interest payment method	Paid-in-kind			Paid-in-kind (1)			Cash
Conversion by us (2)	—			(3)			(4)
Conversion by holders (2)	(5)			(6)			(7)
Conversion basis	Cash and/or stock			Stock			Cash and/or stock
Conversion value in excess of principal	$	—		$	—		$	—
Maturity date	May 28, 2021			May 13, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate (8)	8.4		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (9)	2.7 years			2.0 years			26.5 years

(1) Prior to the substantial completion of Train 2 of the CCL Project, interest will be paid entirely in kind. Following this date, the interest generally must be paid in cash; however, a portion of the interest may be paid in kind under certain specified circumstances.

(2) Conversion is subject to various limitations and conditions.

(3) Convertible on or after the later of March 1, 2020 and the substantial completion of Train 2 of the CCL Project, provided that our market capitalization is not less than $10.0 billion (“Eligible Conversion Date”). The conversion price is the lower of (1) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock for the 90 trading day period prior to the date notice is provided, and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date notice is provided.

(4) Redeemable at any time after March 15, 2020 at a redemption price payable in cash 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.

(5) Initially convertible at $93.64 (subject to adjustment upon the occurrence of certain specified events), provided that the closing price of our common stock is greater than or equal to the conversion price on the conversion date.

(6) Convertible on or after the six-month anniversary of the Eligible Conversion Date, provided that our total market capitalization is not less than $10.0 billion, at a price equal to the average of the daily VWAP of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided.

(7) 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, 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).

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

(9) We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity except for the 2025 CCH HoldCo II Convertible Senior Notes, which are amortized through the date they are first convertible by holders into our common stock.

Schedule of Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Interest cost on convertible notes:
Interest per contractual rate	$	60		$	55		$	176		$	162
Amortization of debt discount	9			8			25			22
Amortization of debt issuance costs	3			2			7			5
Total interest cost related to convertible notes	72			65			208			189
Interest cost on debt excluding convertible notes	354			324			1,034			931
Total interest cost	426			389			1,242			1,120
Capitalized interest	(205		)	(203		)	(589		)	(581		)
Total interest expense, net	$	221		$	186		$	653		$	539

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

The following table shows the carrying amount, which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in millions):

	September 30, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	19,457	$	20,552	$	18,350	$	20,075
2037 SPL Senior Notes (2)	791		831		790		871
Credit facilities (3)	4,466		4,466		3,574		3,574
2021 Cheniere Convertible Unsecured Notes (2)	1,090		1,267		1,040		1,136
2025 CCH HoldCo II Convertible Senior Notes (2)	1,390		1,597		1,273		1,535
2045 Cheniere Convertible Senior Notes (4)	310		497		309		447

(1) Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2026 CQP Senior Notes, 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes. 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) Includes SPL Working Capital Facility, CQP Credit Facilities, CCH Credit Facility, CCH Working Capital Facility, Cheniere Revolving Credit Facility and Cheniere Marketing trade finance facilities. 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.

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Revenues from Contracts with Customers (Tables)

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
LNG revenues	$	1,712	$	1,345		$	5,327	$	3,646
Regasification revenues	66		65			196		195
Other revenues	30		5			73		12
Other—related party	4		1			8		2
Total revenues from customers	1,812		1,416			5,604		3,855
Gains (losses) from derivative instruments (1)	7		(13		)	—		—
Total revenues	$	1,819	$	1,403		$	5,604	$	3,855

(1) Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

Contract Balances Reconciliation

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

	Nine Months Ended September 30, 2018
Deferred revenues, beginning of period	$	111
Cash received but not yet recognized	120
Revenue recognized from prior period deferral	(111		)
Deferred revenues, end of period	$	120

Transaction Price Allocated to Future Performance Obligations

The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2018:

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	102.4	11.3
Regasification revenues	2.7		5.8
Total revenues	$	105.1

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

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Share-based Compensation Expense, Net

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Share-based compensation costs, pre-tax:
Equity awards	$	25		$	10		$	64		$	25
Liability awards	13			12			45			56
Total share-based compensation	38			22			109			81
Capitalized share-based compensation	(7		)	(4		)	(20		)	(17		)
Total share-based compensation expense	$	31		$	18		$	89		$	64
Tax benefit associated with share-based compensation expense	$	1		$	1		$	3		$	3

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

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The following table reconciles basic and diluted weighted average common shares outstanding for the three and nine months ended September 30, 2018 and 2017 (in millions, except per share data):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
Weighted average common shares outstanding:
Basic	247.2		232.6			241.9		232.5
Dilutive unvested stock	3.0		—			2.7		—
Diluted	250.2		232.6			244.6		232.5
Basic net income (loss) per share attributable to common stockholders	$	0.26	$	(1.24	)	$	1.67	$	(2.24	)
Diluted net income (loss) per share attributable to common stockholders	$	0.26	$	(1.24	)	$	1.65	$	(2.24	)

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Unvested stock (1)	2.0	1.5	2.3	1.5
Convertible notes (2)	17.3	16.8	17.1	16.8
Total potentially dilutive common shares	19.3	18.3	19.4	18.3

(1) Does not include 0.4 million shares for each of the three and nine months ended September 30, 2018 and 5.1 million shares for each of the three and nine months ended September 30, 2017, of unvested stock because the performance conditions had not yet been satisfied as of September 30, 2018 and 2017, respectively.

(2) Includes number of shares in aggregate issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes. There were no shares included in the computation of diluted net income (loss) per share for the 2025 CCH HoldCo II Convertible Senior Notes because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of September 30, 2018.

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Customer Concentration (Tables)

9 Months Ended

Sep. 30, 2018

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:

	Percentage of Total Third-Party Revenues				Percentage of Accounts Receivable from Third Parties
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2018	2017	2018	2017	2018	2017
Customer A	17%	19%	18%	25%	26%	28%
Customer B	15%	14%	15%	13%	24%	16%
Customer C	15%	20%	20%	10%	20%	14%
Customer D	18%	—%	13%	—%	18%	—%
Customer E	—%	20%	*	19%	—%	—%
Customer F	*	*	*	*	—%	15%

* Less than 10%

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2018

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Nine Months Ended September 30,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	552	$	360
Non-cash investing and financing activities:
Acquisition of non-controlling interest in Cheniere Holdings	702		—
Contribution of assets to equity method investee	—		14
Acquisition of assets under capital lease	30		—

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Recent Accounting Standards (Tables)

9 Months Ended

Sep. 30, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards, Not Yet Adopted

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of September 30, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We anticipate electing the optional transition method to initially apply the standard at the January 1, 2019 adoption date. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

Recent Accounting Standards, Adopted

Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period:

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 11—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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Nature of Operations and Basis of Presentation (Details)	9 Months Ended
	Sep. 30, 2018 mi item milliontonnes / yr unit trains
Nature of Operations and Basis of Presentation [Line Items]
Number Of Natural Gas Liquefaction And Export Facilities | unit	2
Corpus Christi LNG Terminal [Member] | Stage 1 [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	2
Number Of LNG Storage Tanks | item	2
Number of marine berths | item	1
Corpus Christi LNG Terminal [Member] | Stage 2 [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	1
Number Of LNG Storage Tanks | item	1
Corpus Christi Pipeline [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length Of Natural Gas Pipeline | mi	23
Corpus Christi LNG Terminal Expansion [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	7
Number Of LNG Storage Tanks | item	1
Train Nominal Capacity | milliontonnes / yr	9.5
Cheniere Partners [Member] | Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	6
CTPL [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length Of Natural Gas Pipeline | mi	94

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Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 1,943	$ 1,880
Non-current restricted cash	0	11
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	649	544
Cheniere Partners and cash held by guarantor subsidiaries [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	808	1,045
CCL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	220	227
Cash held by our subsidiaries restricted to Cheniere [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	266	64
Other [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Non-current restricted cash	$ 0	$ 11

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Accounts and Other Receivables (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Accounts and Other Receivables [Line Items]
Other accounts receivable	$ 14	$ 21
Total accounts and other receivables	243	369
SPL [Member]
Accounts and Other Receivables [Line Items]
Trade receivables	213	185
Cheniere Marketing [Member]
Accounts and Other Receivables [Line Items]
Trade receivables	$ 16	$ 163

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Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Inventory [Line Items]
Inventory	$ 298	$ 243
Natural gas [Member]
Inventory [Line Items]
Inventory	10	17
LNG [Member]
Inventory [Line Items]
Inventory	42	44
LNG in-transit [Member]
Inventory [Line Items]
Inventory	181	130
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 65	$ 52

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 26,499	$ 23,978
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(1,192)	(882)
Property, plant and equipment, net	26,325	23,823
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	13,162	12,687
LNG site and related costs [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	86	86
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	14,269	11,932
Fixed assets and other [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(107)	(86)
Property, plant and equipment, net	144	155
Computer and office equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	17	14
Furniture and fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19	19
Computer software [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	97	92
Leasehold improvements [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	41	41
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	59	59
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	18	16
Tug vessels under capital lease [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 30	$ 0

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Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 112	$ 91	$ 331	$ 250
Offsets to LNG terminal costs	$ 0	$ 82	$ 0	$ 252

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Derivative Instruments - Narrative (Details) - USD ($) $ in Millions	1 Months Ended					9 Months Ended
	Oct. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	May 31, 2017	Mar. 31, 2017	Sep. 30, 2018	Dec. 31, 2017
CQP Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional Amount		$ 225				$ 225
CQP Interest Rate Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional Amount		1,300				1,300
CCH Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional Amount		29				29
CCH Interest Rate Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional Amount		4,700				$ 4,700
Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract						8 years
FX Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional Amount		227				$ 227	$ 27
Cheniere Partners [Member] | CQP Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease, Net		$ 1,200
Cheniere Partners [Member] | CQP Interest Rate Derivatives [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Gain (Loss), Net	$ 28
CCH [Member] | CCH Credit Facility [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease, Net				$ 1,400
CCH [Member] | CCH Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Gain (Loss), Net			$ 5	$ (13)
SPL [Member] | SPL Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease, Net					$ 1,600
SPL [Member] | SPL Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Gain (Loss), Net					$ (7)

XML

Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
CQP Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 28	$ 21
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	28	21
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
CCH Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	94	(32)
CCH Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
CCH Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	94	(32)
CCH Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	29	55
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(1)	2
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	4	10
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	26	43
LNG Trading Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(90)	(8)
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(19)	(13)
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(71)	5
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
FX Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	11	(1)
FX Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
FX Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	11	(1)
FX Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

XML

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	9 Months Ended
	Sep. 30, 2018 USD ($)
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Net Fair Value Asset	$ 26,000,000
Minimum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Significant Unobservable Inputs Range	(0.748)
Maximum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Significant Unobservable Inputs Range	$ 0.079

XML

Derivative Instruments - Schedule of Level 3 Derivatives Activity (Details) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ 12	$ 40	$ 43	$ 79
Realized and mark-to-market gains (losses):
Included in cost of sales		5	(8)	(4)	(43)
Purchases and settlements:
Purchases		9	(1)	14	1
Settlements		1	(2)	(27)	(8)
Transfers out of Level 3	[1]	(1)	0	0	0
Balance, end of period		26	29	26	29
Change in unrealized gains relating to instruments still held at end of period		$ 5	$ (8)	$ (4)	$ (43)

[1] Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

XML

Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
CQP Interest Rate Derivatives [Member]
Derivative [Line Items]
Notional Amount	$ 225
Effective Date	Mar. 22, 2016
Maturity Date	Feb. 29, 2020
Weighted Average Fixed Interest Rate Paid	1.19%
Variable Interest Rate Received	One-month LIBOR
CQP Interest Rate Derivatives [Member] | Maximum [Member]
Derivative [Line Items]
Notional Amount	$ 1,300
CCH Interest Rate Derivatives [Member]
Derivative [Line Items]
Notional Amount	$ 29
Effective Date	May 20, 2015
Maturity Date	May 31, 2022
Weighted Average Fixed Interest Rate Paid	2.30%
Variable Interest Rate Received	One-month LIBOR
CCH Interest Rate Derivatives [Member] | Maximum [Member]
Derivative [Line Items]
Notional Amount	$ 4,700

XML

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) $ in Millions		Sep. 30, 2018 USD ($) tbtu	Dec. 31, 2017 USD ($) tbtu
Derivatives, Fair Value [Line Items]
Derivative assets		$ 63	$ 57
Non-current derivative assets		121	34
Derivative liabilities		(96)	(37)
Non-current derivative liabilities		(16)	(19)
Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		122	24
Total derivative liabilities		0	(35)
Derivative asset (liability), net		122	(11)
Interest Rate Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		32	7
Interest Rate Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		90	17
Interest Rate Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		0	(20)
Interest Rate Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0	(15)
CQP Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		28	21
Total derivative liabilities		0	0
Derivative asset (liability), net		28	21
CQP Interest Rate Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		19	7
CQP Interest Rate Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		9	14
CQP Interest Rate Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		0	0
CQP Interest Rate Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0	0
CCH Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		94	3
Total derivative liabilities		0	(35)
Derivative asset (liability), net		94	(32)
CCH Interest Rate Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		13	0
CCH Interest Rate Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		81	3
CCH Interest Rate Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		0	(20)
CCH Interest Rate Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0	(15)
Commodity Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		51	67
Total derivative liabilities		(112)	(20)
Derivative asset (liability), net		(61)	47
Commodity Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		20	50
Commodity Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		31	17
Commodity Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(96)	(17)
Commodity Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		(16)	(3)
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[1]	40	58
Total derivative liabilities	[1]	(11)	(3)
Derivative asset (liability), net	[1]	$ 29	$ 55
Notional amount | tbtu	[2]	4,769	2,539
Derivative, collateral deposit (call)		$ (3)	$ (1)
Liquefaction Supply Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	13	41
Liquefaction Supply Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[1]	27	17
Liquefaction Supply Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(6)	0
Liquefaction Supply Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[1]	(5)	(3)
LNG Trading Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[3]	11	9
Total derivative liabilities	[3]	(101)	(17)
Derivative asset (liability), net	[3]	$ (90)	$ (8)
Notional amount | tbtu		20	25
Derivative, collateral deposit (call)		$ 58	$ 28
LNG Trading Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[3]	7	9
LNG Trading Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[3]	4	0
LNG Trading Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[3]	(90)	(17)
LNG Trading Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[3]	(11)	0
FX Derivatives [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		11	0
FX Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		$ 0	$ (1)
SPL [Member]
Derivatives, Fair Value [Line Items]
Energy Units Secured Through Natural Gas Supply Contracts | tbtu		2,755	2,214
CCL [Member]
Derivatives, Fair Value [Line Items]
Energy Units Secured Through Natural Gas Supply Contracts | tbtu		2,640	2,024

[1] Does not include collateral calls of $3 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively.

[2] SPL had secured up to approximately 2,755 TBtu and 2,214 TBtu and CCL had secured up to approximately 2,640 TBtu and 2,024 TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2018 and December 31, 2017, respectively.

[3] Does not include collateral of $58 million and $28 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively.

XML

Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
CQP Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 2	$ 1	$ 13	$ 0
CCH Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		21	(3)	119	(35)
SPL Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		0	0	0	(2)
LNG Trading Derivatives [Member] | LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	(58)	(16)	(128)	(20)
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	21	(11)	(32)	(51)
FX Derivatives [Member] | LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 1	$ 0	$ 11	$ 0

[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.

XML

Derivative Instruments - Derivative Net Presentation on Consolidated Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
CQP Interest Rate Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 28	$ 21
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	0	0
Derivative Assets (Liabilities), at Fair Value, Net	28	21
CCH Interest Rate Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	94	3
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	0	0
Derivative Assets (Liabilities), at Fair Value, Net	94	3
CCH Interest Rate Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(35)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		0
Derivative Assets (Liabilities), at Fair Value, Net		(35)
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	46	64
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(6)	(6)
Derivative Assets (Liabilities), at Fair Value, Net	40	58
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(22)	(3)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	11	0
Derivative Assets (Liabilities), at Fair Value, Net	(11)	(3)
LNG Trading Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	50	9
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(39)	0
Derivative Assets (Liabilities), at Fair Value, Net	11	9
LNG Trading Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(154)	(37)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	53	20
Derivative Assets (Liabilities), at Fair Value, Net	(101)	(17)
FX Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	21
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(10)
Derivative Assets (Liabilities), at Fair Value, Net	$ 11
FX Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(1)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		0
Derivative Assets (Liabilities), at Fair Value, Net		$ (1)

XML

Other Non-Current Assets - Schedule of Non-Current Assets (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Other Assets, Noncurrent [Abstract]
Advances made under EPC and non-EPC contracts	$ 15	$ 26
Advances made to municipalities for water system enhancements	90	97
Advances and other asset conveyances to third parties to support LNG terminals	48	48
Tax-related payments and receivables	21	29
Equity method investments	92	64
Other	29	24
Other non-current assets, net	$ 295	$ 288

XML

Other Non-Current Assets - Equity Method Investments (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) mi	Sep. 30, 2017 USD ($)	May 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Investment [Line Items]
Equity method investment	$ 92,000,000		$ 92,000,000			$ 64,000,000
Accounts receivable—related party	3,000,000		3,000,000			2,000,000
Midship Holdings [Member]
Investment [Line Items]
Equity method investment	84,000,000		84,000,000			55,000,000
O&M Services [Member] | Midship Pipeline [Member] | Service Agreements [Member]
Investment [Line Items]
Other—related party	4,000,000	$ 1,000,000	8,000,000	$ 2,000,000
Accounts receivable—related party	3,000,000		$ 3,000,000			$ 2,000,000
CCL [Member] | Midship Pipeline [Member] | Natural Gas Transportation Agreement [Member]
Investment [Line Items]
Long-term Purchase Commitment, Period			10 years
Midship Pipeline [Member]
Investment [Line Items]
Length Of Natural Gas Pipeline | mi			200
Midship Pipeline [Member] | CCL [Member] | Midship Pipeline Letter of Credit [Member]
Investment [Line Items]
Letter of Credit, Maximum Borrowing Capacity					$ 16,000,000
Letters of credit issued	0		$ 0
EIG [Member] | Maximum [Member]
Investment [Line Items]
Investment Company, Financial Commitment to Investee, Future Amount	$ 500,000,000		$ 500,000,000

XML

Non-Controlling Interest (Details) - shares shares in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Cheniere Holdings [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest of Cheniere Holdings, Acquired	8.10%	17.30%
Noncontrolling Interest, Ownership Percentage by Parent			82.70%
Cheniere Partners [Member]
Noncontrolling Interest [Line Items]
Limited Partner Ownership percentage		48.60%
General Partner ownership percentage		100.00%
Common Units [Member] | Cheniere Partners [Member]
Noncontrolling Interest [Line Items]
Partners Capital Account, Units, Units Held	104.5	104.5
Subordinated Units [Member] | Cheniere Partners [Member]
Noncontrolling Interest [Line Items]
Partners Capital Account, Units, Units Held	135.4	135.4

XML

Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 252	$ 397
Accrued natural gas purchases	251	298
LNG terminals and related pipeline costs	228	192
Compensation and benefits	113	141
Accrued LNG inventory	76	1
Other accrued liabilities	67	49
Total accrued liabilities	$ 987	$ 1,078

XML

Debt - Schedule of Debt Instruments (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net	$ (784,000,000)	$ (730,000,000)
Long-Term Debt, Net	27,438,000,000	25,336,000,000
Current Debt, Net	66,000,000	0
Total Debt, Net	27,504,000,000	25,336,000,000
2021 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2022 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,000,000,000	1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.25%
2023 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%
2025 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,350,000,000	1,350,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.20%
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 800,000,000	800,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2025 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.25%
2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,100,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	5.625%
CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	1,090,000,000
2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,250,000,000	1,250,000,000
Debt Instrument, Interest Rate, Stated Percentage	7.00%
2025 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.125%
CCH Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 4,492,000,000	2,485,000,000
2025 CCH Holdco II Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,416,000,000	1,305,000,000
Debt Instrument, Interest Rate, Stated Percentage	11.00%
2021 Cheniere Convertible Unsecured Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,189,000,000	1,161,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.875%
2045 Cheniere Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 625,000,000	625,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Cheniere Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	0
Line of Credit Facility, Maximum Borrowing Capacity	750,000,000
SPL Working Capital Facility [Member]
Debt Instrument [Line Items]
Current Debt, Net	0	0
Line of Credit Facility, Maximum Borrowing Capacity	1,200,000,000.0
CCH Working Capital Facility [Member]
Debt Instrument [Line Items]
Current Debt, Net	0	0
Line of Credit Facility, Maximum Borrowing Capacity	1,200,000,000.0
Cheniere Marketing Trade Finance Facilities [Member]
Debt Instrument [Line Items]
Current Debt, Net	$ 66,000,000	$ 0

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Debt - Debt Issuances and Redemptions - 2026 CQP Senior Notes (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Debt Instrument [Line Items]
Loss on modification or extinguishment of debt		$ 12	$ 25	$ 27	$ 100
2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.625%	5.625%		5.625%
Cheniere Partners [Member] | 2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 1,100	$ 1,100		$ 1,100
Net proceeds from issuances of long-term debt	$ 1,100
Loss on modification or extinguishment of debt		$ 12		$ 12
Debt Instrument, Interest Rate, Stated Percentage	5.625%	5.625%		5.625%
Debt Instrument, Redemption Price, Percentage				100.00%
Debt Instrument, Redemption Price, Percentage Price For Amount Which May Be Redeemed With Cash Proceeds From Certain Equity Offerings				105.625%
Debt Instrument Registration Period				360 days
Cheniere Partners [Member] | 2026 CQP Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Amount, Percentage of Principal Amount Which May Be Redeemed With Cash Proceeds From Certain Equity Offerings				35.00%
Cheniere Partners [Member] | CQP Credit Facilities - Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 115	$ 115		$ 115
Cheniere Partners [Member] | CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Monetary Amount	$ 1,500	$ 1,500		$ 1,500
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Percentage of Net Tangible Assets				10.00%

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Debt - Debt Issuances - Credit Facilities (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) Rate trains	Sep. 30, 2017 USD ($)	May 31, 2018 USD ($)
Line of Credit Facility [Line Items]
Loss on modification or extinguishment of debt | $	$ 12,000,000	$ 25,000,000	$ 27,000,000	$ 100,000,000
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR or base rate
CCH Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.75%
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.75%
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity | $	1,200,000,000.0		$ 1,200,000,000.0
Debt Instrument, Description of Variable Rate Basis			LIBOR or base rate
CCH Working Capital Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.25%
CCH Working Capital Facility [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.25%
CCH Working Capital Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.75%
CCH Working Capital Facility [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.75%
CCH [Member] | CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity | $					$ 6,100,000,000
Number of Liquefaction LNG Trains | trains			3
Maturity date			Jun. 30, 2024
Line of Credit Facility, Date of First Quarterly Payment, Number of Months Following Project Completion			3 months
Line Of Credit Facility, Amortization Period			19 years
Debt Instrument, Description of Variable Rate Basis			LIBOR or the base rate
Debt Issuance Costs, Required Fees to Agents and Lenders | $	53,000,000		$ 53,000,000
Loss on modification or extinguishment of debt | $			$ 15,000,000
CCH [Member] | CCH Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate			1.75%
CCH [Member] | CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate			0.75%
CCH [Member] | CCH Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Fixed Charge, Coverage Ratio, Projected | Rate			1.50
CCH [Member] | CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity | $	1,200,000,000		$ 1,200,000,000
Maturity date			Jun. 29, 2023
Debt Instrument, Description of Variable Rate Basis			LIBOR or the base rate
Debt Issuance Costs, Required Fees to Agents and Lenders | $	$ 14,000,000		$ 14,000,000
CCH [Member] | CCH Working Capital Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate			1.25%
CCH [Member] | CCH Working Capital Facility [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate			0.25%
CCH [Member] | CCH Working Capital Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate			1.75%
CCH [Member] | CCH Working Capital Facility [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate			0.75%

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Debt - Credit Facilities Table (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Outstanding balance - current		$ 66	$ 0
SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size		1,200
Incremental commitments		0
Outstanding balance - current		0	0
Commitments prepaid or terminated		0
Letters of credit issued		494
Available commitment		$ 706
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		December 31, 2020, with various terms for underlying loans
SPL Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
SPL Working Capital Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 2,800
Incremental commitments		0
Outstanding balance		0	1,090
Commitments prepaid or terminated		2,685
Letters of credit issued		0
Available commitment		$ 115
Debt Instrument, Description of Variable Rate Basis	[1]	LIBOR or base rate
Debt Instrument, Maturity Date, Description		February 25, 2020
CQP Credit Facilities [Member] | February 25, 2019 [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase		0.50%
CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]	2.25%
CQP Credit Facilities [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]	1.25%
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 8,404
Incremental commitments		1,566
Outstanding balance		4,492	2,485
Commitments prepaid or terminated		3,832
Letters of credit issued		0
Available commitment		$ 1,646
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		June 30, 2024
CCH Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 350
Incremental commitments		850
Outstanding balance - current		0	0
Commitments prepaid or terminated		0
Letters of credit issued		316
Available commitment		$ 884
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		June 29, 2023
CCH Working Capital Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.25%
CCH Working Capital Facility [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.25%
CCH Working Capital Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
CCH Working Capital Facility [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
Cheniere Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 750
Incremental commitments		0
Outstanding balance		0	$ 0
Commitments prepaid or terminated		0
Letters of credit issued		0
Available commitment		$ 750
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		March 2, 2021
Cheniere Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		3.25%
Cheniere Revolving Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.25%

[1] There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

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Debt - Convertible Notes (Details)	9 Months Ended
	Sep. 30, 2018 USD ($) d $ / shares
2021 Cheniere Convertible Unsecured Notes [Member]
Debt Instrument [Line Items]
Aggregate original principal	$ 1,000,000,000
Debt component, net of discount and debt issuance costs	1,090,000,000
Equity component	207,000,000
Conversion value in excess of principal	$ 0
Maturity date	May 28, 2021
Contractual interest rate	4.875%
Effective interest rate	8.40%	[1]
Remaining debt discount and debt issuance costs amortization period	2 years 260 days	[2]
2021 Cheniere Convertible Unsecured Notes [Member] | Note Holders [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Price | $ / shares	$ 93.64
2025 CCH Holdco II Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate original principal	$ 1,000,000,000
Debt component, net of discount and debt issuance costs	1,390,000,000
Equity component	0
Conversion value in excess of principal	$ 0
Maturity date	May 13, 2025
Contractual interest rate	11.00%
Effective interest rate	11.90%	[1]
Remaining debt discount and debt issuance costs amortization period	2 years	[2]
2025 CCH Holdco II Convertible Senior Notes [Member] | Cheniere [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible,Threshold Market Capitalization	$ 10,000,000,000
Debt Instrument, Convertible, Percentage of Conversion 1, Discount to VWAP	10.00%
Debt Instrument, Convertible, Consecutive Trading Days | d	90
Debt Instrument, Convertible, Percentage Of Conversion 2, Discount to closing price of common stock	10.00%
2025 CCH Holdco II Convertible Senior Notes [Member] | Note Holders [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible,Threshold Market Capitalization	$ 10,000,000,000
Debt Instrument, Convertible, Consecutive Trading Days | d	90
Debt Instrument, Convertible, Earliest date of conversion, Period after closing	6 months
2045 Cheniere Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate original principal	$ 625,000,000
Debt component, net of discount and debt issuance costs	310,000,000
Equity component	194,000,000
Conversion value in excess of principal	$ 0
Maturity date	Mar. 15, 2045
Contractual interest rate	4.25%
Effective interest rate	9.40%	[1]
Remaining debt discount and debt issuance costs amortization period	26 years 175 days	[2]
2045 Cheniere Convertible Senior Notes [Member] | Note Holders [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Price | $ / shares	$ 138.38
Debt Instrument, Convertible, Conversion Ratio per $1,000 principal amount, in shares	7.2265

[1] Rate to accrete the discounted carrying value of the convertible notes to the face value over the remaining amortization period.

[2] We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity except for the 2025 CCH HoldCo II Convertible Senior Notes, which are amortized through the date they are first convertible by holders into our common stock.

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Debt Instrument [Line Items]
Total interest cost	$ 426	$ 389	$ 1,242	$ 1,120
Capitalized interest	(205)	(203)	(589)	(581)
Total interest expense, net	221	186	653	539
Convertible Debt [Member]
Debt Instrument [Line Items]
Interest per contractual rate	60	55	176	162
Amortization of debt discount	9	8	25	22
Amortization of debt issuance costs	3	2	7	5
Total interest cost	72	65	208	189
Debt Excluding Convertible Debt [Member]
Debt Instrument [Line Items]
Total interest cost	$ 354	$ 324	$ 1,034	$ 931

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 27,504	$ 25,336
Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	19,457	18,350
Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	20,552	20,075
2037 SPL Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	791	790
2037 SPL Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	831	871
Credit facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[3]	4,466	3,574
Credit facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facilities, Estimated Fair Value	[3]	4,466	3,574
2021 Cheniere Convertible Unsecured Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	1,090	1,040
2021 Cheniere Convertible Unsecured Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible Debt, Estimated Fair Value	[2]	1,267	1,136
2025 CCH Holdco II Convertible Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	1,390	1,273
2025 CCH Holdco II Convertible Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible Debt, Estimated Fair Value	[2]	1,597	1,535
2045 Cheniere Convertible Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[4]	310	309
2045 Cheniere Convertible Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible Debt, Estimated Fair Value	[4]	$ 497	$ 447

[1] Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2026 CQP Senior Notes, 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes. 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] Includes SPL Working Capital Facility, CQP Credit Facilities, CCH Credit Facility, CCH Working Capital Facility, Cheniere Revolving Credit Facility and Cheniere Marketing trade finance facilities. 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.

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Revenues from Contracts with Customers (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) bcf / d item	Sep. 30, 2017 USD ($)
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
Revenue earned from contracts with customers	$ 1,812.0	$ 1,416.0	$ 5,604.0	$ 3,855.0
Regasification Capacity | bcf / d			4.0
Operating and maintenance expense	170.0	114.0	$ 457.0	309.0
TUA Customers [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d			2.0
Number Of Fixed Price Contracts | item			2
TUA Customer 1 [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d			1.0
Revenue, Performance Obligation, Fixed Consideration			$ 125.0
Long-term Purchase Commitment, Period			20 years
TUA Customer 2 [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d			1.0
Revenue, Performance Obligation, Fixed Consideration			$ 125.0
Long-term Purchase Commitment, Period			20 years
LNG procured from third parties [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	208.0	427.0	$ 394.0	631.0
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	$ 1,712.0	1,345.0	$ 5,327.0	3,646.0
Revenue, Variable Consideration Received From Customers, Percentage	55.00%		55.00%
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	$ 66.0	65.0	$ 196.0	195.0
Revenue, Variable Consideration Received From Customers, Percentage	3.00%		3.00%
Terminal Use Agreement Regasification Capacity, Partial [Member]
Disaggregation of Revenue [Line Items]
Operating and maintenance expense	$ 7.5	$ 7.5	$ 23.0	$ 15.0

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Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		$ 1,812	$ 1,416	$ 5,604	$ 3,855
Total revenues		1,819	1,403	5,604	3,855
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		1,712	1,345	5,327	3,646
Total revenues		1,719	1,332	5,327	3,646
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		66	65	196	195
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		30	5	73	12
Other, Related Party [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		4	1	8	2
Derivative Instruments [Member]
Disaggregation of Revenue [Line Items]
Total revenues	[1]	$ 7	$ (13)	$ 0	$ 0

[1] Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

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Revenues from Contracts with Customers - Schedule of Deferred Revenue Reconciliation (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	$ 111
Cash received but not yet recognized	120
Revenue recognized from prior period deferral	(111)
Deferred revenues, end of period	$ 120

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Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) $ in Billions	Sep. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 105.1
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 102.4
Weighted Average Recognition Timing	11 years 109 days	[1]
Regasification [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 2.7
Weighted Average Recognition Timing	5 years 299 days	[1]

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

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income tax benefit (provision)	$ (3)	$ 2	$ (15)	$ 1
Federal statutory tax rate	21.00%	35.00%	21.00%	35.00%

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Share-Based Compensation - Narrative (Details) - 2011 Incentive Plan [Member] shares in Millions	9 Months Ended
	Sep. 30, 2018 shares
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units granted	2.3
Restricted Stock Units [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period, Vests Ratably Over Service Period	2 years
Restricted Stock Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period, Vests Ratably Over Service Period	3 years
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units granted	0.2
Award Vesting Period, Cliff Vesting	3 years
Performance Stock Units [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of Target Amount Earned Upon Vesting If Threshold Performance is Met	50.00%
Performance Stock Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of Target Amount Earned Upon Vesting If Threshold Performance is Met	200.00%

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Share-Based Compensation - Schedule of Share-Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation	$ 38	$ 22	$ 109	$ 81
Capitalized share-based compensation	(7)	(4)	(20)	(17)
Total share-based compensation expense	31	18	89	64
Tax benefit associated with share-based compensation expense	1	1	3	3
Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation	25	10	64	25
Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation	$ 13	$ 12	$ 45	$ 56

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Net Income (Loss) Per Share Attributable to Common Stockholders (Details) - $ / shares		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Weighted Average Number of Common Shares Outstanding, Basic		247,200,000	232,600,000	241,900,000	232,500,000
Dilutive Unvested Stock		3,000,000	0		0
Weighted Average Number of Shares Outstanding, Diluted		250,200,000	232,600,000	244,600,000	232,500,000
Basic net income (loss) per share attributable to common stockholders		$ 0.26	$ (1.24)	$ 1.67	$ (2.24)
Diluted net income (loss) per share attributable to common stockholders		$ 0.26	$ (1.24)	$ 1.65	$ (2.24)
Antidilutive securities excluded from computation of earnings per share		19,300,000	18,300,000	19,400,000	18,300,000
Unvested stock [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	[1]	2,000,000	1,500,000	2,300,000	1,500,000
2021 Cheniere Convertible Notes And 2045 Cheniere Convertible Notes [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	[2]	17,300,000	16,800,000	17,100,000	16,800,000
Restricted Stock With Unsatisfied Performance Conditions [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share		400,000	5,100,000	400,000	5,100,000
2025 CCH Holdco II Convertible Senior Notes [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share		0	0	0	0

[1] Does not include 0.4 million shares for each of the three and nine months ended September 30, 2018 and 5.1 million shares for each of the three and nine months ended September 30, 2017, of unvested stock because the performance conditions had not yet been satisfied as of September 30, 2018 and 2017, respectively.

[2] Includes number of shares in aggregate issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes. There were no shares included in the computation of diluted net income (loss) per share for the 2025 CCH HoldCo II Convertible Senior Notes because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of September 30, 2018.

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Commitments and Contingencies (Details) - USD ($)	Mar. 11, 2016	Sep. 30, 2018	Dec. 31, 2017	Dec. 31, 2015
Guarantee Obligations [Member]
Commitments and Contingencies [Line Items]
Loss Contingency Accrual		$ 0	$ 0
Cheniere LNG Terminals, LLC [Member] | Parallax Enterprises [Member]
Commitments and Contingencies [Line Items]
Secured notes receivable				$ 46,000,000
Loss Contingency, Damages Sought, Value	$ 400,000,000

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Leases (Details) $ in Millions	Sep. 30, 2018 USD ($) item	Dec. 31, 2017 USD ($)
Capital Leased Assets [Line Items]
Total minimum lease payments	$ 50
Imputed interest included in payments	20
Current capital lease obligations	1
Non-current capital lease obligations	$ 29	$ 0
Tug Vessels Under Contract [Member]
Capital Leased Assets [Line Items]
Tug vessels under capital lease | item	4
Tug Vessels Received [Member]
Capital Leased Assets [Line Items]
Tug vessels under capital lease | item	2

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Customer Concentration (Details)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Customer A [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%	19.00%	18.00%	25.00%
Customer A [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			26.00%		28.00%
Customer B [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%	14.00%	15.00%	13.00%
Customer B [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			24.00%		16.00%
Customer C [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%	20.00%	20.00%	10.00%
Customer C [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			20.00%		14.00%
Customer D [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	0.00%	13.00%	0.00%
Customer D [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			18.00%		0.00%
Customer E [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%	20.00%		19.00%
Customer E [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			0.00%		0.00%
Customer F [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			0.00%		15.00%

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 552	$ 360
Noncash:
Acquisition of non-controlling interest in Cheniere Holdings	702	0
Contribution of assets to equity method investee	0	14
Acquisition of assets under capital lease	30	0
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities	$ 471	$ 426