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 June 30, 2016

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x	Accelerated filer                    ¨
Non-accelerated filer   ¨	Smaller reporting company   ¨
(Do not check if a smaller reporting company)

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

As of August 1, 2016, the issuer had 235,689,131 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	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47
Item 4.	Controls and Procedures	48
Part II. Other Information
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 5.	Other Information	50
Item 6.	Exhibits	51
	Signatures	53

i

DEFINITIONS

As commonly used in the liquefied natural gas industry, to the extent applicable and 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 consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure
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	Securities and Exchange Commission
SPA	LNG sale and purchase agreement
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 Organizational Structure

The following diagram depicts our abbreviated organizational structure as of June 30, 2016, 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. (NYSE MKT: LNG) and its consolidated subsidiaries, including our publicly traded subsidiaries, Cheniere Partners (NYSE MKT: CQP) and Cheniere Holdings (NYSE MKT: CQH).

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 thousands, except share data)

	June 30,			December 31,
	2016			2015
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	1,049,478		$	1,201,112
Restricted cash	724,458			503,397
Accounts and other receivables	74,283			5,749
Inventory	66,322			18,125
Other current assets	75,941			54,203
Total current assets	1,990,482			1,782,586
Non-current restricted cash	31,726			31,722
Property, plant and equipment, net	18,729,177			16,193,907
Debt issuance costs, net	336,474			378,677
Non-current derivative assets	20,715			30,887
Goodwill	76,819			76,819
Other non-current assets	251,458			314,455
Total assets	$	21,436,851		$	18,809,053
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	48,676		$	22,820
Accrued liabilities	589,604			427,199
Current debt, net	1,677,476			1,673,379
Deferred revenue	26,709			26,669
Derivative liabilities	72,002			35,201
Other current liabilities	54			—
Total current liabilities	2,414,521			2,185,268
Long-term debt, net	17,789,074			14,920,427
Non-current deferred revenue	7,500			9,500
Non-current derivative liabilities	311,207			79,387
Other non-current liabilities	50,382			53,068
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 June 30, 2016 and December 31, 2015
Issued and outstanding: 235.7 million shares and 235.6 million shares at June 30, 2016 and December 31, 2015, respectively	707			708
Treasury stock: 11.8 million shares and 11.6 million shares at June 30, 2016 and December 31, 2015, respectively, at cost	(357,491		)	(353,927		)
Additional paid-in-capital	3,105,728			3,075,317
Accumulated deficit	(4,243,204		)	(3,623,948		)
Total stockholders’ deficit	(1,494,260		)	(901,850		)
Non-controlling interest	2,358,427			2,463,253
Total equity	864,167			1,561,403
Total liabilities and equity	$	21,436,851		$	18,809,053

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

3

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues
Regasification revenues	$	65,622		$	66,489		$	131,173		$	133,291
LNG revenues (losses)	110,735			(706		)	113,439			(44		)
Other revenues	470			2,242			1,296			3,147
Total revenues	176,827			68,025			245,908			136,394
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	85,709			1,444			100,216			2,137
Operating and maintenance expense	45,562			17,727			81,879			53,433
Development expense	1,616			16,609			3,163			32,705
Marketing expense	26,225			20,379			51,203			33,425
General and administrative expense	61,409			87,477			109,333			132,448
Depreciation and amortization expense	32,781			20,154			56,870			37,923
Impairment expense (recovery)	(71		)	—			10,095			176
Other	50			109			162			265
Total operating costs and expenses	253,281			163,899			412,921			292,512
Loss from operations	(76,454		)	(95,874		)	(167,013		)	(156,118		)
Other income (expense)
Interest expense, net of capitalized interest	(105,967		)	(85,486		)	(182,304		)	(145,098		)
Loss on early extinguishment of debt	(55,315		)	(7,281		)	(56,772		)	(96,273		)
Derivative gain (loss), net	(90,621		)	46,049			(271,555		)	(80,641		)
Other income (expense)	(6,930		)	283			(6,001		)	655
Total other expense	(258,833		)	(46,435		)	(516,632		)	(321,357		)
Loss before income taxes and non-controlling interest	(335,287		)	(142,309		)	(683,645		)	(477,475		)
Income tax benefit (provision)	343			507			(273		)	(171		)
Net loss	(334,944		)	(141,802		)	(683,918		)	(477,646		)
Less: net loss attributable to non-controlling interest	(36,526		)	(23,307		)	(64,662		)	(91,442		)
Net loss attributable to common stockholders	$	(298,418	)	$	(118,495	)	$	(619,256	)	$	(386,204	)
Net loss per share attributable to common stockholders—basic and diluted	$	(1.31	)	$	(0.52	)	$	(2.71	)	$	(1.71	)
Weighted average number of common shares outstanding—basic and diluted	228,323			226,481			228,231			226,405

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

4

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(in thousands)

(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, 2015	235,639		$	708		11,649	$	(353,927	)	$	3,075,317		$	(3,623,948	)	$	2,463,253		$	1,561,403
Issuances of restricted stock	273		1			—	—			(1		)	—			—			—
Forfeitures of restricted stock	(96	)	(1		)	3	—			1			—			—			—
Share-based compensation	—		—			—	—			29,568			—			—			29,568
Shares repurchased related to share-based compensation	(105	)	(1		)	105	(3,564		)	1			—			—			(3,564		)
Excess tax benefit (shortfall) from share-based compensation	—		—			—	—			(15		)	—			—			(15		)
Loss attributable to non-controlling interest	—		—			—	—			—			—			(64,662		)	(64,662		)
Equity portion of convertible notes, net	—		—			—	—			857			—			—			857
Distributions to non-controlling interest	—		—			—	—			—			—			(40,164		)	(40,164		)
Net loss	—		—			—	—			—			(619,256		)	—			(619,256		)
Balance at June 30, 2016	235,711		$	707		11,757	$	(357,491	)	$	3,105,728		$	(4,243,204	)	$	2,358,427		$	864,167

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

5

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Six Months Ended June 30,
	2016			2015
Cash flows from operating activities
Net loss	$	(683,918	)	$	(477,646	)
Adjustments to reconcile net loss to net cash used in operating activities:
Non-cash LNG inventory write-downs	—			17,366
Depreciation and amortization expense	56,870			37,923
Share-based compensation	51,724			66,378
Amortization of debt issuance costs and discount	26,906			24,900
Loss on early extinguishment of debt	56,772			96,273
Total losses on derivatives, net	295,917			80,198
Net cash used for settlement of derivative instruments	(16,798		)	(88,934		)
Impairment expense	10,095			176
Other	8,811			28,957
Changes in restricted cash for certain operating activities	151,676			(55,410		)
Changes in operating assets and liabilities:
Accounts and other receivables	(67,760		)	(2,396		)
Inventory	(34,003		)	(28,919		)
Accounts payable and accrued liabilities	(14,226		)	42,101
Deferred revenue	(1,960		)	(1,985		)
Other, net	15,860			(33,937		)
Net cash used in operating activities	(144,034		)	(294,955		)
Cash flows from investing activities
Property, plant and equipment, net	(2,277,469		)	(4,294,814		)
Use of restricted cash for the acquisition of property, plant and equipment	2,279,835			4,183,620
Other	(21,623		)	(101,836		)
Net cash used in investing activities	(19,257		)	(213,030		)
Cash flows from financing activities
Proceeds from issuances of debt	5,698,219			5,205,000
Repayments of debt	(2,892,965		)	—
Debt issuance and deferred financing costs	(97,215		)	(411,149		)
Investment in restricted cash	(2,652,576		)	(4,518,880		)
Distributions and dividends to non-controlling interest	(40,164		)	(40,121		)
Proceeds from exercise of stock options	—			1,914
Payments related to tax withholdings for share-based compensation	(3,564		)	(6,174		)
Other	(78		)	19
Net cash provided by financing activities	11,657			230,609
Net decrease in cash and cash equivalents	(151,634		)	(277,376		)
Cash and cash equivalents—beginning of period	1,201,112			1,747,583
Cash and cash equivalents—end of period	$	1,049,478		$	1,470,207

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—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. 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 had no effect on our overall consolidated financial position, operating results or cash flows.

In 2016, we started production at our natural gas liquefaction facilities at the Sabine Pass LNG terminal (the “SPL Project”). As a result, we introduced two new line items entitled “Cost of sales” and “Marketing expense”, and modified the components of activity included in “Operating and maintenance expense” and “General and administrative expense” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made to the prior periods. The components of these line items are as follows:

• Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the SPL Project, vessel chartering costs and other costs related to converting natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense. Also included in cost of sales are purchase and delivery costs of our LNG and natural gas marketing business incurred by Cheniere Marketing.

• Operating and maintenance expense now primarily includes costs associated with operating and maintaining the SPL Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs.

• Marketing expense includes costs directly associated with our LNG and natural gas marketing activities by Cheniere Marketing such as payroll and benefit costs of LNG marketing and origination personnel, professional services and other support costs to contract LNG customers throughout the global marketplace for the SPL Project and our second natural gas liquefaction and export facility at the Corpus Christi LNG terminal (the “CCL Project”) and to place volumes in the market for our portfolio. These costs were reclassified from general and administrative expense.

Additionally, we distinguished and reclassified our historical “LNG terminal revenues” line item into “regasification revenues” and “LNG revenues.” Regasification revenues include LNG regasification capacity reservation fees that are received pursuant to our TUAs and tug services fees that are received by Sabine Pass Tug Services, LLC, a wholly owned subsidiary of SPLNG. Substantially all of our regasification revenues, which are generated by our LNG terminal segment, are received from our two long-term TUA customers. LNG revenues include fees that are received pursuant to our SPAs and related LNG marketing activities. During the three and six months ended June 30, 2016, we received 74% and 72%, respectively, of our net LNG revenues from one SPA customer, which were generated by our LNG terminal segment.

Results of operations for the three and six months ended June 30, 2016 are not necessarily indicative of the operating results that will be realized for the year ending December 31, 2016.

For further information, refer to the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2015.

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 June 30, 2016 and December 31, 2015, restricted cash consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Current restricted cash
SPLNG debt service and interest payment	$	77,415	$	77,415
SPL Project	263,114		189,260
CTPL construction and interest payment	—		7,882
CQP and cash held by guarantor subsidiaries	109,977		—
CCL Project	223,117		46,770
Cash held by our subsidiaries restricted to Cheniere	12,821		147,138
Other	38,014		34,932
Total current restricted cash	$	724,458	$	503,397
Non-current restricted cash
SPLNG debt service	$	13,650	$	13,650
Other	18,076		18,072
Total non-current restricted cash	$	31,726	$	31,722

Under the indentures governing the senior notes issued by SPLNG (the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until certain conditions are satisfied, including: (1) there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and (2) there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the SPLNG Indentures. During the six months ended June 30, 2016 and 2015, SPLNG made distributions of $145.3 million and $199.6 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

In February 2016, Cheniere Partners entered into a $2.8 billion credit facility (the “2016 CQP Credit Facilities”). Cheniere Partners, and Cheniere Investments and CTPL as Cheniere Partners’ guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to Cheniere Partners. Specifically, Cheniere Partners, Cheniere Investments and CTPL may only withdraw funds from collateral accounts held at a designated depositary bank on a monthly basis and for specific purposes, including for the payment of operating expenses. 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 June 30, 2016 and December 31, 2015, accounts and other receivables consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
SPL trade receivable	$	67,266	$	—
Interest receivable	259		95
Other accounts receivable	6,758		5,654
Total accounts and other receivables	$	74,283	$	5,749

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of SPL’s debt holders, SPL is required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the SPL Project and other restricted payments. As of June 30, 2016, the entire balance of the SPL trade receivable was from a single SPA customer.

8

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 4—INVENTORY

As of June 30, 2016 and December 31, 2015, inventory consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Natural gas	$	5,338	$	5,724
LNG	35,526		5,148
Materials and other	25,458		7,253
Total inventory	$	66,322	$	18,125

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of LNG terminal costs and fixed assets and other, as follows (in thousands):

	June 30,			December 31,
	2016			2015
LNG terminal costs
LNG terminal	$	5,459,151		$	2,487,759
LNG terminal construction-in-process	13,487,338			13,875,204
LNG site and related costs, net	38,753			33,512
Accumulated depreciation	(456,716		)	(413,545		)
Total LNG terminal costs, net	18,528,526			15,982,930
Fixed assets and other
Computer and office equipment	12,491			12,153
Furniture and fixtures	17,393			17,101
Computer software	76,471			69,340
Leasehold improvements	44,064			40,136
Land	60,582			60,612
Other	37,476			49,376
Accumulated depreciation	(47,826		)	(37,741		)
Total fixed assets and other, net	200,651			210,977
Property, plant and equipment, net	$	18,729,177		$	16,193,907

During the three and six months ended June 30, 2016, we realized offsets to LNG terminal costs of $131.8 million and $146.0 million, respectively, that were related to the sale of commissioning cargoes because these amounts were earned prior to the start of commercial operations, during the testing phase for the construction of Train 1 of the SPL Project.

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 of our credit facilities (“Interest Rate Derivatives”);

• commodity derivatives to hedge the exposure to price risk attributable to future: (1) sales of our LNG inventory and (2) purchases of natural gas to operate the Sabine Pass LNG terminal (“Natural Gas Derivatives”);

• commodity derivatives consisting of natural gas purchase agreements for the commissioning and operation of the SPL Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives”, and collectively with the Physical Liquefaction Supply Derivatives, 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 operations in countries outside of the United States (“FX Derivatives”).

9

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

The following table (in thousands) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of June 30, 2016 and December 31, 2015, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	June 30, 2016											December 31, 2015
	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
SPL Interest Rate Derivatives liability	$	—		$	(20,666	)	$	—	$	(20,666	)	$	—	$	(8,740	)	$	—	$	(8,740	)
CQP Interest Rate Derivatives liability	—			(19,148		)	—		(19,148		)	—		—			—		—
CCH Interest Rate Derivatives liability	—			(327,342		)	—		(327,342		)	—		(104,999		)	—		(104,999		)
Liquefaction Supply Derivatives asset (liability)	(2,850		)	381			22,434		19,965			—		(25		)	32,492		32,467
LNG Trading Derivatives asset (liability)	(1,443		)	(10,907		)	—		(12,350		)	—		1,053			—		1,053
Natural Gas Derivatives liability	—			—			—		—			—		(66		)	—		(66		)
FX Derivatives asset	—			160			—		160			—		—			—		—

We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. The estimated fair values of our economic hedges related to the LNG Trading Derivatives and our Natural Gas Derivatives are the amounts at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. We estimate the fair values of our FX Derivatives with a market approach using observable FX rates and other relevant data.

We acquired $0.8 million of certain LNG Trading Derivatives during the first three months of 2016, which we transferred into Level 1 during the three months ended June 30, 2016. We transferred these LNG Trading Derivatives to Level 1 due to the use of unadjusted quoted exchange prices to calculate the fair value of these LNG Trading derivative positions, which were previously Level 2 as the fair value was calculated using adjusted quoted exchange prices.

The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. 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 particular 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. Internal fair value models include conditions precedent to the respective long-term natural gas purchase agreements. As of June 30, 2016 and December 31, 2015, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow. Accordingly, our internal fair value models are based on market prices that equate to our own contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the completion and placement into service of relevant pipeline

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas purchase agreements as of the reporting date.

As all of our Physical Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2016:

	Net Fair Value Asset (in thousands)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$22,434	Income Approach	Basis Spread	$(0.35) - $(0.02)

The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
Balance, beginning of period	$	30,054		$	342	$	32,492		$	342
Realized and mark-to-market losses:
Included in cost of sales (1)	(7,855		)	27		(10,204		)	27
Purchases and settlements:
Purchases	(16		)	71		31			71
Settlements (1)	(71		)	—		(128		)	—
Transfers out of Level 3 (2)	322			—		243			—
Balance, end of period	$	22,434		$	440	$	22,434		$	440
Change in unrealized gains relating to instruments still held at end of period	$	(7,795	)	$	27	$	(9,484	)	$	27

(1) Does not include the decrease in fair value of $0.1 million and $0.7 million related to the realized gains capitalized during the three and six months ended June 30, 2016, respectively.

(2) 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.  

Interest Rate Derivatives

SPL Interest Rate Derivatives

SPL has 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 “2015 SPL Credit Facilities”). The SPL Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities.

In March 2015, SPL settled a portion of the SPL Interest Rate Derivatives and recognized a derivative loss of $34.7 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments under the previous credit facilities.

CQP Interest Rate Derivatives

In March 2016, Cheniere Partners entered into interest rate swaps (“CQP Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2016 CQP Credit Facilities. The CQP Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities.

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(unaudited)

CCH Interest Rate Derivatives

CCH has entered into interest rate swaps (“CCH Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on its credit facility (the “2015 CCH Credit Facility”). The CCH Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 CCH Credit Facility. The CCH Interest Rate Derivatives have a seven-year term and were contingent upon reaching a final investment decision with respect to the CCL Project, which was reached in May 2015. Upon meeting the contingency related to the CCH Interest Rate Derivatives in May 2015, we paid $50.1 million related to contingency and syndication premiums, which is included in derivative gain (loss), net on our Consolidated Statements of Operations.

As of June 30, 2016, 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
SPL Interest Rate Derivatives	$20.0 million	$628.8 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
CQP Interest Rate Derivatives	$225.0 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR
CCH Interest Rate Derivatives	$28.8 million	$5.5 billion	May 20, 2015	May 31, 2022	2.29%	One-month LIBOR

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

	June 30, 2016												December 31, 2015
	SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			CCH Interest Rate Derivatives			Total			SPL Interest Rate Derivatives			CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total
Balance Sheet Location
Derivative liabilities	$	(7,340	)	$	(5,570	)	$	(45,149	)	$	(58,059	)	$	(5,940	)	$	—	$	(28,559	)	$	(34,499	)
Non-current derivative liabilities	(13,326		)	(13,578		)	(282,193		)	(309,097		)	(2,800		)	—		(76,440		)	(79,240		)
Total derivative liabilities	$	(20,666	)	$	(19,148	)	$	(327,342	)	$	(367,156	)	$	(8,740	)	$	—	$	(104,999	)	$	(113,739	)

The following table (in thousands) 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 six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
SPL Interest Rate Derivatives gain (loss)	$	(4,752	)	$	1,469	$	(16,030	)	$	(35,669	)
CQP Interest Rate Derivatives loss	(10,040		)	—		(19,570		)	—
CCH Interest Rate Derivatives gain (loss)	(75,877		)	44,580		(236,053		)	(44,972		)

Commodity Derivatives

Liquefaction Supply Derivatives

SPL has 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. The terms of the physical natural gas supply contracts primarily range from approximately one to seven years and commence upon the satisfaction of certain conditions precedent, including but not limited to the date of first commercial operation of specified Trains of the SPL Project. We recognize our Physical Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Physical Liquefaction Supply Derivatives are reported in earnings. As of June 30, 2016, SPL has secured up to approximately

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

2,027.5 millionMMBtu of natural gas feedstock through natural gas purchase agreements. The notional natural gas position of our Physical Liquefaction Supply Derivatives was approximately 1,114.5 millionMMBtu as of June 30, 2016.

Our Financial Liquefaction Supply Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our Financial Liquefaction Supply Derivatives activities.

LNG Trading Derivatives

As of June 30, 2016, we have entered into certain LNG Trading Derivatives representing a short position of 18.2 million MMBtu, and we may from time to time enter into certain financial derivatives in the form of swaps, forwards, options or futures to economically hedge exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG. We have entered into LNG Trading Derivatives to secure a fixed price position to minimize future cash flow variability associated with such LNG transactions.

Natural Gas Derivatives

Our Natural Gas Derivatives were executed through over-the-counter contracts which were subject to nominal credit risk as these transactions settled on a daily margin basis with investment grade financial institutions. We were required by these financial institutions to use margin deposits as credit support for our Natural Gas Derivatives activities. As of June 30, 2016, we did not have any open Natural Gas Derivatives positions or margin deposits at financial institutions.

We recognize all commodity derivative instruments, including our Liquefaction Supply Derivatives, LNG Trading Derivatives and Natural Gas Derivatives(collectively, “Commodity Derivatives”), as either assets or liabilities and measure those instruments at fair value.  Changes in the fair value of our Commodity Derivatives are reported in earnings.

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

	June 30, 2016											December 31, 2015
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Natural Gas Derivatives		Total			Liquefaction Supply Derivatives			LNG Trading Derivatives (2)			Natural Gas Derivatives (3)			Total
Balance Sheet Location
Other current assets	$	2,526		$	232		$	—	$	2,758		$	2,737		$	640		$	—		$	3,377
Non-current derivative assets	20,472			243			—		20,715			30,304			583			—			30,887
Total derivative assets	22,998			475			—		23,473			33,041			1,223			—			34,264
Derivative liabilities	(3,033		)	(10,778		)	—		(13,811		)	(490		)	(107		)	(66		)	(663		)
Non-current derivative liabilities	—			(2,047		)	—		(2,047		)	(84		)	(63		)	—			(147		)
Total derivative liabilities	(3,033		)	(12,825		)	—		(15,858		)	(574		)	(170		)	(66		)	(810		)
Derivative asset (liabilities), net	$	19,965		$	(12,350	)	$	—	$	7,615		$	32,467		$	1,053		$	(66	)	$	33,454

(1) Does not include collateral of $0.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of June 30, 2016.

(2) Does not include collateral of $15.6 million and $11.0 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015, respectively.

(3) Does not include collateral of $5.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table (in thousands) 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 six months ended June 30, 2016 and 2015:

		Three Months Ended June 30,						Six Months Ended June 30,
	Statement of Operations Location	2016			2015			2016			2015
Liquefaction Supply Derivatives loss	LNG revenues (losses)	$	(34	)	$	—		$	(6	)	$	—
Liquefaction Supply Derivatives gain (loss) (1)	Cost of sales	(8,670		)	81			(12,264		)	81
LNG Trading Derivatives loss	LNG revenues (losses)	(16,976		)	—			(12,214		)	—
Natural Gas Derivatives gain (loss)	LNG revenues (losses)	—			67			(5		)	(98		)
Natural Gas Derivatives gain (loss)	Operating and maintenance expense	—			(294		)	174			460

(1)    Does not include the realized value associated with derivative instruments that settle through physical delivery.

The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our Commodity Derivatives are in an asset position.

FX Derivatives

Cheniere Marketing has entered into FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives economically hedge the foreign currency exposure arising from cash flows expended for both physical and financial LNG transactions and general and administrative expenses related to operations in countries outside of the United States. The total notional amount of our FX Derivatives was $102.1 million as of June 30, 2016.

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

		Fair Value Measurements as of
	Balance Sheet Location	June 30, 2016			December 31, 2015
FX Derivatives	Other current assets	$	355		$	—
FX Derivatives	Derivative liabilities	(132		)	—
FX Derivatives	Non-current derivative liabilities	(63		)	—

The following table (in thousands) shows the changes in the fair value of our FX Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2016 and 2015:

		Three Months Ended June 30,					Six Months Ended June 30,
	Statement of Operations Location	2016			2015		2016			2015
FX Derivatives gain	LNG revenues (losses)	$	2,641		$	—	$	40		$	—
FX Derivatives gain	Derivative gain (loss), net	48			—		98			—
FX Derivatives loss	Other income (expense)	(87		)	—		(87		)	—

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(unaudited)

Balance Sheet Presentation

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

	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 June 30, 2016
SPL Interest Rate Derivatives	$	(20,666	)	$	—		$	(20,666	)
CQP Interest Rate Derivatives	(19,148		)	—			(19,148		)
CCH Interest Rate Derivatives	(327,342		)	—			(327,342		)
Liquefaction Supply Derivatives	23,165			(167		)	22,998
Liquefaction Supply Derivatives	(4,505		)	1,472			(3,033		)
LNG Trading Derivatives	475			—			475
LNG Trading Derivatives	(22,455		)	9,630			(12,825		)
FX Derivatives	860			(505		)	355
FX Derivatives	(376		)	181			(195		)
As of December 31, 2015
SPL Interest Rate Derivatives	$	(8,740	)	$	—		$	(8,740	)
CCH Interest Rate Derivatives	(104,999		)	—			(104,999		)
Liquefaction Supply Derivatives	33,636			(595		)	33,041
Liquefaction Supply Derivatives	(574		)	—			(574		)
LNG Trading Derivatives	1,922			(699		)	1,223
LNG Trading Derivatives	(2,826		)	2,656			(170		)
Natural Gas Derivatives	188			(254		)	(66		)

NOTE 7—OTHER NON-CURRENT ASSETS

As of June 30, 2016 and December 31, 2015, other non-current assets consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Advances made under EPC and non-EPC contracts	$	14,000	$	83,579
Advances made to municipalities for water system enhancements	95,584		89,953
Tax-related payments and receivables	29,351		31,712
Equity method investments	11,983		20,295
Other	100,540		88,916
Total other non-current assets	$	251,458	$	314,455

NOTE 8—VARIABLE INTEREST ENTITY

Cheniere Holdings

On January 1, 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This guidance changed (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination.

Cheniere Holdings is a limited liability company formed by us in 2013 to hold our Cheniere Partners limited partner interests. As of June 30, 2016, we owned 80.1% of Cheniere Holdings as well as the director voting share. The director voting share is the sole share entitled to vote in the election of Cheniere Holdings’ board of directors and allows us to remove members of the board of directors at any time and for any reason. If we cease to own greater than 25% of the common shares of Cheniere Holdings or if we choose to relinquish the director voting share, the director voting share will be extinguished.

The board of directors makes all major operating and financial decisions on behalf of Cheniere Holdings. Because ownership of the director voting share allows us to control Cheniere Holdings, irrespective of our majority ownership interest, and the director voting share cannot be removed from our control by the other equity holders of Cheniere Holdings, we have determined that

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Holdings is now a variable interest entity. However, this determination has not changed the consolidation of Cheniere Holdings as we have determined that we are its primary beneficiary. Therefore, the determination that Cheniere Holdings is now a variable interest entity had no impact on our Consolidated Financial Statements.

NOTE 9—NON-CONTROLLING INTEREST

As of both June 30, 2016 and December 31, 2015, we owned 80.1% of Cheniere Holdings as well as the director voting share, with the remaining non-controlling interest held by the public. Cheniere Holdings owns a 55.9% limited partner interest in Cheniere Partners in the form of 12.0 million common units, 45.3 million Class B 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.

NOTE 10—ACCRUED LIABILITIES

As of June 30, 2016 and December 31, 2015, accrued liabilities consisted of the following (in thousands): 

	June 30,		December 31,
	2016		2015
Interest costs and related debt fees	$	173,907	$	159,968
Compensation and benefits	69,975		99,511
SPL Project and CCL Project costs	326,788		145,759
LNG terminal costs	4,795		3,918
Other accrued liabilities	14,139		18,043
Total accrued liabilities	$	589,604	$	427,199

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(unaudited)

NOTE 11—DEBT

As of June 30, 2016 and December 31, 2015, our debt consisted of the following (in thousands): 

	June 30,			December 31,
	2016			2015
Long-term debt:
SPLNG
6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) (1)	$	420,000		$	420,000
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7,959 and $8,718	2,007,959			2,008,718
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000,000			1,000,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $6,029 and $6,392	1,506,029			1,506,392
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000,000			2,000,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000,000			2,000,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500,000			—
2015 SPL Credit Facilities	832,695			845,000
CTPL
$400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429	—			398,571
Cheniere Partners
2016 CQP Credit Facilities	450,000			—
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250,000			—
2015 CCH Credit Facility	2,730,340			2,713,000
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,109,165			1,050,588
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”), net of unamortized discount of $158,036 and $174,095	921,690			879,938
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”), net of unamortized discount of $317,994 and $319,062	307,006			305,938
Unamortized debt issuance costs (2)	(245,810		)	(207,718		)
Total long-term debt, net	17,789,074			14,920,427
Current debt:
7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of $1,956 and $4,303 (3)	1,663,544			1,661,197
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			15,000
Cheniere Marketing trade finance facilities	15,219			—
Unamortized debt issuance costs (2)	(1,287		)	(2,818		)
Total current debt, net	1,677,476			1,673,379
Total debt, net	$	19,466,550		$	16,593,806

(1) Must be redeemed or repaid concurrently with the 2016 SPLNG Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 SPLNG Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities.

(2) Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $207.8 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.

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(unaudited)

(3) Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities.

2016 Debt Issuances and Redemptions

2026 SPL Senior Notes

In June 2016, SPL issued an aggregate principal amount of $1.5 billion of the 2026 SPL Senior Notes. Net proceeds of the offering of approximately $1.3 billion, after deducting commissions, fees and expenses and incremental interest required under the 2026 SPL Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $26.0 million during both the three and six months ended June 30, 2016. The 2026 SPL Senior Notes accrue interest at a fixed rate of 5.875% and interest on the 2026 SPL Senior Notes is payable semi-annually in arrears. The terms of the 2026 SPL Senior Notes are governed by the same common indenture as SPL’s other senior notes, which contains customary terms and events of default, covenants and redemption terms.

In connection with the closing of the sale of the 2026 SPL Senior Notes, SPL entered into a Registration Rights Agreement dated June 14, 2016 (the “2026 SPL Registration Rights Agreement”). Under the terms of the 2026 SPL Registration Rights Agreement, SPL has agreed, and any future guarantors of the 2026 SPL Senior Notes will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement within 360 days after June 14, 2016 with respect to an offer to exchange any and all of the 2026 SPL Senior Notes for a like aggregate principal amount of debt securities of SPL with terms identical in all material respects to the respective 2026 SPL Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), and that are registered under the Securities Act of 1933, as amended (the “Securities Act”). Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2026 SPL Senior Notes. SPL will be obligated to pay additional interest if it fails to comply with its obligation to register the 2026 SPL Senior Notes within the specified time period.

2024 CCH Senior Notes

In May 2016, CCH issued an aggregate principal amount of $1.25 billion of the 2024 CCH Senior Notes, which are jointly and severally guaranteed by its subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (“CCP GP”, and collectively with CCL and CCP, the “Guarantors”). Net proceeds of the offering of approximately $1.1 billion, after deducting commissions, fees and expenses and incremental interest required under the 2024 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 CCH Credit Facility, resulting in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $29.0 million during both the three and six months ended June 30, 2016. Borrowings under the 2024 CCH Senior Notes accrue interest at a fixed rate of 7.000%, and interest on the 2024 CCH Senior Notes is payable semi-annually in arrears.

The indenture governing the 2024 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 Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.

At any time prior to January 1, 2024, CCH may redeem all or a part of the 2024 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 on or after January 1, 2024 through the maturity date of June 30, 2024, redeem the 2024 CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2024 CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

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(unaudited)

In connection with the closing of the sale of the 2024 CCH Senior Notes, CCH and the Guarantors entered into a Registration Rights Agreement dated May 18, 2016 (the “CCH Registration Rights Agreement”). Under the terms of the CCH Registration Rights Agreement, CCH and the Guarantors have agreed, and any future guarantors of the 2024 CCH Senior Notes will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement within 360 days after May 18, 2016 with respect to an offer to exchange any and all of the 2024 CCH Senior Notes for a like aggregate principal amount of debt securities of CCH with terms identical in all material respects to the respective 2024 CCH Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), and that are registered under the Securities Act. Under specified circumstances, CCH and the Guarantors have also agreed, and any future guarantors of the 2024 CCH Senior Notes will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2024 CCH Senior Notes. CCH will be obligated to pay additional interest if it fails to comply with its obligation to register the 2024 CCH Senior Notes within the specified time period.

2016 CQP Credit Facilities

In February 2016, Cheniere Partners entered into the $2.8 billion2016 CQP Credit Facilities, which consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 millionCTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes.

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

Cheniere Partners incurred $48.7 million of debt issuance costs during the six months ended June 30, 2016, and will incur an additional $21.5 million of debt issuance costs when the SPLNG tranche is funded. The prepayment of the CTPL Term Loan resulted in a write-off of unamortized discount and debt issuance costs of $1.5 million during the six months ended June 30, 2016. Cheniere Partners pays a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the 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 2016 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 terms of the 2016 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 2016 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than: (1) SPL, (2) SPLNG until funding of its tranche term loan and (3) certain of the 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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(unaudited)

Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2016 (in thousands):

	2015 SPL Credit Facilities		SPL Working Capital Facility		2016 CQP Credit Facilities		2015 CCH Term Loan Facilities
Original facility size	$	4,600,000	$	1,200,000	$	2,800,000	$	8,403,714
Outstanding balance	832,695		—		450,000		2,730,340
Commitments terminated	1,287,305		—		—		1,050,660
Letters of credit issued	—		237,270		7,500		—
Available commitment	$	2,480,000	$	962,730	$	2,342,500	$	4,622,714
Interest rate	LIBOR plus 1.30% - 1.75% or base rate plus 1.75%		LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)		LIBOR plus 2.25% or base rate plus 1.25% (2)
Maturity date	Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date		December 31, 2020, with various terms for underlying loans		February 25, 2020, with principals due quarterly commencing on February 19, 2019		Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date

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

(2) There is a 0.25% step-up for both LIBOR and base rate loans following completion of the first two Trains of the CCL Project.

Convertible Notes

Below is a summary of our convertible notes outstanding as of June 30, 2016 (in thousands):

	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000,000		$	1,000,000		$	625,000
Debt component, net of discount	$	921,690		$	1,109,165		$	307,006
Equity component	$	203,892		$	—		$	194,082
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			March 1, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate	9.1		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (8)	4.9 years			4.3 years			28.7 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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(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) 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 into our common stock.

Interest Expense

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Interest cost on convertible notes:
Interest per contractual rate	$	49,853		$	33,603		$	98,893		$	47,542
Amortization of debt discount	9,100			7,116			17,985			13,714
Amortization of debt issuance costs	1,254			601			2,405			615
Total interest cost related to convertible notes	60,207			41,320			119,283			61,871
Interest cost on other debt	255,853			199,911			490,069			359,998
Total interest cost	316,060			241,231			609,352			421,869
Capitalized interest	(210,093		)	(155,745		)	(427,048		)	(276,771		)
Total interest expense, net	$	105,967		$	85,486		$	182,304		$	145,098

Fair Value Disclosures

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

	June 30, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior Notes, net of premium or discount (1)	$	13,347,532	$	13,447,629	$	10,596,307	$	9,525,809
CTPL Term Loan, net of discount (2)	—		—		398,571		400,000
Credit facilities (2) (3)	4,028,254		4,028,254		3,573,000		3,573,000
2021 Cheniere Convertible Unsecured Notes, net of discount (4)	921,690		918,414		879,938		825,413
2025 CCH HoldCo II Convertible Senior Notes (4)	1,109,165		1,153,534		1,050,588		914,363
2045 Cheniere Convertible Senior Notes, net of discount (5)	307,006		356,250		305,938		331,919

(1) Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes; 2025 SPL Senior Notes; 2026 SPL Senior Notes; and 2024 CCH Senior Notes(collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the Senior Notes and other similar instruments.

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(2) 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. 

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility, 2016 CQP Credit Facilities, 2015 CCH Credit Facility and Cheniere Marketing trade finance facilities.

(4) 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. 

(5) 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 12—INCOME TAXES

We are not presently a taxpayer for federal or state income tax purposes and have not recorded a provision for federal or state income taxes in any of the periods included in the accompanying Consolidated Financial Statements. However, we are presently a foreign taxpayer and have recorded a net benefit (provision) of $0.3 million and $0.5 million for the three months ended June 30, 2016 and 2015, respectively, and $(0.3) million and $(0.2) million for the six months ended June 30, 2016 and 2015, respectively, for foreign income taxes.

We experienced an ownership change within the provisions of Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of our net operating losses (“NOLs”) was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of our NOLs in full over the carryover period. We will continue to monitor trading activity in our shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize our existing tax NOL carryforwards.

NOTE 13—SHARE-BASED COMPENSATION

We have granted stock, restricted stock, phantom units and options to purchase common stock to employees, outside directors and a consultant under the Amended and Restated 2003 Stock Incentive Plan, as amended (the “2003 Plan”), 2011 Incentive Plan, as amended (the “2011 Plan”), the 2015 Long-Term Cash Incentive Plan (the “2015 Plan”) and the 2015 Employee Inducement Incentive Plan (the “Inducement Plan”).

The 2003 Plan and 2011 Plan provide for the issuance of 21.0 million shares and 35.0 million shares, respectively, of our common stock that may be in the form of non-qualified stock options, incentive stock options, purchased stock, restricted (non-vested) stock, bonus (unrestricted) stock, stock appreciation rights, phantom units and other share-based performance awards deemed by the Compensation Committee of our Board of Directors (the “Compensation Committee”) to be consistent with the purposes of the 2003 Plan and 2011 Plan. As of June 30, 2016, all of the shares under the 2003 Plan have been granted and 26.8 million shares, net of cancellations, have been granted under the 2011 Plan. The 2015 Plan generally provides for cash-settled awards in the form of stock appreciation rights, phantom unit awards, performance unit awards, other-stock based awards and cash awards. As of June 30, 2016, 6.1 million phantom units have been granted under the 2015 Plan. The Inducement Plan provides for the issuance of up to 1.0 million shares of our common stock in the form of non-qualified stock options, restricted stock awards, stock appreciation rights, performance awards, phantom stock awards and other stock-based awards deemed by the Compensation Committee to provide us with an opportunity to attract employees. As of June 30, 2016, 0.2 million shares of restricted stock have been granted under the Inducement Plan.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Total share-based compensation	$	40,535		$	68,665		$	58,060		$	86,655
Capitalized share-based compensation	(4,982		)	(18,427		)	(6,336		)	(20,277		)
Total share-based compensation expense	$	35,553		$	50,238		$	51,724		$	66,378

Total share-based compensation expense for the three and six months ended June 30, 2016 includes $15.6 million and $22.1 million, respectively, related to employee separations. The total unrecognized compensation cost at June 30, 2016 relating to non-

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(unaudited)

vested share-based compensation arrangements was $154.5 million, which is expected to be recognized over a weighted average period of 1.8 years.

We did not receive any proceeds from the exercise of stock options in the three and six months ended June 30, 2016 and received $0.9 million and $1.9 million in the three and six months ended June 30, 2015, respectively.

NOTE 14—NET LOSS PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

Basic net 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 following table (in thousands, except for loss per share) reconciles basic and diluted weighted average common shares outstanding for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Weighted average common shares outstanding:
Basic	228,323			226,481			228,231			226,405
Dilutive common stock options and unvested stock (1)	—			—			—			—
Diluted	228,323			226,481			228,231			226,405
Basic and diluted net loss per share attributable to common stockholders	$	(1.31	)	$	(0.52	)	$	(2.71	)	$	(1.71	)

(1) Stock options and unvested stock of 7.1 million shares for each of the three and six months ended June 30, 2016 and 10.1 million shares for each of the three and six months ended June 30, 2015, representing securities that could potentially dilute basic EPS in the future, were not included in the diluted net loss per share computations because their effect would have been anti-dilutive. In addition, 16.0 million shares in aggregate for the three and six months ended June 30, 2016 and 15.5 million shares in aggregate for the three and six months ended June 30, 2015, issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes, were not included in the computation of diluted net loss per share because the computation of diluted net loss per share utilizing the “if-converted” method would be anti-dilutive. There were no shares included in the computation of diluted net loss per share for the 2025 CCH HoldCo II Convertible Senior Notes because non-market-based contingencies underlying the eligible conversion date have not been met as of June 30, 2016.

NOTE 15—COMMITMENTS AND CONTINGENCIES

Cheniere has 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 June 30, 2016, are not recognized as liabilities.

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

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(unaudited)

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 Suit”). CLNGT asserted claims in the Texas 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 Suit moved to dismiss the suit for lack of subject matter jurisdiction. CLNGT has responded to that motion, and it remains pending before the court.

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 seeks $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, where it is pending as Civil Action No. 2:16-cv-03209-CJB-SS. On April 22, 2016, we and CLNGT filed a motion in the Louisiana Suit seeking (1) dismissal of all claims against us for lack of personal jurisdiction, (2) dismissal, stay, or transfer of the suit to the United States District Court for the Southern District of Texas in deference to the first-filed Texas Suit, and (3) alternatively, transfer of the suit for convenience of the parties and witnesses. On May 4, 2016, Parallax Enterprises filed a motion to remand the Louisiana Suit to state court. On June 6, 2016, the court granted our request to transfer the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was then transferred to the same judge before which the Texas Suit is pending.  Parallax Enterprises’ motion to remand the Louisiana Suit to Louisiana state court and our motion to dismiss the Louisiana Suit in deference to the first-filed Texas Suit remain pending. We do not expect that the resolution of this litigation will have a material adverse impact on our financial results.

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 June 30, 2016 and December 31, 2015, there were no liabilities recognized under these guarantee arrangements.

NOTE 16—BUSINESS SEGMENT INFORMATION

We have two reportable segments: LNG terminal segment and LNG and natural gas marketing segment. We determine our reportable segments by identifying each segment that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the entities’ chief operating decision maker for purposes of resource allocation and performance assessment, and had discrete financial information. Revenues from external customers that were derived from customers outside of the United States were $28.7 million and $31.4 million for the three and six months ended June 30, 2016, respectively. We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

Our LNG terminal segment consists of the Sabine Pass and Corpus Christi LNG terminals. We own and operate the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast through our ownership interest in and management agreements with Cheniere Partners. We own 100% of the general partner interest in Cheniere Partners and 80.1% of the common shares of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners. We are also developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal near Corpus Christi, Texas.

Our LNG and natural gas marketing segment consists of LNG and natural gas marketing activities by Cheniere Marketing. Cheniere Marketing is developing a platform for LNG sales to international markets with professional staff based in the United States, United Kingdom, Singapore and Chile.

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(unaudited)

The following table (in thousands) summarizes revenues (losses) and income (loss) from operations for each of our reporting segments: 

	Segments
	LNG Terminal			LNG & Natural Gas Marketing			Corporate and Other (1)			Total Consolidation
Three Months Ended June 30, 2016
Revenues (losses) from external customers	$	150,977		$	43,969		$	(18,119	)	$	176,827
Intersegment revenues (losses) (2)	6			7,029			(7,035		)	—
Depreciation and amortization expense	26,711			306			5,764			32,781
Income (loss) from operations	10,115			(31,917		)	(54,652		)	(76,454		)
Interest expense, net of capitalized interest	(80,127		)	—			(25,840		)	(105,967		)
Loss before income taxes and non-controlling interest (3)	(210,561		)	(31,870		)	(92,856		)	(335,287		)
Share-based compensation	7,045			10,257			23,233			40,535
Expenditures for additions to long-lived assets	1,089,190			1,296			3,206			1,093,692
Three Months Ended June 30, 2015
Revenues (losses) from external customers	$	68,532		$	(706	)	$	199		$	68,025
Intersegment revenues (losses) (2)	491			6,354			(6,845		)	—
Depreciation and amortization expense	16,071			244			3,839			20,154
Loss from operations	(18,061		)	(26,367		)	(51,446		)	(95,874		)
Interest expense, net of capitalized interest	(59,465		)	—			(26,021		)	(85,486		)
Loss before income taxes and non-controlling interest (3)	(33,403		)	(26,816		)	(82,090		)	(142,309		)
Share-based compensation	25,778			6,052			36,835			68,665
Expenditures for additions to long-lived assets	3,944,191			1,400			20,874			3,966,465
Six Months Ended June 30, 2016
Revenues (losses) from external customers	$	216,528		$	46,673		$	(17,293	)	$	245,908
Intersegment revenues (losses) (2)	924			14,623			(15,547		)	—
Depreciation and amortization expense	44,684			621			11,565			56,870
Loss from operations	(2,434		)	(62,464		)	(102,115		)	(167,013		)
Interest expense, net of capitalized interest	(131,493		)	—			(50,811		)	(182,304		)
Loss before income taxes and non-controlling interest (3)	(451,532		)	(62,550		)	(169,563		)	(683,645		)
Share-based compensation	9,822			15,146			33,092			58,060
Expenditures for additions to long-lived assets	2,590,568			1,531			9,652			2,601,751
Six Months Ended June 30, 2015
Revenues (losses) from external customers	$	136,112		$	(44	)	$	326		$	136,394
Intersegment revenues (losses) (2)	594			13,371			(13,965		)	—
Depreciation and amortization expense	31,012			444			6,467			37,923
Loss from operations	(42,396		)	(31,550		)	(82,172		)	(156,118		)
Interest expense, net of capitalized interest	(102,310		)	—			(42,788		)	(145,098		)
Loss before income taxes and non-controlling interest (3)	(311,058		)	(32,206		)	(134,211		)	(477,475		)
Share-based compensation	28,917			10,087			47,651			86,655
Expenditures for additions to long-lived assets	4,534,436			2,114			49,655			4,586,205

(1) Includes corporate activities, business development, strategic activities and certain intercompany eliminations. These activities have been included in the corporate and other column.

(2) Intersegment revenues (losses) related to our LNG and natural gas marketing segment are primarily a result of international revenue allocations using a cost plus transfer pricing methodology. These LNG and natural gas marketing segment intersegment revenues (losses) are eliminated with intersegment revenues (losses) in our Consolidated Statements of Operations.

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(unaudited)

(3) Items to reconcile loss from operations and loss before income taxes and non-controlling interest include consolidated other income (expense) amounts as presented on our Consolidated Statements of Operations primarily related to our LNG terminal segment.

The following table (in thousands) shows total assets for each of our reporting segments: 

	June 30,		December 31,
	2016		2015
LNG Terminal	$	20,130,382	$	17,363,750
LNG & Natural Gas Marketing	540,454		550,896
Corporate and Other	766,015		894,407
Total Consolidation	$	21,436,851	$	18,809,053

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended June 30,
	2016		2015
Cash paid during the period for interest, net of amounts capitalized	$	59,260	$	46,165

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $472.4 million and $383.7 million as of June 30, 2016 and 2015, respectively.

NOTE 18—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by the Company as of June 30, 2016:

Standard	Description	Expected 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 amends 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. This guidance may be early adopted beginning January 1, 2017, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	This standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted.	December 31, 2016	The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a 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 must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	This standard primarily requires the recognition of excess tax benefits for share-based awards in the statement of operations and the classification of excess tax benefits as an operating activity within the statement of cash flows. The guidance also allows an entity to elect to account for forfeitures when they occur. This guidance may be early adopted, but all of the guidance must be adopted in the same period.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	These amendments primarily affect asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2016	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	These standards require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 11—Debt for additional disclosures.
ASU 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement	This standard clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. This guidance may be early adopted, and may be adopted as either retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date.	January 1, 2016	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 facts, 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 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 ability to enter into such transactions;

• statements relating to the construction of our Trains and pipeline, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;

• statements regarding any SPA or any other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;

• statements regarding counterparties to our commercial contracts, construction contracts and other contracts;

• statements regarding our planned development and construction of additional Trains 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 and capital expenditures, any or all of which are subject to change;

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

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

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

All of these types of statements, other than statements of historical fact, 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 due to factors described in this quarterly report and in the other reports and other information that we file with the SEC. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed under “Risk Factors” in our annual report on Form 10-K for the year ended December 31,

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2015. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

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. 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. We own 100% of the general partner interest in Cheniere Partners and 80.1% of Cheniere Holdings, which is a publicly traded limited liability company formed in 2013 that owns a 55.9% limited partner interest in Cheniere Partners. 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. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two marine berths that can 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 is developing and constructing 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 and construction. Train 1 has commenced commercial operations, Train 2 is undergoing commissioning, Trains 3 through 5 are under construction and Train 6 is fully permitted. Each Train is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. 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, which is on nearly 2,000 acres of land that we own or control 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 up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two marine berths that can 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, 48-inch natural gas supply pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”).

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Corpus Christi Liquefaction Stage III, LLC and Cheniere Corpus Christi Pipeline Stage III, LLC (the “CCL Stage III entities”), our wholly owned subsidiaries separate from the CCH Group, are also developing two additional Trains and one LNG storage tank at the Corpus Christi LNG terminal adjacent to the CCL Project, along with a second natural gas pipeline.

Cheniere Marketing is engaged in the LNG and natural gas marketing business and is developing a portfolio of long-term, short-term and spot SPAs. Cheniere Marketing has entered into SPAs with SPL and CCL to purchase, at Cheniere Marketing’s option, LNG produced by the SPL Project and the CCL Project.

We are also in various stages of developing other projects which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision (“FID”).

Overview of Significant Events

Our significant accomplishments since January 1, 2016 and through the filing date of this Form 10-Q include the following:  

• In February 2016, Cheniere Partners entered into a Credit and Guaranty Agreement for the incurrence of debt of up to an aggregate amount of approximately $2.8 billion (the “2016 CQP Credit Facilities”). The 2016 CQP Credit Facilities consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 million term loan facility (the “CTPL Term Loan”) in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 7.50% Senior Secured Notes due 2016 issued by SPLNG (the “2016 SPLNG Senior Notes”) and the 6.50% Senior Secured Notes due 2020 issued by SPLNG (the “2020 SPLNG Senior Notes” and collectively with the 2016 SPLNG Senior Notes, the “SPLNG Senior Notes”) (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities ), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes.

• In February 2016, SPL commenced production and shipment of LNG commissioning cargoes from Train 1 of the SPL Project.

• In May 2016, our Board of Directors appointed Jack Fusco as our President and Chief Executive Officer, effective as of May 12, 2016.

• In May 2016, CCH issued an aggregate principal amount of $1.25 billion of 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”). Net proceeds of the offering of approximately $1.1 billion, after deducting commissions, fees and expenses and incremental interest required under the 2024 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under its credit facility (the “2015 CCH Credit Facility”).

• In May 2016, Train 1 of the SPL Project achieved substantial completion and initiated operating activities.

• In June 2016, SPL issued an aggregate principal amount of $1.5 billion of 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”). Net proceeds of the offering of approximately $1.3 billion, after deducting commissions, fees and expenses and incremental interest required under the 2026 SPL Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the credit facilities it entered into in June 2015 (the “2015 SPL Credit Facilities”).

Liquidity and Capital Resources

Although results are consolidated for financial reporting, Cheniere, Cheniere Holdings, Cheniere Partners, SPL, SPLNG 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:

•SPLNG through operating cash flows, existing unrestricted cash and debt offerings or equity contributions;

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

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

•Cheniere Holdings through distributions from Cheniere Partners;

•CCH Group through project financing and equity contributions from Cheniere; and

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

As of June 30, 2016, we had cash and cash equivalents of $1,049.5 million available to Cheniere. In addition, we had current and non-current restricted cash of $756.2 million (which included current and non-current restricted cash available to us and our subsidiaries) designated for the following purposes: $223.1 million for the CCL Project; $263.1 million for the SPL Project; $110.0 million due to restrictions under the 2016 CQP Credit Facilities; $91.1 million for interest payments related to the SPLNG Senior Notes; and $68.9 million for other restricted purposes.

In November 2014, we issued an aggregate principal amount of $1.0 billion 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. The initial conversion price was $93.64 and is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.

In March 2015, we issued the $625.0 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. 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. The conversion rate is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.

Cheniere Holdings

Cheniere Holdings was formed by us to hold our Cheniere Partners limited partner interests, thereby allowing us to segregate our lower risk, stable, cash flow generating assets from our higher risk, early stage development projects and marketing activities. As of June 30, 2016, we had an 80.1% direct ownership interest in Cheniere Holdings. We receive dividends on our Cheniere Holdings shares from the distributions that Cheniere Holdings receives from Cheniere Partners, and we receive management fees for managing Cheniere Holdings. We received $7.4 million and $7.2 million in dividends on our Cheniere Holdings common shares during the six months ended June 30, 2016 and 2015, respectively, and $0.5 million of management fees from Cheniere Holdings during each of the six months ended June 30, 2016 and 2015.

Cheniere Partners

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of June 30, 2016, we own 80.1% of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners in the form of 11,963,488 common units, 45,333,334 Class B units and 135,383,831 subordinated units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.

Prior to the initial public offering by Cheniere Holdings, we received quarterly equity distributions from Cheniere Partners related to our limited partner and 2% general partner interests. We will continue to receive quarterly equity distributions from Cheniere Partners related to our 2% general partner interest, and we receive fees for providing services to Cheniere Partners, SPLNG, SPL and CTPL. We received $1.0 million in distributions on our general partner interest during each of the six months ended June 30, 2016 and 2015, and we received $80.8 million and $32.9 million in total service fees from Cheniere Partners, SPLNG, SPL and CTPL, during the six months ended June 30, 2016 and 2015, respectively.

Cheniere Partners’ common unit and general partner distributions are being funded from accumulated operating surplus. We have not received distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010. Cheniere Partners will not make distributions on our subordinated units until it generates additional cash flow from SPLNG, SPL, CTPL or other new business, which would be used to make quarterly distributions on our subordinated units before any increase in distributions to the common unitholders.

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Cheniere Partners’ Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Cheniere Partners Class B units are not entitled to cash distributions except in the event of a liquidation of Cheniere Partners, a merger, consolidation or other combination of Cheniere Partners with another person or the sale of all or substantially all of the assets of Cheniere Partners. On a quarterly basis beginning on the initial purchase date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco LP was 1.74 and 1.71, respectively, as of June 30, 2016. We expect the Class B units to mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the SPL Project, which Cheniere Partners currently expects to occur before June 30, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

LNG Terminal Business

Sabine Pass LNG Terminal

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 20 years after SPL delivers its first commercial cargo at the SPL Project. SPL entered into a partial TUA assignment agreement with Total, whereby SPL will progressively gain access to Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement will provide SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Trains 5 and 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3 and permit SPL to more flexibly manage its LNG storage capacity with the commencement of Train 1. 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.

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

Liquefaction Facilities

The SPL Project is being developed and constructed 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 commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In June 2015, we commenced construction of Train 5 and the related facilities.

The DOE has authorized the export of domestically produced LNG by vessel from Trains 1 through 4 of the Sabine Pass LNG terminal to FTA countries for a 30-year term and to non-FTA countries for a 20-year term, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas). The DOE further issued orders authorizing SPL to export domestically produced LNG by vessel from Trains 1 through 4 of the Sabine Pass LNG terminal to 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. Additionally, the DOE issued orders authorizing us to export domestically produced LNG by vessel from Trains 5 and 6 of the Sabine Pass LNG terminal to FTA countries and non-FTA countries for a 20-year term, in an amount up to a combined total of 503.3 Bcf/yr (approximately 10 mtpa) of natural gas. A party to the proceedings requested rehearings of the orders above related to the export of 803 Bcf/yr, 203 Bcf/yr and 503.3 Bcf/yr to non-FTA countries. The DOE issued orders

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denying rehearing of the orders related to 803 Bcf/yr and 503.3 Bcf/yr but has not yet issued a final ruling on the rehearing request related to the 203 Bcf/yr. 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, we have a 3-year makeup period with respect to each of the non-FTA orders for LNG volumes we were unable to export during the initial 20-year export period of such order. Furthermore, in January 2016, the DOE issued an order authorizing us 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 on January 15, 2016, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports to non-FTA countries under this order, when combined with exports to non-FTA countries under the orders related to Trains 1 through 4 above, may not exceed 1,006 Bcf/yr).

As of June 30, 2016, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the SPL Project were approximately 99.4% and 87.4%, respectively.  As of June 30, 2016, the overall project completion percentage for Train 5 of the SPL Project was approximately 38.3% with engineering, procurement, subcontract work and construction approximately 77.0%, 58.0%, 37.8% and 2.0% complete, respectively.  As of June 30, 2016, the overall project completion of each of our Trains was ahead of the contractual schedule.  We produced our first LNG from Train 1 of the SPL Project in February 2016 and achieved substantial completion in May 2016. We produced our first LNG from Train 2 of the SPL Project in late July 2016.  Based on our current construction schedule, we anticipate that Train 2 will achieve substantial completion in late September 2016, Trains 3 and 4 are expected to achieve substantial completion in 2017 and Train 5 is expected to achieve substantial completion in 2019.

Customers

SPL has entered into six fixed price, 20-year SPAs with third parties to make available an aggregate amount of LNG that equates to approximately 19.75 mtpa of LNG, which is approximately 88% of the expected aggregate nominal production capacity of Trains 1 through 5. The obligation to make LNG available under the SPAs commences from the date of first commercial delivery for Trains 1 through 5, as specified in each SPA. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee (a portion of which is subject to annual adjustment for inflation) per MMBtu of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. 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. 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 commences upon the start of operations of a specified Train.

In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion annually for Trains 1 through 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.

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 volatility in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas purchase agreements with third parties in order to secure natural gas feedstock for the SPL Project. As of June 30, 2016, SPL has secured up to approximately 2,027.5 million MMBtu of natural gas feedstock through long-term natural gas purchase agreements.

Construction

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 5, 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.

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The total contract prices of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC Contract for Train 5 of the SPL Project are approximately $4.1 billion, $3.8 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through June 30, 2016. 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 $17.0 billion and $18.0 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 the Train.

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 one or more of the following: borrowings, equity contributions from Cheniere Partners and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the 2015 SPL Credit Facilities, available commitments under the SPL Working Capital Facility (as defined below) and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 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. Additionally, during the three and six months ended June 30, 2016, we realized offsets to LNG terminal costs of $131.8 million and $146.0 million, respectively, that were related to the sale of commissioning cargoes because these amounts were earned prior to the start of commercial operations, during the testing phase for the construction of Train 1 of the SPL Project.

Senior Secured Notes

As of June 30, 2016, Cheniere Partners’ subsidiaries had eight series of senior secured notes outstanding:

• $1.7 billion of 2016 SPLNG Senior Notes;

• $0.4 billion of 2020 SPLNG Senior Notes;

• $2.0 billion of 5.625% Senior Secured Notes due 2021 issued by SPL (the “2021 SPL Senior Notes”);

• $1.0 billion of 6.25% Senior Secured Notes due 2022 issued by SPL (the “2022 SPL Senior Notes”);

• $1.5 billion of 5.625% Senior Secured Notes due 2023 issued by SPL (the “2023 SPL Senior Notes”);

• $2.0 billion of 5.75% Senior Secured Notes due 2024 issued by SPL (the “2024 SPL Senior Notes”);

• $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes” and collectively with the 2021 SPL Senior Notes, the 2022 SPL Senior Notes, the 2023 SPL Senior Notes, the 2024 SPL Senior Notes and the 2026 SPL Senior Notes, the “SPL Senior Notes”); and

• $1.5 billion of 2026 SPL Senior Notes.

Interest on the SPL Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the SPLNG Senior Notes are secured on a pari passu first-priority basis by a security interest in all of SPLNG’s equity interests and substantially all of SPLNG’s operating assets. The SPL Senior Notes are secured on a first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets.

SPLNG may redeem all or part of its 2016 SPLNG Senior Notes at any time at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:

•1.0% of the principal amount of the 2016 SPLNG Senior Notes; or

• the excess of: (1) the present value at such redemption date of (a) the redemption price of the 2016 SPLNG Senior Notes plus (b) all required interest payments due on the 2016 SPLNG Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis points; over (2) the principal amount of the 2016 SPLNG Senior Notes, if greater.

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SPLNG may redeem all or part of the 2020 SPLNG Senior Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPLNG may also, at its option, redeem all or part of the 2020 SPLNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes, SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price set forth in the common indenture governing the SPL Senior Notes(the “SPL Indenture”), 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, 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.

Under the indentures governing the SPLNG Senior Notes(the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a fixed charge coverage ratio test of 2:1 is satisfied. Under the SPL Indenture, SPL may not make any distributions until, among other requirements, substantial completion of Trains 1 and 2 of the SPL Project has occurred, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. During the six months ended June 30, 2016 and 2015, SPLNG made distributions of $145.3 million and $199.6 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

The SPL Indenture includes 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, the 2015 SPL Credit Facilities and the SPL Working Capital Facility.

2015 SPL Credit Facilities

In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion. The 2015 SPL Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the SPL Project. Borrowings under the 2015 SPL Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. In June 2016, in conjunction with the issuance of the 2026 SPL Senior Notes, SPL prepaid approximately $1.3 billion of outstanding borrowings under the 2015 SPL Credit Facilities. This prepayment resulted in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $26.0 million during both the three and six months ended June 30, 2016. As of June 30, 2016, SPL had $2.5 billion of available commitments and $0.8 billion of outstanding borrowings under the 2015 SPL Credit Facilities.

Loans under the 2015 SPL Credit Facilities accrue interest at a variable rate per annum equal to, at SPL’s election, LIBOR or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.30% to 1.75%, depending on the applicable 2015 SPL Credit Facility, and the applicable margin for base rate loans is 1.75%. Interest on LIBOR loans is due and payable at the end of each LIBOR period and interest on base rate loans is due and payable at the end of each quarter. In addition, SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 SPL Credit Facilities. The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee calculated at a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility. The principal of the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the SPL Project. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2015 SPL Credit Facilities.

The 2015 SPL Credit Facilities contain conditions precedent for borrowings, as well as customary affirmative and negative covenants. The obligations of SPL under the 2015 SPL Credit Facilities 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 and SPL Working Capital Facility.

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Under the terms of the 2015 SPL Credit Facilities, SPL is required to hedge not less than 65% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. Additionally, SPL may not make any distributions until substantial completion of Trains 1 and 2 of the SPL Project has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is satisfied.

2013 SPL Credit Facilities

 In May 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 SPL Credit Facilities”) to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the SPL Project. In June 2015, the 2013 SPL Credit Facilities were replaced with the 2015 SPL Credit Facilities.

In March 2015, in conjunction with SPL’s issuance of the 2025 SPL Senior Notes, SPL terminated approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities. This termination and the replacement of the 2013 SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015 resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 SPL Credit Facilities of $7.3 million and $96.3 million for the three and six months ended June 30, 2015, respectively.

CTPL Term Loan

In May 2013, CTPL entered into the CTPL Term Loan, which was used to fund modifications to the Creole Trail Pipeline and for general business purposes. In February 2016, CTPL prepaid the full amount of $400.0 million outstanding under the CTPL Term Loan with capital contributions from Cheniere Partners, which in turn was funded with borrowings under the 2016 CQP Credit Facilities. This prepayment resulted in a write-off of unamortized discount and debt issuance costs of $1.5 million during the six months ended June 30, 2016.

2016 CQP Credit Facilities

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities. The 2016 CQP Credit Facilities consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 millionCTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities ), (3) the $125.0 millionDSR Facility that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes. As of June 30, 2016, Cheniere Partners had $2.3 billion of available commitments, $7.5 million aggregate amount of issued letters of credit and $450.0 million of outstanding borrowings under the 2016 CQP Credit Facilities.

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

Cheniere Partners incurred $48.7 million of debt issuance costs during the six months ended June 30, 2016, and will incur an additional $21.5 million of debt issuance costs when the SPLNG tranche is funded. Cheniere Partners pays a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the 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 2016 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 terms of the 2016 CQP Credit Facilities, Cheniere Partners is required to hedge not less than 50% of the

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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 2016 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than: (1) SPL, (2) SPLNG until funding of its tranche term loan and (3) certain of the subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

SPL Working Capital Facility

In September 2015, SPL entered into a $1.2 billion Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “SPL Working Capital Facility”), which replaced the $325.0 million Senior Letter of Credit and Reimbursement Agreement that was entered into in April 2014. The SPL Working Capital Facility is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit, as well as for swing line loans to 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 June 30, 2016, SPL had $962.7 million of available commitments, $237.3 million aggregate amount of issued letters of credit and no loans outstanding under the SPL Working Capital Facility. As of December 31, 2015, SPL had $1.1 billion of available commitments, $135.2 million aggregate amount of issued letters of credit and $15.0 million of loans outstanding under the SPL Working Capital Facility.

The SPL Working Capital Facility accrues interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR loans under the SPL Working Capital Facility is 1.75% per annum, and the applicable margin for base rate loans under the SPL Working Capital Facility is 0.75% per annum. Interest on Swing Line Loans and loans deemed made in connection with a draw upon a letter of credit (“LC Loans”) is due and payable on the date the loan becomes due. Interest on LIBOR Working Capital Loans is due and payable at the end of each applicable LIBOR period, and interest on base rate Working Capital Loans is due and payable at the end of each fiscal quarter. However, if such base rate Working Capital Loan is converted into a LIBOR Working Capital Loan, interest is due and payable on that date. Additionally, if the loans become due prior to such periods, the interest also becomes due on that date.

SPL pays (1) a commitment fee equal to an annual rate of 0.70% on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding Swing Line Loans and (2) a letter of credit fee equal to an annual rate of 1.75% of the undrawn portion of all letters of credit issued under the SPL Working Capital Facility. If draws are made upon a letter of credit issued under the SPL Working Capital Facility and SPL does not elect for such draw (an “LC Draw”) to be deemed an LC Loan, SPL is required to pay the full amount of the LC Draw on or prior to the business day following the notice of the LC Draw. An LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of June 30, 2016, no LC Draws had been made upon any letters of credit issued under the SPL Working Capital Facility.

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. LC Loans have a term of up to one year. 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 Swing Line Loan is made and (3) the first borrowing date for a Working Capital Loan or Swing Line Loan occurring at least three business days following the date the Swing Line Loan is made. SPL is required to reduce the aggregate outstanding principal amount of all 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 and the 2015 SPL Credit Facilities.

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Corpus Christi LNG Terminal

Liquefaction Facilities

The CCL Project is being developed and constructed at the Corpus Christi LNG terminal, on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas. In December 2014, we received authorization from the FERC to site, construct and operate Stages 1 and 2 of the CCL Project. In May 2015, we commenced construction of Stage 1 of the CCL Project.

Through the CCL Stage III entities, which are separate from the CCH Group, we are developing two additional Trains and one LNG storage tank at the Corpus Christi LNG terminal adjacent to the CCL Project, along with a second natural gas pipeline, and we commenced the regulatory approval process in June 2015.

The DOE has authorized the export of domestically produced LNG by vessel from the CCL Project to 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. Additionally, the DOE has authorized the export of domestically produced LNG by vessel from the two additional Trains being developed adjacent to the CCL Project to FTA countries for a 20-year term in an amount equivalent to 514 Bcf/yr (approximately 10 mtpa) of natural gas. The application for authorization to export that same 514 Bcf/yr of domestically produced LNG by vessel to non-FTA countries is currently pending at the DOE. 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 7 to 10 years from the date the order was issued.

As of June 30, 2016, the overall project completion percentage for Stage 1 of the CCL Project was approximately 36.6% with engineering, procurement and construction approximately 98.4%, 50.6% and 8.8% complete, respectively. The construction of the Corpus Christi Pipeline is planned to commence in 2016. Based on our current construction schedule, we anticipate that Trains 1 and 2 of the CCL Project will achieve substantial completion in 2019.

Customers

CCL has entered into seven fixed price, 20-year SPAs with six third parties to make available an aggregate amount of LNG that equates to approximately 7.7 mtpa of LNG, which is approximately 86% of the expected aggregate nominal production capacity of Trains 1 and 2. The obligation to make LNG available under these SPAs commences from the date of first commercial delivery for Trains 1 and 2, as specified in each SPA. In addition, CCL has entered into one fixed price, 20-year SPA with a third party for another 0.8 mtpa of LNG that commences with the date of first commercial delivery for Train 3. Under these eight SPAs, the customers will purchase LNG from CCL for a price consisting of a fixed fee of $3.50 (a portion of which is subject to annual adjustment for inflation) per MMBtu of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. 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. 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 commences upon the start of operations of a specified Train.

In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $1.4 billion annually for Trains 1 and 2, and $1.5 billion if we make a positive FID with respect to Stage 2 of the CCL Project, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $550 million, $846 million and $140 million for each of Trains 1 through 3, respectively.

In addition, Cheniere Marketing has entered into SPAs with CCL to purchase, at Cheniere Marketing’s option, any LNG produced by CCL that is not required for other customers.

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 volatility in natural gas needs for the CCL Project. CCL has also entered into enabling agreements with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. We expect to enter into gas purchase agreements under these enabling agreements as and when required for the CCL Project.

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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 contracts for Stages 1 and 2, which do not include the Corpus Christi Pipeline, are approximately $7.6 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through June 30, 2016. Total expected capital costs for Stages 1 and 2 are estimated to be between $12.0 billion and $13.0 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. Total expected capital costs for Stage 1 only are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $11.0 billion and $12.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Stage 2

We will contemplate making an FID to commence construction of Stage 2 of the CCL Project based upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct the facility.

Capital Resources

We expect to finance the construction costs of the CCL Project from one or more of the following: project financing, operating cash flow from CCL and CCP and equity contributions from Cheniere.

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 $1.0 billion principal of the 2025 CCH HoldCo II Convertible Senior Notes will be used to partially fund costs associated with Stage 1 of the CCL Project and the Corpus Christi Pipeline. The 2025 CCH HoldCo II Convertible Senior Notes bear interest at a rate of 11.0% per annum, which is payable quarterly in arrears. Prior to the substantial completion of Train 2 of the CCL Project, interest on the 2025 CCH HoldCo II Convertible Senior Notes 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. The 2025 CCH HoldCo II Convertible Senior Notes are secured by a pledge by us of 100% of the equity interests in CCH HoldCo II, and a pledge by CCH HoldCo II of 100% of the equity interests in CCH HoldCo I.

At CCH HoldCo II’s option, the outstanding 2025 CCH HoldCo II Convertible Senior Notes are convertible into our common stock, provided that our total market capitalization at that time is not less than $10.0 billion, on or after the later of (1) 58 months from May 1, 2015, and (2) the substantial completion of Train 2 of the CCL Project(the “Eligible Conversion Date”). The conversion price for 2025 CCH HoldCo II Convertible Senior Notes converted at CCH HoldCo II’s option 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 on which notice of conversion is provided, and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date on which notice of conversion is provided. At the option of the holders, the 2025 CCH HoldCo II Convertible Senior Notes are convertible on or after the six-month anniversary of the Eligible Conversion Date at a conversion 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. Conversions are also subject to various limitations and conditions.

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.

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2024 CCH Senior Notes

In May 2016, CCH issued an aggregate principal amount of $1.25 billion of the 2024 CCH Senior Notes. Borrowings under the 2024 CCH Senior Notes accrue interest at a fixed rate of 7.000%, and interest on the 2024 CCH Senior Notes is payable semi-annually in arrears.

The indenture governing the 2024 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 guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.

At any time prior to January 1, 2024, CCH may redeem all or a part of the 2024 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 on or after January 1, 2024 through the maturity date of June 30, 2024, redeem the 2024 CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2024 CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

2015 CCH Credit Facility

In May 2015, CCH entered into the 2015 CCH Credit Facility, which is being used to fund a portion of the costs associated with the development, construction, operation and maintenance of Stage 1 of the CCL Project and the Corpus Christi Pipeline. Borrowings under the 2015 CCH Credit Facility may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. In May 2016, in conjunction with the issuance of the 2024 CCH Senior Notes, CCH prepaid approximately $1.1 billion of outstanding borrowings under the 2015 CCH Credit Facility. This prepayment resulted in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $29.0 million during both the three and six months ended June 30, 2016. As of June 30, 2016, CCH had $4.6 billion of available commitments and $2.7 billion of outstanding borrowings under the 2015 CCH Credit Facility.

The principal of the loans made under the 2015 CCH Credit Facility must be repaid in quarterly installments, commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following project completion and (2) a set date determined by reference to the date under which a certain LNG buyer linked to Train 2 of the CCL Project 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 project completion and designed to achieve a minimum projected fixed debt service coverage ratio of 1.55:1.

Loans under the 2015 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 margins for LIBOR loans are 2.25% prior to completion and 2.50% on completion and thereafter. The applicable margins for base rate loans are 1.25% prior to completion and 1.50% on completion and thereafter. 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. The 2015 CCH Credit Facility also requires CCH to pay a commitment fee at a rate per annum equal to 40% of the margin for LIBOR loans, multiplied by the outstanding undrawn debt commitments.

The obligations of CCH under the 2015 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.

Under the terms of the 2015 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.

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LNG and Natural Gas Marketing Business

Cheniere Marketing is engaged in the LNG and natural gas marketing business and is developing a portfolio of long-term, short-term and spot LNG SPAs. Cheniere Marketing has purchased, transported and unloaded commercial LNG cargoes into the Sabine Pass LNG terminal and other LNG terminals worldwide and has used trading strategies intended to maximize margins on these cargoes. Cheniere Marketing has secured the following rights and obligations to support its business:

• pursuant to an SPA with SPL, the right to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers;

• pursuant to SPAs with CCL, the right to purchase, at Cheniere Marketing’s option, any LNG produced by CCL that is not required for other customers; and

• a portfolio of LNG vessel time charters.

In addition, as of June 30, 2016, Cheniere Marketing has sold approximately 512 million MMBtu of LNG to be delivered to counterparties between 2016 and 2023, with delivery obligations conditional in certain circumstances.  The cargoes have been sold with a portfolio of delivery points, either on a Free on Board basis (delivered to the counterparty at the Sabine Pass LNG terminal) or a Delivered at Terminal (“DAT”) basis (delivered to the counterparty at their LNG receiving terminal). Cheniere Marketing has chartered LNG vessels to be utilized in DAT transactions. In addition, Cheniere Marketing has entered into a long-term agreement to sell LNG cargoes on a DAT basis.  The agreement is conditioned upon the buyer achieving certain milestones, including reaching an FID related to certain projects and obtaining related financing.

Cheniere Marketing entered into uncommitted trade finance facilities for up to $470.0 million primarily for the purchase of natural gas, LNG or other energy products for ultimate resale in the course of its business. The finance facilities are intended to be used for advances, guarantees or the issuance of letters of credit or standby letters of credit on behalf of Cheniere Marketing. As of June 30, 2016, Cheniere Marketing had $15.2 million in loans and $23.2 million in standby letters of credit and guarantees 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 which, among other things, will require acceptable commercial and financing arrangements before we make an FID.

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Sources and Uses of Cash

The following table (in thousands) summarizes the sources and uses of our cash, cash equivalents and restricted cash for the six months ended June 30, 2016 and 2015. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table. 

	Six Months Ended June 30,
	2016			2015
Operating cash flows
Net cash used in operating activities	$	(144,034	)	$	(294,955	)
Changes in restricted cash for certain operating activities	(151,676		)	55,410
Cash, cash equivalents and restricted cash used in operating activities	(295,710		)	(239,545		)
Investing cash flows
Net cash used in investing activities	(19,257		)	(213,030		)
Use of restricted cash for the acquisition of property, plant and equipment	(2,279,835		)	(4,183,620		)
Cash, cash equivalents and restricted cash used in investing activities	(2,299,092		)	(4,396,650		)
Financing cash flows
Net cash provided by financing activities	11,657			230,609
Investment in restricted cash	2,652,576			4,518,880
Cash, cash equivalents and restricted cash provided by financing activities	2,664,233			4,749,489
Net increase in cash, cash equivalents and restricted cash	69,431			113,294
Cash, cash equivalents and restricted cash—beginning of period	1,736,231			2,780,131
Cash, cash equivalents and restricted cash—end of period	$	1,805,662		$	2,893,425

Operating Cash Flows

Operating cash flows during the six months ended June 30, 2016 and 2015 were $295.7 million and $239.5 million, respectively. The increase in operating cash outflows in 2016 compared to 2015 primarily related to increased operating costs and expenses as a result of the commencement of operations of Train 1 of the SPL Project in May 2016 and increased cash payout for phantom unit awards, partially offset by cash receipts from the sale of LNG cargoes.

Investing Cash Flows

Investing cash flows during the six months ended June 30, 2016 and 2015 were $2.3 billion and $4.4 billion, respectively, and are primarily used to fund the construction costs for Trains 1 through 5 of the SPL Project and Trains 1 and 2 of the CCL Project. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, during the six months ended June 30, 2016 and 2015, we used $21.6 million and $101.8 million, respectively, primarily to pay a municipal water district for water system enhancements that will increase potable water supply to the Sabine Pass LNG terminal and for investments made in unconsolidated entities.

Financing Cash Flows

Financing cash flows during the six months ended June 30, 2016 were $2.7 billion, primarily as a result of:

• $450.0 million of borrowings under the 2016 CQP Credit Facilities, which was entered into in February 2016 to prepay the $400.0 million CTPL Term Loan;

• $1.1 billion of borrowings under the 2015 CCH Credit Facility;

• issuance of an aggregate principal amount of $1.3 billion of the 2024 CCH Senior Notes in May 2016, which were used to prepay $1.1 billion of the outstanding borrowings under the 2015 CCH Credit Facility;

• $1.3 billion of borrowings under the 2015 SPL Credit Facilities;

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• issuance of an aggregate principal amount of $1.5 billion of the 2026 SPL Senior Notes in June 2016, which was used to prepay $1.3 billion of the outstanding borrowings under the 2015 SPL Credit Facilities;

• $15.2 million borrowings under the Cheniere Marketing trade finance facilities;

• $140.0 million borrowings, net of $155.0 million repayment, made under the SPL Working Capital Facility;

• $97.2 million of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions; and

• $40.2 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings.

Financing cash flows during the six months ended June 30, 2015 were $4.7 billion, primarily as a result of:

• issuance of an aggregate principal amount of $2.0 billion of the 2025 SPL Senior Notes in March 2015;

• issuance of an aggregate principal amount of $625.0 million of the 2045 Cheniere Convertible Senior Notes in March 2015, with an original issue discount of 20% for net proceeds of $495.7 million;

• issuance of an aggregate principal amount of $1.0 billion of the 2025 CCH HoldCo II Convertible Senior Notes in May 2015;

• entering into the 2015 CCH Credit Facility in May 2015 and borrowed $1.7 billion under this facility during the second quarter of 2015;

• entering into the 2015 SPL Credit Facilities aggregating $4.6 billion in June 2015, which terminated and replaced the 2013 SPL Credit Facilities;

• $411.1 million of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions; and

• $40.1 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings.

Results of Operations

Our consolidated net loss attributable to common stockholders was $298.4 million, or $1.31 per share (basic and diluted), in the three months ended June 30, 2016, compared to a net loss attributable to common stockholders of $118.5 million, or $0.52 per share (basic and diluted) in the three months ended June 30, 2015. This $179.9 million increase in net loss in 2016 was primarily a result of increased derivative loss, net, operating costs and expenses and loss on early extinguishment of debt, which was partially offset by increased LNG revenues.

Our consolidated net loss attributable to common stockholders was $619.3 million, or $2.71 per share (basic and diluted), in the six months ended June 30, 2016, compared to a net loss attributable to common stockholders of $386.2 million, or $1.71 per share (basic and diluted), in the six months ended June 30, 2015. This $233.1 million increase in net loss in 2016 was primarily a result of increased derivative loss, net, operating costs and expenses and interest expense, net of amounts capitalized, which was partially offset by increased LNG revenues and decreased loss on early extinguishment of debt.

Revenues

	Three Months Ended June 30,								Six Months Ended June 30,
(Dollars in thousands)	2016		2015			Change			2016		2015			Change
Regasification revenues	$	65,622	$	66,489		$	(867	)	$	131,173	$	133,291		$	(2,118	)
LNG revenues (losses)	110,735		(706		)	111,441			113,439		(44		)	113,483
Other revenues	470		2,242			(1,772		)	1,296		3,147			(1,851		)
Total revenues	$	176,827	$	68,025		$	108,802		$	245,908	$	136,394		$	109,514

During the three and six months ended June 30, 2016, we began recognizing LNG revenues from the SPL Project following the substantial completion of Train 1 in May 2016. Prior to this date, amounts received from the sale of commissioning cargoes were offset against LNG terminal construction-in-process because these amounts were earned during the testing phase for the construction of Train 1 of the SPL Project. We loaded a total of 38.9 million MMBtu and 53.4 million MMBtu of LNG during the three and six months ended June 30, 2016, respectively, of which 18.2 million MMBtu was loaded after substantial completion

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of Train 1 of the SPL Project in May 2016, resulting in the recognition of revenues related to this volume. Additionally, LNG revenues included revenues from our LNG and natural gas marketing segment of $44.0 million and $46.7 million for the three and six months ended June 30, 2016, respectively, which were net of related commodity and FX derivative losses of $14.4 million and $12.2 million, respectively.

Operating costs and expenses

	Three Months Ended June 30,								Six Months Ended June 30,
(Dollars in thousands)	2016			2015		Change			2016		2015		Change
Cost of sales	$	85,709		$	1,444	$	84,265		$	100,216	$	2,137	$	98,079
Operating and maintenance expense	45,562			17,727		27,835			81,879		53,433		28,446
Development expense	1,616			16,609		(14,993		)	3,163		32,705		(29,542		)
Marketing expense	26,225			20,379		5,846			51,203		33,425		17,778
General and administrative expense	61,409			87,477		(26,068		)	109,333		132,448		(23,115		)
Depreciation and amortization expense	32,781			20,154		12,627			56,870		37,923		18,947
Impairment expense (recovery)	(71		)	—		(71		)	10,095		176		9,919
Other	50			109		(59		)	162		265		(103		)
Total operating costs and expenses	$	253,281		$	163,899	$	89,382		$	412,921	$	292,512	$	120,409

Our total operating costs and expenses increased $89.4 million and $120.4 million during the three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015, respectively, generally as a result of the commencement of operations of Train 1 of the SPL Project in May 2016. Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the SPL Project, and other related costs to convert natural gas into LNG, all to the extent not utilized for the commissioning process, as well as cost of sales related to our LNG and natural gas marketing business by Cheniere Marketing. Included in cost of sales during the three and six months ended June 30, 2016 was vessel charter costs of $6.8 million and $16.1 million, respectively, which were incurred throughout the period, including the period prior to substantial completion of Train 1 of the SPL Project. Operating and maintenance expense includes costs associated with operating and maintaining the SPL Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs. Depreciation and amortization expense increased during the three and six months ended June 30, 2016 as we began depreciation of our assets related to Train 1 of the SPL Project upon reaching substantial completion.

Offsetting the increases above was a decrease in general and administrative expense, which was partially due to a decrease in share-based compensation as a result of vesting of restricted stock awards in the second half of 2015, and partially due to a reallocation of resources from general and administrative activities to operating and maintenance activities following commencement of operations at the SPL Project. Development expense also decreased during the three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015, due to an FID made on Train 5 of the SPL Project in June 2015 and an FID made on Trains 1 and 2 of the CCL Project in May 2015.

Other expense (income)

	Three Months Ended June 30,							Six Months Ended June 30,
(Dollars in thousands)	2016		2015			Change		2016		2015			Change
Interest expense, net of capitalized interest	$	105,967	$	85,486		$	20,481	$	182,304	$	145,098		$	37,206
Loss on early extinguishment of debt	55,315		7,281			48,034		56,772		96,273			(39,501		)
Derivative loss (gain), net	90,621		(46,049		)	136,670		271,555		80,641			190,914
Other expense (income)	6,930		(283		)	7,213		6,001		(655		)	6,656
Total other expense	$	258,833	$	46,435		$	212,398	$	516,632	$	321,357		$	195,275

Interest expense, net of capitalized interest, increased $20.5 million and $37.2 million in the three and six months ended June 30, 2016, as compared to the three and six months ended June 30, 2015, primarily as a result of an increase in our indebtedness outstanding, from $16.6 billion as of June 30, 2015 to $19.5 billion as of June 30, 2016, and the decrease in the portion of total interest costs that could be capitalized as Train 1 of the SPL Project is no longer in construction. For the three and six months ended June 30, 2016, we incurred $316.1 million and $609.4 million of total interest cost, respectively, of which we capitalized $210.1 million and $427.0 million, respectively, which were directly related to the construction of the SPL Project and the CCL Project. For the three and six months ended June 30, 2015, we incurred $241.2 million and $421.9 million of total interest cost,

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respectively, of which we capitalized $155.7 million and $276.8 million, respectively, which were directly related to the construction of the SPL Project and the CCL Project.

Loss on early extinguishment of debt increased $48.0 million in the three months ended June 30, 2016, as compared to the three months ended June 30, 2015 whereas it decreased $39.5 million in the six months ended June 30, 2016, as compared to the six months ended June 30, 2015. Loss on early extinguishment of debt during the three and six months ended June 30, 2016 was attributable to the $29.0 million write-off of debt issuance costs related to the prepayment of approximately $1.1 billion of outstanding borrowings under the 2015 CCH Credit Facility in May 2016 in connection with the issuance of the 2024 CCH Senior Notes, $26.0 million write-off of debt issuance costs related to the prepayment of approximately $1.3 billion of outstanding borrowings under the 2015 SPL Credit Facilities in June 2016 in connection with the issuance of the 2026 SPL Senior Notes and the $1.5 million write-off of debt issuance costs and unamortized discount in connection with the prepayment of the CTPL Term Loan in February 2016. Loss on early extinguishment of debt during the three months ended June 30, 2015 was related to the termination and replacement of the 2013 SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015 that resulted in a write-off of debt issuance costs and deferred commitment fees of $7.3 million and in the six months ended June 30, 2015 included an additional $89.0 million write-off of debt issuance costs and deferred commitment fees related to the termination of approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities in March 2015.

Derivative loss, net increased $136.7 million and $190.9 million during the three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015, respectively, primarily due to a decrease in the forward LIBOR curve during those periods and an increase in the notional amount of interest rate swaps. Derivative loss recognized during the six months ended June 30, 2015 also included the loss recognized upon meeting the contingency related to the CCH Interest Rate Derivatives, as well as the loss recognized in March 2015 upon the termination of interest rate swaps associated with approximately $1.8 billion of commitments that were terminated under the 2013 SPL Credit Facilities.

Other

	Three Months Ended June 30,									Six Months Ended June 30,
(Dollars in thousands)	2016			2015			Change			2016			2015			Change
Income tax provision (benefit)	$	(343	)	$	(507	)	$	164		$	273		$	171		$	102
Net loss attributable to non-controlling interest	(36,526		)	(23,307		)	(13,219		)	(64,662		)	(91,442		)	26,780

Net loss attributable to non-controlling interest increased $13.2 million in the three months ended June 30, 2016 as compared to the three months ended June 30, 2015, primarily as a result of the increase in consolidated net loss recognized by Cheniere Partners in which the non-controlling interest is held. The consolidated net loss recognized by Cheniere Partners increased from $60.0 million in the three months ended June 30, 2015 to $100.1 million in the three months ended June 30, 2016, primarily as a result of increased loss on early extinguishment of debt, increased derivative loss, net, increased interest expense, net of amounts capitalized, partially offset by increased income from operations primarily as a result of the commencement of operations of Train 1 of the SPL Project in May 2016. Net loss attributable to non-controlling interest decreased $26.8 million in the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, as a result of the decrease in consolidated net loss recognized by Cheniere Partners in which the non-controlling interest is held. The additional consolidated net loss recognized by Cheniere Partners in the first six months of 2015 primarily related to the increased loss on early extinguishment of debt during the period as explained above and loss from operations.

Off-Balance Sheet Arrangements

As of June 30, 2016, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results. 

Summary of Critical Accounting Estimates

The preparation of 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, 2015.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 18—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 purchase agreements to secure natural gas feedstock for the SPL Project(“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the basis price for natural gas for each delivery location. As of June 30, 2016, we estimated the fair value of the Liquefaction Supply Derivatives to be $20.0 million. Based on actual derivative contractual volumes, a 10% increase or decrease in the underlying basis prices would have resulted in a change in the fair value of the Liquefaction Supply Derivatives of $1.5 million as of June 30, 2016, compared to $0.9 million as of December 31, 2015. See Note 6—Derivative Instruments for additional details about our derivative instruments.

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 LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the basis price for LNG. As of June 30, 2016, we estimated the fair value of the LNG Trading Derivatives to be a liability of $12.4 million. Based on actual derivative contractual volumes, a 10% increase or decrease in the underlying basis price would have resulted in a change in the fair value of the LNG Trading Derivatives of $10.0 million as of June 30, 2016, whereas it was immaterial as of December 31, 2015. See Note 6—Derivative Instruments for additional details about our derivative instruments.

Interest Rate Risk

SPL has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 SPL Credit Facilities(“SPL Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the SPL Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining term of the SPL Interest Rate Derivatives. As of June 30, 2016, we estimated the fair value of the SPL Interest Rate Derivatives to be a liability of $20.7 million. This 10% change in interest rates would have resulted in a change in the fair value of the SPL Interest Rate Derivatives of $1.4 million as of June 30, 2016, compared to $3.1 million as of December 31, 2015. The decrease in the effect of change in interest rates was due to a decrease in the forward 1-month LIBOR curve during the six months ended June 30, 2016.

Cheniere Partners has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2016 CQP Credit Facilities(“CQP Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the CQP Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining term of the CQP Interest Rate Derivatives. As of June 30, 2016, we estimated the fair value of the CQP Interest Rate Derivatives to be a liability of $19.1 million. This 10% change in interest rates would have resulted in a change in the fair value of the CQP Interest Rate Derivatives of $3.3 million as of June 30, 2016.

CCH has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 CCH Credit Facility(“CCH Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the CCH Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining term of the CCH Interest Rate Derivatives. As of June 30, 2016, we estimated the fair value of the CCH Interest Rate Derivatives to be a liability of $327.3 million. This 10% change in interest rates would have resulted in a change in the fair value of the CCH Interest Rate Derivatives of $36.0 million as of June 30, 2016, compared to $55.6 million as of December 31, 2015. The decrease in the effect of change in interest rates was due to a decrease in the forward 1-month LIBOR curve during the six months ended June 30, 2016.

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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 of June 30, 2016, we estimated the fair value of the FX Derivatives to be $0.2 million. This 10% change in FX rates would have resulted in an immaterial change in the fair value of the FX Derivatives as of June 30, 2016.

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.

LDEQ Matter

Please see Part II, Item 1, “Legal Proceedings - LDEQ Matter” in the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2016.

Parallax Litigation

In 2015, Cheniere Energy Inc.’s (“CEI”) 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 Suit”). CLNGT asserted claims in the Texas 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 Suit moved to dismiss the suit for lack of subject matter jurisdiction. CLNGT has responded to that motion, and it remains pending before the court.

On March 11, 2016, Parallax Enterprises filed a suit against CEI 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 CEI and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises seeks $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, CEI and CLNGT removed the Louisiana Suit to the United States District Court for the Eastern District of Louisiana, where it is pending as Civil Action No. 2:16-cv-03209-CJB-SS. On April 22, 2016, CEI and CLNGT filed a motion in the Louisiana Suit seeking (1) dismissal of all claims against CEI for lack of personal jurisdiction, (2) dismissal, stay, or transfer of the suit to the United States District Court for the Southern District of Texas in deference to the first-filed Texas Suit, and (3) alternatively, transfer of the suit for convenience of the parties and witnesses. On May 4, 2016, Parallax Enterprises filed a motion to remand the Louisiana Suit to state court. On June 6, 2016, the court granted our request to transfer the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was then transferred to the same judge before which the Texas Suit is pending.  Parallax Enterprises’ motion to remand the Louisiana Suit to Louisiana state court and our motion to dismiss the Louisiana Suit in deference to the first-filed Texas Suit remain pending. We do not expect that the resolution of this litigation will have a material adverse impact on our financial results.

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, 2015.

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

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended June 30, 2016:

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
April 1 - 30, 2016	15,345	$33.77	—	—
May 1 - 31, 2016	17,224	$38.84	—	—
June 1 - 30, 2016	41,950	$33.36	—	—
Total	74,519		—	—

(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.

ITEM 5. OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the quarter ended June 30, 2016, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our quarterly report on Form 10-Q as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”). During the quarter ended June 30, 2016, we did not engage in any transactions with Iran or with persons or entities related to Iran.

Blackstone CQP Holdco LP, an affiliate of The Blackstone Group L.P. (“Blackstone Group”), is a holder of more than 29% of the outstanding equity interests of Cheniere Partners and has three representatives on the board of directors of Cheniere Partners GP. Accordingly, Blackstone Group may be deemed an “affiliate” of Cheniere Partners, as that term is defined in Exchange Act Rule 12b-2. Blackstone Group included in its quarterly report on Form 10-Q for the quarterly period ended June 30, 2016 disclosures pursuant to ITRA regarding one of its portfolio companies that may be deemed to be affiliates of Blackstone Group. Because of the broad definition of “affiliate” in Exchange Act Rule 12b-2, this portfolio company of Blackstone Group, through Blackstone Group’s ownership of Cheniere Partners, may also be deemed to be an affiliate of ours. We have not independently verified the disclosure described in the following paragraph.

Blackstone Group disclosed that NCR Corporation (“NCR”) has engaged in the following activities: NCR has reported that during the period from April 1, 2016 through April 30, 2016, NCR continued to maintain a bank account and guarantees at the Commercial Bank of Syria (“CBS”), which was designated as a Specially Designated National pursuant to Executive Order 13382 (“EO 13382”) on August 10, 2011.  This bank account and the guarantees at CBS were maintained in the normal course of business prior to the listing of CBS pursuant to EO 13382.  NCR reported that the last known account balance as of April 30, 2016, was approximately $3,468.  The bank account did not generate interest from April 1, 2016 through April 30, 2016, and the guarantees did not generate any revenue or profits for NCR. Pursuant to a license granted to NCR by the Office of Foreign Assets Control (the “OFAC”) on January 3, 2013, and subsequent licenses granted on April 29, 2013, July 12, 2013, February 28, 2014, November 12, 2014, and October 24, 2015, NCR had been winding down its past operations in Syria. NCR’s last such license expired on April 30, 2016. In addition, NCR’s application to renew the license to transact business with CBS, which was submitted to OFAC on May 18, 2015, was not acted upon prior to the expiration of NCR’s last such license. As a result, and in connection with the license expiration, the Company abandoned its remaining property in Syria, which, including the CBS account, was commercially insignificant, and ended the employment of its final two employees in Syria, who had remained employed by the Company to assist with the execution of the Company’s wind-down activities pursuant to authority granted by the OFAC licenses. NCR does not intend to engage in any further business activities with CBS.

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ITEM 6. EXHIBITS

Exhibit No.	Description
4.1	Indenture, dated as of May 18, 2016, among Cheniere Corpus Christi Holdings, LLC, as issuer, Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P. and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 18, 2016)
4.2	Seventh Supplemental Indenture, dated as of June 14, 2016, between Sabine Pass Liquefaction, LLC 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 June 14, 2016)
10.1†	Employment Agreement between Cheniere Energy, Inc. and Jack Fusco, dated May 12, 2016 (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 12, 2016)
10.2†	Letter Agreement between Cheniere Energy, Inc. and Neal Shear, dated May 12, 2016 (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 12, 2016)
10.3	Registration Rights Agreement, dated as of May 18, 2016, among Cheniere Corpus Christi Holdings, LLC and Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P. and Corpus Christi Pipeline GP, LLC, as guarantors, and Morgan Stanley & Co. LLC, for itself and as representative of the purchasers (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 18, 2016)
10.4	Registration Rights Agreement, dated as of June 14, 2016, between Sabine Pass Liquefaction, LLC and Credit Suisse Securities (USA) LLC (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on June 14, 2016)
10.5	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00045 April Site Closure for Cheniere Celebration, dated April 4, 2016, (ii) the Change Order CO-00046 Defer Completion of Ship Loading Time Commissioning Test, dated May 17, 2016, and (iii) the Change Order CO-00047 Re-Orientation of PSV Bypass Valves, dated May 25, 2016 (Incorporated by reference to Exhibit 10.2 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on August 8, 2016)
10.6	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00021 Smokeless Flare Modification Study, dated March 29, 2016, (ii) the Change Order CO-00022 Cable Tray Support and Arc Flash Study, dated May 4, 2016, and (iii) the Change Order CO-00023 Re-Orientation of PSV Bypass Valves, dated May 17, 2016 (Incorporated by reference to Exhibit 10.3 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on August 8, 2016)
10.7	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00005 Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum, dated March 16, 2016, (ii) the Change Order CO-00006 Additional Bechtel Hours to Support RECON, Temporary Access Rd., Addition of Flash Liquid Expander, Removal of Vibration Monitor System, To-Date Reconciliation of Soils Preparation Provisional Sum, dated March 22, 2016, (iii) the Change Order CO-00007 Additional Support for FERC Document Requests, dated May 10, 2016, (iv) the Change Order CO-00008 Water System Scope Changes and Seal Design & Seal Gas Modification, dated May 4, 2016, (v) the Change Order CO-00009 Re-Orientation of PSV Bypass Valves, dated May 17, 2016, and (vi) the Change Order CO-00010 Deletion of Chlorine Analyzer, dated June 15, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on August 8, 2016)
10.8*	Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between Corpus Christi Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00017 Process and Utility Tie-Ins Studies and Associated Scopes (138 kV Pricing, Transfer Line, Connections for Future LNG Truck Loading Facility), dated May 24, 2016, (ii) the Change Order CO-00018 FERC Conditions 40, 63, 64, 80, dated May 4, 2016, (iii) the Change Order CO-00019 Trelleborg Marine Equipment, BOG Compressor Tie-In, Multiplexer Credit, Additional FERC Hours, dated May 4, 2016, and (iv) the Change Order CO-00020 Impact Due to Overhead Power Transmission Lines on La Quinta Road and Flare System Modification Evaluation, dated May 31, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)

51

Exhibit No.	Description
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.
†	Management contract or compensatory plan or arrangement.

52

SIGNATURES

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

		CHENIERE ENERGY, INC.
Date:	August 8, 2016	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Senior Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	August 8, 2016	By:	/s/ Leonard Travis
			Leonard Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

53

EX-10.8

Exhibit 10.8

*** 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 FORM

Process and Utility Tie-Ins Studies and Associated Scopes (138 kV Pricing, Transfer Line, Connections for Future LNG Truck Loading Facility)

PROJECT NAME:  Corpus Christi Stage 1 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 6, 2013 CHANGE ORDER NUMBER: CO-00017 DATE OF CHANGE ORDER: May 24, 2016

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

1. Per Article 6.1.B of the Agreement, Parties agree Contractor will engineer, procure and construct to facilitate future expansion for the following scopes of work:

a. Condensate Storage Tank Connections — a 3” T-connection and associated valves and drain.

b. Refrigerant Storage System updates are listed below:

i. 6” T-connection and associated valves and drains added to the suction of the Stage 1 Propane Make-up Pump and a 4” T-connection and associated valves and drains added to the liquid propane return line from Trains in Stage 1.

ii. Three 4” T-connections and associated valves and drains added to the ethylene make-up/de-inventory line in Stage 1

iii. Utility connections in Stage 1 for future Stage 3 pump (Propane Makeup and Ethylene Re-Inventory Pumps) are listed below:

▪ Two 2” blowdown connections with associated valves and drains

▪ Four 2" dry flare connections with associated valves and drains

▪ Two 2" nitrogen connections with associated valves and drains

c. Amine Storage System — Three 6” T-connections and associated valves and drains.

d. Firewater — 18” T-connection and isolation valve added to the Stage 1 firewater pumps header and modifications to three (3) pipe racks and foundations to accommodate the future 18” line.

e. Plant Air — 8” T-connection and associated valve and drain added to the Stage 1 plant air header.

f. Details of these studies are depicted in Exhibit A of this Change Order.

2. Per Article 6.1.B of the Agreement, Parties agree Contractor will conduct all the following updates for the future expansion:

a. The first pole outside Hecker substation will be changed to a branch pole. This pole will allow the incoming lines from Hecker substation to split and run in two directions. One set of lines from the branch pole will cross the La Quinta road and will be routed North to a dead-end structure for future expansion. The other set of lines from the branch pole will cross the La Quinta road and will be routed South to serve CCL Stage 1 and future CCL Stage 2. Height of poles will be designed to meet clearance requirements of the overhead lines in accordance with NESC C-2.

b. A manually operated disconnect switch will be provided to allow the future expansion dead -end pole to be de-energized when CCL Stage 1 overhead lines are in service.

c. Separate set of 2 x OPGW (Optical Ground Wire) will be provided from the Hecker substation to the future expansion dead-end pole.

d. Contractor’s installation scope will begin from the branch pole outside Hecker substation and will include the overhead lines routed to the future expansion dead end pole and CCL Stage 1 overhead-to-underground termination pole. Contractor will free-issue the overhead line conductor and OPGW for installation between the branch pole and the Hecker substation termination poles by Owner. Contractor will coil the OPGW fibers in splice boxes provided on the branch pole. Fusion splicing of fibers in the splice boxes at branch pole and the future expansion dead-end pole will be by the Owner.

e. This scope is depicted in Exhibit B.

3. Per Article 6.1.B of the Agreement, Parties agree Contractor will design and construct foundation and structural steel changes required on a portion of the 102R01(Utility Piperack) necessary for volume and loads of a new 30” transfer line. This scope is depicted in Exhibit C.

4. Per Article 6.1.B of the Agreement, Parties agree Contractor will engineer, procure, and construct two (2) tie-ins for future LNG truck loading facilities. One of the tie-ins will be an 8” tie-in to the LNG line and the other will be an 8” tie-in to the BOG line. This scope is depicted in Exhibit D.

5. The cost breakdowns for the scopes of work noted above in this Change Order are detailed in Exhibit E.

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

Adjustment to Contract Price

The original Contract Price was	$	7,080,830,000
Net change by previously authorized Change Orders (0001-00016)	$	543,457,362
The Contract Price prior to this Change Order was	$	7,624,287,362
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	$	7,627,893,684

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was	$	***
Net change by previously authorized Change Orders (0001-00016)	$	***
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 (0001-00016)	$	***
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 Aggregate Labor and Skills Price including this Change Order will be	$	***

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was	$	950,561,351
Net change by previously authorized Change Orders (0001-00016)	$	(745,966,926	)
The Aggregate Provisional Sum prior to this Change Order was	$	204,594,425
The Aggregate Provisional Sum will be changed by this Change Order in the amount of	$	—
The new Aggregate Provisional Sum including this Change Order will be	$	204,594,425

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): No impact to Project Schedule.

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

Adjustment to Payment Schedule: Yes. See Exhibit C 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/ WK 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/ Walker Kimball
Owner	Contractor
Ed Lehotsky	Walker Kimball
Name	Name
Sr. VP LNG E&C	Senior Project Manager, SVP
Title	Title
June 8, 2016	May 24, 2016
Date of Signing	Date of Signing

*** 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 FORM

FERC Conditions 40, 63, 64, 80

PROJECT NAME:  Corpus Christi Stage 1 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 6, 2013 CHANGE ORDER NUMBER: CO-00018 DATE OF CHANGE ORDER: May 4, 2016

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

1. Per Article 6.1.B of the Agreement, Parties agree Contractor will comply with the conditions of FERC Order 40 which states the “final design shall provide an air gap or vent installed downstream of the process seals or isolations installed at the interface between a flammable fluid system and an electrical conduit or wiring system. Each air gap shall vent to a safe location and be equipped with a leak detection device that shall continuously monitor for the presence of flammable fluid; shall alarm the hazardous condition; and shall shutdown the appropriate systems.” To comply, Contractor will revise the design as follows:

a. Provide interlock showdown capability on identified pumps;

b. Mitigate nuisance alarms and trips by:

i. Prescribing alarm set-point to be fluid service specific

ii. Alarm to occur at (-5 degrees F) and trip alarm at (-58 degrees F)

iii. Add an interlock to shutdown each pump at Time elapsed 10 seconds after receiving trip set point.

2. Per Article 6.1.B of the Agreement, Parties agree Contractor will comply with the conditions of FERC Order 63 which states “final design shall specify the ethylene storage vessels be equipped with redundant full capacity relief valves.” To comply, Contractor will install redundant full capacity relief valves on ethylene storage vessels 00V-2001A, 00V-2001B, and 00V-2001C. The redundant valve shall be set at the design pressure of the equipment. All relief valves shall have their isolation valves car sealed open and upstream isolation valves on spare(s) car seal closed.

3. Per Article 6.1.B of the Agreement, Parties agree Contractor will comply with the conditions of FERC Order 64 which states “final design shall specify that propane storage vessels be equipped with redundant full capacity relief valves.” To comply, Contractor will install redundant full capacity relief valves on propane storage vessels 00V-2002A and 00V-2002B. The redundant valve shall be set at the design pressure of the equipment. All relief valves shall have their isolation valves car sealed open and upstream isolation valves on spare(s) car seal closed.

4. Per Article 6.1.B of the Agreement, Parties agree Contractor will comply with the conditions of FERC Order 80 which states “final design shall include clean agent systems in the electrical switchgear and instrumentation buildings.” To comply, Contractor will add 17 clean agent systems in all occupied or unoccupied electrical switchgear and instrumentation buildings. Clean agent systems will be based on FM-200 or equivalent.

5. The cost breakdowns for the scopes of work noted above in this Change Order are detailed in Exhibit A.

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

Adjustment to Contract Price

The original Contract Price was	$	7,080,830,000
Net change by previously authorized Change Orders (0001-00017)	$	547,063,684
The Contract Price prior to this Change Order was	$	7,627,893,684
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	$	7,634,601,089

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was	$	***
Net change by previously authorized Change Orders (0001-00017)	$	***
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 (0001-00017)	$	***
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 Aggregate Labor and Skills Price including this Change Order will be	$	***

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was	$	950,561,351
Net change by previously authorized Change Orders (0001-00017)	$	(745,966,926	)
The Aggregate Provisional Sum prior to this Change Order was	$	204,594,425
The Aggregate Provisional Sum will be changed by this Change Order in the amount of	$	—
The new Aggregate Provisional Sum including this Change Order will be	$	204,594,425

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): No impact to Project Schedule.

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

Adjustment to Payment Schedule: Yes. See Exhibit B 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/ WK 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/ Walker Kimball
Owner	Contractor
Ed Lehotsky	Walker Kimball
Name	Name
Sr. VP LNG E&C	Senior Project Manager, SVP
Title	Title
May 17, 2016	May 4, 2016
Date of Signing	Date of Signing

*** 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 FORM

Trelleborg Marine Equipment, BOG Compressor Tie-In, Multiplexer Credit, Additional FERC Hours

PROJECT NAME:  Corpus Christi Stage 1 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 6, 2013 CHANGE ORDER NUMBER: CO-00019 DATE OF CHANGE ORDER: May 4, 2016

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

1. Per Article 6.1.B of the Agreement, Parties agree Contractor will ensure the Quick Release Hook (QRH) assemblies and spare fasteners will be stainless steel. The chains for the breasting dolphin fenders will remain hot dip galvanized with a 6mm corrosion allowance.

2. Per Article 6.1.B of the Agreement, Parties agree Contractor will install an additional 20-inch line and an additional 2-inch line for the future BOG and thermal relief tie-ins for the BOG compressor. These additions require increased support associated with pipe racks 102R01 (Utility Piperack) and 102R02 (Storage Tank Piperack) as shown in Exhibit A.

3. Per Article 6.1.B of the Agreement, Parties agree Contractor will remove the two (2) additional multiplexer (MUX) interfaces that interconnected the Owner and AEP 138kV switchgear to drive the fiber optic lines. This scope was added in Change Order CO-00007, executed August 11, 2015. Owner will be credited for this scope removal.

4. Per Article 6.1.B of the Agreement, Parties agree Contractor will add 3,500 additional hours for FERC support in accordance with Attachment A, Section 9.2 of the Agreement.

5. The cost breakdowns for the scopes of work noted above in this Change Order are detailed in Exhibit B.

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

Adjustment to Contract Price

The original Contract Price was	$	7,080,830,000
Net change by previously authorized Change Orders (0001-00018)	$	553,771,089
The Contract Price prior to this Change Order was	$	7,634,601,089
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	$	7,635,880,974

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was	$	***
Net change by previously authorized Change Orders (0001-00018)	$	***
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 (0001-00018)	$	***
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 Aggregate Labor and Skills Price including this Change Order will be	$	***

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was	$	950,561,351
Net change by previously authorized Change Orders (0001-00016)	$	(745,966,926	)
The Aggregate Provisional Sum prior to this Change Order was	$	204,594,425
The Aggregate Provisional Sum will be changed by this Change Order in the amount of	$	—
The new Aggregate Provisional Sum including this Change Order will be	$	204,594,425

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): No impact to Project Schedule.

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

Adjustment to Payment Schedule: Yes. See Exhibit C 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/ WK 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/ Walker Kimball
Owner	Contractor
Ed Lehotsky	Walker Kimball
Name	Name
Sr. VP LNG E&C	Senior Project Manager, SVP
Title	Title
June 8, 2016	May 4, 2016
Date of Signing	Date of Signing

*** 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 FORM

Impact Due to Overhead Power Transmission Lines on La Quinta Road and Flare System Modification Evaluation

PROJECT NAME:  Corpus Christi Stage 1 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 6, 2013 CHANGE ORDER NUMBER: CO-00020 DATE OF CHANGE ORDER: May 31, 2016

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

1. Per Article 6.1.B of the Agreement, Parties agree Contractor will be compensated for the costs associated with required mobilization of a larger crane than planned to complete box culvert installation impeded by overhead transmission lines obstructing the path of construction.

2. Per Article 6.1.B of the Agreement, Parties agree Contractor will conduct a study to identify a short-term solution (based on nitrogen injection) and a long-term solution (based on either high or low pressure air injection) to mitigate smoke production in the flares. The study will form the basis of estimate for the implementation of short-term and long-term flare modifications.

3. The cost breakdowns for the scopes of work noted above in this Change Order are detailed in Exhibit A.

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

Adjustment to Contract Price

The original Contract Price was	$	7,080,830,000
Net change by previously authorized Change Orders (0001-00019)	$	555,050,974
The Contract Price prior to this Change Order was	$	7,635,880,974
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	$	7,636,461,457

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was	$	***
Net change by previously authorized Change Orders (0001-00019)	$	***
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 (0001-00019)	$	***
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 Aggregate Labor and Skills Price including this Change Order will be	$	***

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was	$	950,561,351
Net change by previously authorized Change Orders (0001-00019)	$	(745,966,926	)
The Aggregate Provisional Sum prior to this Change Order was	$	204,594,425
The Aggregate Provisional Sum will be changed by this Change Order in the amount of	$	—
The new Aggregate Provisional Sum including this Change Order will be	$	204,594,425

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): No impact to Project Schedule.

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

Adjustment to Payment Schedule: Yes. See Exhibit B 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/ WK 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/ Walker Kimball
Owner	Contractor
Ed Lehotsky	Walker Kimball
Name	Name
Sr. VP LNG E&C	Senior Project Manager, SVP
Title	Title
June 15, 2016	May 31, 2016
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 quarterthat has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

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

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

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

Date: August 8, 2016

/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 quarterthat has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

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

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

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

Date: August 8, 2016

/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 June 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: August 8, 2016

/s/ Jack A. Fusco

Jack A. Fusco
Chief Executive Officer of

Cheniere Energy, Inc.

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2016, 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: August 8, 2016

/s/ Michael J. Wortley

Michael J. Wortley
Chief Financial Officer of

Cheniere Energy, Inc.

XML

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2016	Aug. 01, 2016
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	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		235,689,131

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 1,049,478	$ 1,201,112
Restricted cash	724,458	503,397
Accounts and other receivables	74,283	5,749
Inventory	66,322	18,125
Other current assets	75,941	54,203
Total current assets	1,990,482	1,782,586
Non-current restricted cash	31,726	31,722
Property, plant and equipment, net	18,729,177	16,193,907
Debt issuance costs, net	336,474	378,677
Non-current derivative assets	20,715	30,887
Goodwill	76,819	76,819
Other non-current assets	251,458	314,455
Total assets	21,436,851	18,809,053
Current liabilities
Accounts payable	48,676	22,820
Accrued liabilities	589,604	427,199
Current debt, net	1,677,476	1,673,379
Deferred revenue	26,709	26,669
Derivative liabilities	72,002	35,201
Other current liabilities	54	0
Total current liabilities	2,414,521	2,185,268
Long-term debt, net	17,789,074	14,920,427
Non-current deferred revenue	7,500	9,500
Non-current derivative liabilities	311,207	79,387
Other non-current liabilities	50,382	53,068
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 June 30, 2016 and December 31, 2015; Issued and outstanding: 235.7 million shares and 235.6 million shares at June 30, 2016 and December 31, 2015, respectively	707	708
Treasury stock: 11.8 million shares and 11.6 million shares at June 30, 2016 and December 31, 2015, respectively, at cost	(357,491)	(353,927)
Additional paid-in-capital	3,105,728	3,075,317
Accumulated deficit	(4,243,204)	(3,623,948)
Total stockholders’ deficit	(1,494,260)	(901,850)
Non-controlling interest	2,358,427	2,463,253
Total equity	864,167	1,561,403
Total liabilities and equity	$ 21,436,851	$ 18,809,053

XML

Consolidated Balance Sheets Parentheticals - $ / shares shares in Thousands	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Preferred Stock, Par Value	$ 0.0001	$ 0.0001
Preferred Stock, Shares Authorized	5,000	5,000
Preferred Stock, Shares Issued	0	0
Common Stock, Par Value Per Share	$ 0.003	$ 0.003
Common Stock, Shares Authorized	480,000	480,000
Common Stock, Shares, Issued	235,711	235,639
Common Stock, Shares, Outstanding	235,711	235,639
Treasury Stock, Shares	11,757	11,649

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues
Regasification revenues		$ 65,622	$ 66,489	$ 131,173	$ 133,291
LNG revenues (losses)		110,735	(706)	113,439	(44)
Other revenues		470	2,242	1,296	3,147
Total revenues		176,827	68,025	245,908	136,394
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)		85,709	1,444	100,216	2,137
Operating and maintenance expense		45,562	17,727	81,879	53,433
Development expense		1,616	16,609	3,163	32,705
Marketing expense		26,225	20,379	51,203	33,425
General and administrative expense		61,409	87,477	109,333	132,448
Depreciation and amortization expense		32,781	20,154	56,870	37,923
Impairment expense (recovery)		(71)	0	10,095	176
Other		50	109	162	265
Total operating costs and expenses		253,281	163,899	412,921	292,512
Loss from operations		(76,454)	(95,874)	(167,013)	(156,118)
Other income (expense)
Interest expense, net of capitalized interest		(105,967)	(85,486)	(182,304)	(145,098)
Loss on early extinguishment of debt		(55,315)	(7,281)	(56,772)	(96,273)
Derivative gain (loss), net		(90,621)	46,049	(271,555)	(80,641)
Other income (expense)		(6,930)	283	(6,001)	655
Total other expense		(258,833)	(46,435)	(516,632)	(321,357)
Loss before income taxes and non-controlling interest	[1]	(335,287)	(142,309)	(683,645)	(477,475)
Income tax benefit (provision)		343	507	(273)	(171)
Net loss		(334,944)	(141,802)	(683,918)	(477,646)
Less: net loss attributable to non-controlling interest		(36,526)	(23,307)	(64,662)	(91,442)
Net loss attributable to common stockholders		$ (298,418)	$ (118,495)	$ (619,256)	$ (386,204)
Net loss per share attributable to common stockholders—basic and diluted		$ (1.31)	$ (0.52)	$ (2.71)	$ (1.71)
Weighted average number of common shares outstanding—basic and diluted		228,323	226,481	228,231	226,405

[1] Items to reconcile loss from operations and loss before income taxes and non-controlling interest include consolidated other income (expense) amounts as presented on our Consolidated Statements of Operations primarily related to our LNG terminal segment.

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Consolidated Statement of Stockholders' Equity - 6 months ended Jun. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Accumulated Deficit	Non-controlling Interest
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2015	235,639	235,639
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2015	11,649		11,649
Stockholders' Equity, Beginning of Period at Dec. 31, 2015	$ 1,561,403	$ 708	$ (353,927)	$ 3,075,317	$ (3,623,948)	$ 2,463,253
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuances of restricted stock, shares		273	0
Issuances of restricted stock	0	$ 1	$ 0	(1)	0	0
Forfeitures of restricted stock, shares		(96)	3
Forfeitures of restricted stock	0	$ (1)	$ 0	1	0	0
Share-based compensation	29,568	$ 0	$ 0	29,568	0	0
Shares repurchased related to share-based compensation, shares		(105)	105
Shares repurchased related to share-based compensation	(3,564)	$ (1)	$ (3,564)	1	0	0
Excess tax benefit (shortfall) from share-based compensation	(15)	0	0	(15)	0	0
Loss attributable to non-controlling interest	(64,662)	0	0	0	0	(64,662)
Equity portion of convertible notes, net	857	0	0	857	0	0
Distributions to non-controlling interest	(40,164)	0	0	0	0	(40,164)
Net loss	$ (619,256)	$ 0	$ 0	0	(619,256)	0
Common Stock, Shares, Outstanding, End of Period at Jun. 30, 2016	235,711	235,711
Treasury Stock, Shares, End of Period at Jun. 30, 2016	11,757		11,757
Stockholders' Equity, End of Period at Jun. 30, 2016	$ 864,167	$ 707	$ (357,491)	$ 3,105,728	$ (4,243,204)	$ 2,358,427

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities
Net loss	$ (683,918)	$ (477,646)
Adjustments to reconcile net loss to net cash used in operating activities:
Non-cash LNG inventory write-downs	0	17,366
Depreciation and amortization expense	56,870	37,923
Share-based compensation	51,724	66,378
Amortization of debt issuance costs and discount	26,906	24,900
Loss on early extinguishment of debt	56,772	96,273
Total losses on derivatives, net	295,917	80,198
Net cash used for settlement of derivative instruments	(16,798)	(88,934)
Impairment expense	10,095	176
Other	8,811	28,957
Changes in restricted cash for certain operating activities	151,676	(55,410)
Changes in operating assets and liabilities:
Accounts and other receivables	(67,760)	(2,396)
Inventory	(34,003)	(28,919)
Accounts payable and accrued liabilities	(14,226)	42,101
Deferred revenue	(1,960)	(1,985)
Other, net	15,860	(33,937)
Net cash used in operating activities	(144,034)	(294,955)
Cash flows from investing activities
Property, plant and equipment, net	(2,277,469)	(4,294,814)
Use of restricted cash for the acquisition of property, plant and equipment	2,279,835	4,183,620
Other	(21,623)	(101,836)
Net cash used in investing activities	(19,257)	(213,030)
Cash flows from financing activities
Proceeds from issuances of debt	5,698,219	5,205,000
Repayments of debt	(2,892,965)	0
Debt issuance and deferred financing costs	(97,215)	(411,149)
Investment in restricted cash	(2,652,576)	(4,518,880)
Distributions and dividends to non-controlling interest	(40,164)	(40,121)
Proceeds from exercise of stock options	0	1,914
Payments related to tax withholdings for share-based compensation	(3,564)	(6,174)
Other	(78)	19
Net cash provided by financing activities	11,657	230,609
Net decrease in cash and cash equivalents	(151,634)	(277,376)
Cash and cash equivalents—beginning of period	1,201,112	1,747,583
Cash and cash equivalents—end of period	$ 1,049,478	$ 1,470,207

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Basis of Presentation

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

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. 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 had no effect on our overall consolidated financial position, operating results or cash flows.

In 2016, we started production at our natural gas liquefaction facilities at the Sabine Pass LNG terminal (the “SPL Project”). As a result, we introduced two new line items entitled “Cost of sales” and “Marketing expense”, and modified the components of activity included in “Operating and maintenance expense” and “General and administrative expense” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made to the prior periods. The components of these line items are as follows:

• Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the SPL Project, vessel chartering costs and other costs related to converting natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense. Also included in cost of sales are purchase and delivery costs of our LNG and natural gas marketing business incurred by Cheniere Marketing.

• Operating and maintenance expense now primarily includes costs associated with operating and maintaining the SPL Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs.

• Marketing expense includes costs directly associated with our LNG and natural gas marketing activities by Cheniere Marketing such as payroll and benefit costs of LNG marketing and origination personnel, professional services and other support costs to contract LNG customers throughout the global marketplace for the SPL Project and our second natural gas liquefaction and export facility at the Corpus Christi LNG terminal (the “CCL Project”) and to place volumes in the market for our portfolio. These costs were reclassified from general and administrative expense.

Additionally, we distinguished and reclassified our historical “LNG terminal revenues” line item into “regasification revenues” and “LNG revenues.” Regasification revenues include LNG regasification capacity reservation fees that are received pursuant to our TUAs and tug services fees that are received by Sabine Pass Tug Services, LLC, a wholly owned subsidiary of SPLNG. Substantially all of our regasification revenues, which are generated by our LNG terminal segment, are received from our two long-term TUA customers. LNG revenues include fees that are received pursuant to our SPAs and related LNG marketing activities. During the three and six months ended June 30, 2016, we received 74% and 72%, respectively, of our net LNG revenues from one SPA customer, which were generated by our LNG terminal segment.

Results of operations for the three and six months ended June 30, 2016 are not necessarily indicative of the operating results that will be realized for the year ending December 31, 2016.

For further information, refer to the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2015.

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Restricted Cash

6 Months Ended

Jun. 30, 2016

Cash and Cash Equivalents [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 June 30, 2016 and December 31, 2015, restricted cash consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Current restricted cash
SPLNG debt service and interest payment	$	77,415	$	77,415
SPL Project	263,114		189,260
CTPL construction and interest payment	—		7,882
CQP and cash held by guarantor subsidiaries	109,977		—
CCL Project	223,117		46,770
Cash held by our subsidiaries restricted to Cheniere	12,821		147,138
Other	38,014		34,932
Total current restricted cash	$	724,458	$	503,397
Non-current restricted cash
SPLNG debt service	$	13,650	$	13,650
Other	18,076		18,072
Total non-current restricted cash	$	31,726	$	31,722

Under the indentures governing the senior notes issued by SPLNG (the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until certain conditions are satisfied, including: (1) there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and (2) there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the SPLNG Indentures. During the six months ended June 30, 2016 and 2015, SPLNG made distributions of $145.3 million and $199.6 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

In February 2016, Cheniere Partners entered into a $2.8 billion credit facility (the “2016 CQP Credit Facilities”). Cheniere Partners, and Cheniere Investments and CTPL as Cheniere Partners’ guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to Cheniere Partners. Specifically, Cheniere Partners, Cheniere Investments and CTPL may only withdraw funds from collateral accounts held at a designated depositary bank on a monthly basis and for specific purposes, including for the payment of operating expenses. 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

6 Months Ended

Jun. 30, 2016

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

As of June 30, 2016 and December 31, 2015, accounts and other receivables consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
SPL trade receivable	$	67,266	$	—
Interest receivable	259		95
Other accounts receivable	6,758		5,654
Total accounts and other receivables	$	74,283	$	5,749

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of SPL’s debt holders, SPL is required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the SPL Project and other restricted payments. As of June 30, 2016, the entire balance of the SPL trade receivable was from a single SPA customer.

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Inventory

6 Months Ended

Jun. 30, 2016

Inventory Disclosure [Abstract]

Inventory

INVENTORY

As of June 30, 2016 and December 31, 2015, inventory consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Natural gas	$	5,338	$	5,724
LNG	35,526		5,148
Materials and other	25,458		7,253
Total inventory	$	66,322	$	18,125

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Property, Plant and Equipment

6 Months Ended

Jun. 30, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of LNG terminal costs and fixed assets and other, as follows (in thousands):

	June 30,			December 31,
	2016			2015
LNG terminal costs
LNG terminal	$	5,459,151		$	2,487,759
LNG terminal construction-in-process	13,487,338			13,875,204
LNG site and related costs, net	38,753			33,512
Accumulated depreciation	(456,716		)	(413,545		)
Total LNG terminal costs, net	18,528,526			15,982,930
Fixed assets and other
Computer and office equipment	12,491			12,153
Furniture and fixtures	17,393			17,101
Computer software	76,471			69,340
Leasehold improvements	44,064			40,136
Land	60,582			60,612
Other	37,476			49,376
Accumulated depreciation	(47,826		)	(37,741		)
Total fixed assets and other, net	200,651			210,977
Property, plant and equipment, net	$	18,729,177		$	16,193,907

During the three and six months ended June 30, 2016, we realized offsets to LNG terminal costs of $131.8 million and $146.0 million, respectively, that were related to the sale of commissioning cargoes because these amounts were earned prior to the start of commercial operations, during the testing phase for the construction of Train 1 of the SPL Project.

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Derivative Instruments

6 Months Ended

Jun. 30, 2016

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 of our credit facilities (“Interest Rate Derivatives”);

• commodity derivatives to hedge the exposure to price risk attributable to future: (1) sales of our LNG inventory and (2) purchases of natural gas to operate the Sabine Pass LNG terminal (“Natural Gas Derivatives”);

• commodity derivatives consisting of natural gas purchase agreements for the commissioning and operation of the SPL Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives”, and collectively with the Physical Liquefaction Supply Derivatives, 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 operations in countries outside of the United States (“FX Derivatives”).

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.

The following table (in thousands) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of June 30, 2016 and December 31, 2015, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	June 30, 2016											December 31, 2015
	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
SPL Interest Rate Derivatives liability	$	—		$	(20,666	)	$	—	$	(20,666	)	$	—	$	(8,740	)	$	—	$	(8,740	)
CQP Interest Rate Derivatives liability	—			(19,148		)	—		(19,148		)	—		—			—		—
CCH Interest Rate Derivatives liability	—			(327,342		)	—		(327,342		)	—		(104,999		)	—		(104,999		)
Liquefaction Supply Derivatives asset (liability)	(2,850		)	381			22,434		19,965			—		(25		)	32,492		32,467
LNG Trading Derivatives asset (liability)	(1,443		)	(10,907		)	—		(12,350		)	—		1,053			—		1,053
Natural Gas Derivatives liability	—			—			—		—			—		(66		)	—		(66		)
FX Derivatives asset	—			160			—		160			—		—			—		—

We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. The estimated fair values of our economic hedges related to the LNG Trading Derivatives and our Natural Gas Derivatives are the amounts at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. We estimate the fair values of our FX Derivatives with a market approach using observable FX rates and other relevant data.

We acquired $0.8 million of certain LNG Trading Derivatives during the first three months of 2016, which we transferred into Level 1 during the three months ended June 30, 2016. We transferred these LNG Trading Derivatives to Level 1 due to the use of unadjusted quoted exchange prices to calculate the fair value of these LNG Trading derivative positions, which were previously Level 2 as the fair value was calculated using adjusted quoted exchange prices.

The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. 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 particular 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. Internal fair value models include conditions precedent to the respective long-term natural gas purchase agreements. As of June 30, 2016 and December 31, 2015, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow. Accordingly, our internal fair value models are based on market prices that equate to our own contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the 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 purchase agreements as of the reporting date.

As all of our Physical Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2016:

	Net Fair Value Asset (in thousands)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$22,434	Income Approach	Basis Spread	$(0.35) - $(0.02)

The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
Balance, beginning of period	$	30,054		$	342	$	32,492		$	342
Realized and mark-to-market losses:
Included in cost of sales (1)	(7,855		)	27		(10,204		)	27
Purchases and settlements:
Purchases	(16		)	71		31			71
Settlements (1)	(71		)	—		(128		)	—
Transfers out of Level 3 (2)	322			—		243			—
Balance, end of period	$	22,434		$	440	$	22,434		$	440
Change in unrealized gains relating to instruments still held at end of period	$	(7,795	)	$	27	$	(9,484	)	$	27

(1) Does not include the decrease in fair value of $0.1 million and $0.7 million related to the realized gains capitalized during the three and six months ended June 30, 2016, respectively.

(2) 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.  

Interest Rate Derivatives

SPL Interest Rate Derivatives

SPL has 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 “2015 SPL Credit Facilities”). The SPL Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities.

In March 2015, SPL settled a portion of the SPL Interest Rate Derivatives and recognized a derivative loss of $34.7 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments under the previous credit facilities.

CQP Interest Rate Derivatives

In March 2016, Cheniere Partners entered into interest rate swaps (“CQP Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2016 CQP Credit Facilities. The CQP Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities.

CCH Interest Rate Derivatives

CCH has entered into interest rate swaps (“CCH Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on its credit facility (the “2015 CCH Credit Facility”). The CCH Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 CCH Credit Facility. The CCH Interest Rate Derivatives have a seven-year term and were contingent upon reaching a final investment decision with respect to the CCL Project, which was reached in May 2015. Upon meeting the contingency related to the CCH Interest Rate Derivatives in May 2015, we paid $50.1 million related to contingency and syndication premiums, which is included in derivative gain (loss), net on our Consolidated Statements of Operations.

As of June 30, 2016, 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
SPL Interest Rate Derivatives	$20.0 million	$628.8 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
CQP Interest Rate Derivatives	$225.0 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR
CCH Interest Rate Derivatives	$28.8 million	$5.5 billion	May 20, 2015	May 31, 2022	2.29%	One-month LIBOR

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

	June 30, 2016												December 31, 2015
	SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			CCH Interest Rate Derivatives			Total			SPL Interest Rate Derivatives			CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total
Balance Sheet Location
Derivative liabilities	$	(7,340	)	$	(5,570	)	$	(45,149	)	$	(58,059	)	$	(5,940	)	$	—	$	(28,559	)	$	(34,499	)
Non-current derivative liabilities	(13,326		)	(13,578		)	(282,193		)	(309,097		)	(2,800		)	—		(76,440		)	(79,240		)
Total derivative liabilities	$	(20,666	)	$	(19,148	)	$	(327,342	)	$	(367,156	)	$	(8,740	)	$	—	$	(104,999	)	$	(113,739	)

The following table (in thousands) 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 six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
SPL Interest Rate Derivatives gain (loss)	$	(4,752	)	$	1,469	$	(16,030	)	$	(35,669	)
CQP Interest Rate Derivatives loss	(10,040		)	—		(19,570		)	—
CCH Interest Rate Derivatives gain (loss)	(75,877		)	44,580		(236,053		)	(44,972		)

Commodity Derivatives

Liquefaction Supply Derivatives

SPL has 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. The terms of the physical natural gas supply contracts primarily range from approximately one to seven years and commence upon the satisfaction of certain conditions precedent, including but not limited to the date of first commercial operation of specified Trains of the SPL Project. We recognize our Physical Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Physical Liquefaction Supply Derivatives are reported in earnings. As of June 30, 2016, SPL has secured up to approximately 2,027.5 millionMMBtu of natural gas feedstock through natural gas purchase agreements. The notional natural gas position of our Physical Liquefaction Supply Derivatives was approximately 1,114.5 millionMMBtu as of June 30, 2016.

Our Financial Liquefaction Supply Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our Financial Liquefaction Supply Derivatives activities.

LNG Trading Derivatives

As of June 30, 2016, we have entered into certain LNG Trading Derivatives representing a short position of 18.2 million MMBtu, and we may from time to time enter into certain financial derivatives in the form of swaps, forwards, options or futures to economically hedge exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG. We have entered into LNG Trading Derivatives to secure a fixed price position to minimize future cash flow variability associated with such LNG transactions.

Natural Gas Derivatives

Our Natural Gas Derivatives were executed through over-the-counter contracts which were subject to nominal credit risk as these transactions settled on a daily margin basis with investment grade financial institutions. We were required by these financial institutions to use margin deposits as credit support for our Natural Gas Derivatives activities. As of June 30, 2016, we did not have any open Natural Gas Derivatives positions or margin deposits at financial institutions.

We recognize all commodity derivative instruments, including our Liquefaction Supply Derivatives, LNG Trading Derivatives and Natural Gas Derivatives(collectively, “Commodity Derivatives”), as either assets or liabilities and measure those instruments at fair value.  Changes in the fair value of our Commodity Derivatives are reported in earnings.

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

	June 30, 2016											December 31, 2015
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Natural Gas Derivatives		Total			Liquefaction Supply Derivatives			LNG Trading Derivatives (2)			Natural Gas Derivatives (3)			Total
Balance Sheet Location
Other current assets	$	2,526		$	232		$	—	$	2,758		$	2,737		$	640		$	—		$	3,377
Non-current derivative assets	20,472			243			—		20,715			30,304			583			—			30,887
Total derivative assets	22,998			475			—		23,473			33,041			1,223			—			34,264
Derivative liabilities	(3,033		)	(10,778		)	—		(13,811		)	(490		)	(107		)	(66		)	(663		)
Non-current derivative liabilities	—			(2,047		)	—		(2,047		)	(84		)	(63		)	—			(147		)
Total derivative liabilities	(3,033		)	(12,825		)	—		(15,858		)	(574		)	(170		)	(66		)	(810		)
Derivative asset (liabilities), net	$	19,965		$	(12,350	)	$	—	$	7,615		$	32,467		$	1,053		$	(66	)	$	33,454

(1) Does not include collateral of $0.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of June 30, 2016.

(2) Does not include collateral of $15.6 million and $11.0 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015, respectively.

(3) Does not include collateral of $5.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

The following table (in thousands) 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 six months ended June 30, 2016 and 2015:

		Three Months Ended June 30,						Six Months Ended June 30,
	Statement of Operations Location	2016			2015			2016			2015
Liquefaction Supply Derivatives loss	LNG revenues (losses)	$	(34	)	$	—		$	(6	)	$	—
Liquefaction Supply Derivatives gain (loss) (1)	Cost of sales	(8,670		)	81			(12,264		)	81
LNG Trading Derivatives loss	LNG revenues (losses)	(16,976		)	—			(12,214		)	—
Natural Gas Derivatives gain (loss)	LNG revenues (losses)	—			67			(5		)	(98		)
Natural Gas Derivatives gain (loss)	Operating and maintenance expense	—			(294		)	174			460

(1)    Does not include the realized value associated with derivative instruments that settle through physical delivery.

The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our Commodity Derivatives are in an asset position.

FX Derivatives

Cheniere Marketing has entered into FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives economically hedge the foreign currency exposure arising from cash flows expended for both physical and financial LNG transactions and general and administrative expenses related to operations in countries outside of the United States. The total notional amount of our FX Derivatives was $102.1 million as of June 30, 2016.

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

		Fair Value Measurements as of
	Balance Sheet Location	June 30, 2016			December 31, 2015
FX Derivatives	Other current assets	$	355		$	—
FX Derivatives	Derivative liabilities	(132		)	—
FX Derivatives	Non-current derivative liabilities	(63		)	—

The following table (in thousands) shows the changes in the fair value of our FX Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2016 and 2015:

		Three Months Ended June 30,					Six Months Ended June 30,
	Statement of Operations Location	2016			2015		2016			2015
FX Derivatives gain	LNG revenues (losses)	$	2,641		$	—	$	40		$	—
FX Derivatives gain	Derivative gain (loss), net	48			—		98			—
FX Derivatives loss	Other income (expense)	(87		)	—		(87		)	—

Balance Sheet Presentation

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

	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 June 30, 2016
SPL Interest Rate Derivatives	$	(20,666	)	$	—		$	(20,666	)
CQP Interest Rate Derivatives	(19,148		)	—			(19,148		)
CCH Interest Rate Derivatives	(327,342		)	—			(327,342		)
Liquefaction Supply Derivatives	23,165			(167		)	22,998
Liquefaction Supply Derivatives	(4,505		)	1,472			(3,033		)
LNG Trading Derivatives	475			—			475
LNG Trading Derivatives	(22,455		)	9,630			(12,825		)
FX Derivatives	860			(505		)	355
FX Derivatives	(376		)	181			(195		)
As of December 31, 2015
SPL Interest Rate Derivatives	$	(8,740	)	$	—		$	(8,740	)
CCH Interest Rate Derivatives	(104,999		)	—			(104,999		)
Liquefaction Supply Derivatives	33,636			(595		)	33,041
Liquefaction Supply Derivatives	(574		)	—			(574		)
LNG Trading Derivatives	1,922			(699		)	1,223
LNG Trading Derivatives	(2,826		)	2,656			(170		)
Natural Gas Derivatives	188			(254		)	(66		)

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Other Non-Current Assets

6 Months Ended

Jun. 30, 2016

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

As of June 30, 2016 and December 31, 2015, other non-current assets consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Advances made under EPC and non-EPC contracts	$	14,000	$	83,579
Advances made to municipalities for water system enhancements	95,584		89,953
Tax-related payments and receivables	29,351		31,712
Equity method investments	11,983		20,295
Other	100,540		88,916
Total other non-current assets	$	251,458	$	314,455

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Variable Interest Entity

6 Months Ended

Jun. 30, 2016

Variable Interest Entity [Abstract]

Variable Interest Entity

VARIABLE INTEREST ENTITY

Cheniere Holdings

On January 1, 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This guidance changed (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination.

Cheniere Holdings is a limited liability company formed by us in 2013 to hold our Cheniere Partners limited partner interests. As of June 30, 2016, we owned 80.1% of Cheniere Holdings as well as the director voting share. The director voting share is the sole share entitled to vote in the election of Cheniere Holdings’ board of directors and allows us to remove members of the board of directors at any time and for any reason. If we cease to own greater than 25% of the common shares of Cheniere Holdings or if we choose to relinquish the director voting share, the director voting share will be extinguished.

The board of directors makes all major operating and financial decisions on behalf of Cheniere Holdings. Because ownership of the director voting share allows us to control Cheniere Holdings, irrespective of our majority ownership interest, and the director voting share cannot be removed from our control by the other equity holders of Cheniere Holdings, we have determined that Cheniere Holdings is now a variable interest entity. However, this determination has not changed the consolidation of Cheniere Holdings as we have determined that we are its primary beneficiary. Therefore, the determination that Cheniere Holdings is now a variable interest entity had no impact on our Consolidated Financial Statements.

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Non-Controlling Interest

6 Months Ended

Jun. 30, 2016

Noncontrolling Interest [Abstract]

Non-Controlling Interest

NON-CONTROLLING INTEREST

As of both June 30, 2016 and December 31, 2015, we owned 80.1% of Cheniere Holdings as well as the director voting share, with the remaining non-controlling interest held by the public. Cheniere Holdings owns a 55.9% limited partner interest in Cheniere Partners in the form of 12.0 million common units, 45.3 million Class B 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.

XML

Accrued Liabilities

6 Months Ended

Jun. 30, 2016

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

As of June 30, 2016 and December 31, 2015, accrued liabilities consisted of the following (in thousands): 

	June 30,		December 31,
	2016		2015
Interest costs and related debt fees	$	173,907	$	159,968
Compensation and benefits	69,975		99,511
SPL Project and CCL Project costs	326,788		145,759
LNG terminal costs	4,795		3,918
Other accrued liabilities	14,139		18,043
Total accrued liabilities	$	589,604	$	427,199

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Debt

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Debt

DEBT

As of June 30, 2016 and December 31, 2015, our debt consisted of the following (in thousands): 

	June 30,			December 31,
	2016			2015
Long-term debt:
SPLNG
6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) (1)	$	420,000		$	420,000
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7,959 and $8,718	2,007,959			2,008,718
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000,000			1,000,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $6,029 and $6,392	1,506,029			1,506,392
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000,000			2,000,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000,000			2,000,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500,000			—
2015 SPL Credit Facilities	832,695			845,000
CTPL
$400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429	—			398,571
Cheniere Partners
2016 CQP Credit Facilities	450,000			—
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250,000			—
2015 CCH Credit Facility	2,730,340			2,713,000
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,109,165			1,050,588
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”), net of unamortized discount of $158,036 and $174,095	921,690			879,938
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”), net of unamortized discount of $317,994 and $319,062	307,006			305,938
Unamortized debt issuance costs (2)	(245,810		)	(207,718		)
Total long-term debt, net	17,789,074			14,920,427
Current debt:
7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of $1,956 and $4,303 (3)	1,663,544			1,661,197
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			15,000
Cheniere Marketing trade finance facilities	15,219			—
Unamortized debt issuance costs (2)	(1,287		)	(2,818		)
Total current debt, net	1,677,476			1,673,379
Total debt, net	$	19,466,550		$	16,593,806

(1) Must be redeemed or repaid concurrently with the 2016 SPLNG Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 SPLNG Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities.

(2) Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $207.8 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.

(3) Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities.

2016 Debt Issuances and Redemptions

2026 SPL Senior Notes

In June 2016, SPL issued an aggregate principal amount of $1.5 billion of the 2026 SPL Senior Notes. Net proceeds of the offering of approximately $1.3 billion, after deducting commissions, fees and expenses and incremental interest required under the 2026 SPL Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $26.0 million during both the three and six months ended June 30, 2016. The 2026 SPL Senior Notes accrue interest at a fixed rate of 5.875% and interest on the 2026 SPL Senior Notes is payable semi-annually in arrears. The terms of the 2026 SPL Senior Notes are governed by the same common indenture as SPL’s other senior notes, which contains customary terms and events of default, covenants and redemption terms.

In connection with the closing of the sale of the 2026 SPL Senior Notes, SPL entered into a Registration Rights Agreement dated June 14, 2016 (the “2026 SPL Registration Rights Agreement”). Under the terms of the 2026 SPL Registration Rights Agreement, SPL has agreed, and any future guarantors of the 2026 SPL Senior Notes will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement within 360 days after June 14, 2016 with respect to an offer to exchange any and all of the 2026 SPL Senior Notes for a like aggregate principal amount of debt securities of SPL with terms identical in all material respects to the respective 2026 SPL Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), and that are registered under the Securities Act of 1933, as amended (the “Securities Act”). Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2026 SPL Senior Notes. SPL will be obligated to pay additional interest if it fails to comply with its obligation to register the 2026 SPL Senior Notes within the specified time period.

2024 CCH Senior Notes

In May 2016, CCH issued an aggregate principal amount of $1.25 billion of the 2024 CCH Senior Notes, which are jointly and severally guaranteed by its subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (“CCP GP”, and collectively with CCL and CCP, the “Guarantors”). Net proceeds of the offering of approximately $1.1 billion, after deducting commissions, fees and expenses and incremental interest required under the 2024 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 CCH Credit Facility, resulting in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $29.0 million during both the three and six months ended June 30, 2016. Borrowings under the 2024 CCH Senior Notes accrue interest at a fixed rate of 7.000%, and interest on the 2024 CCH Senior Notes is payable semi-annually in arrears.

The indenture governing the 2024 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 Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.

At any time prior to January 1, 2024, CCH may redeem all or a part of the 2024 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 on or after January 1, 2024 through the maturity date of June 30, 2024, redeem the 2024 CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2024 CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

In connection with the closing of the sale of the 2024 CCH Senior Notes, CCH and the Guarantors entered into a Registration Rights Agreement dated May 18, 2016 (the “CCH Registration Rights Agreement”). Under the terms of the CCH Registration Rights Agreement, CCH and the Guarantors have agreed, and any future guarantors of the 2024 CCH Senior Notes will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement within 360 days after May 18, 2016 with respect to an offer to exchange any and all of the 2024 CCH Senior Notes for a like aggregate principal amount of debt securities of CCH with terms identical in all material respects to the respective 2024 CCH Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), and that are registered under the Securities Act. Under specified circumstances, CCH and the Guarantors have also agreed, and any future guarantors of the 2024 CCH Senior Notes will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2024 CCH Senior Notes. CCH will be obligated to pay additional interest if it fails to comply with its obligation to register the 2024 CCH Senior Notes within the specified time period.

2016 CQP Credit Facilities

In February 2016, Cheniere Partners entered into the $2.8 billion2016 CQP Credit Facilities, which consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 millionCTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes.

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

Cheniere Partners incurred $48.7 million of debt issuance costs during the six months ended June 30, 2016, and will incur an additional $21.5 million of debt issuance costs when the SPLNG tranche is funded. The prepayment of the CTPL Term Loan resulted in a write-off of unamortized discount and debt issuance costs of $1.5 million during the six months ended June 30, 2016. Cheniere Partners pays a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the 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 2016 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 terms of the 2016 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 2016 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than: (1) SPL, (2) SPLNG until funding of its tranche term loan and (3) certain of the subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2016 (in thousands):

	2015 SPL Credit Facilities		SPL Working Capital Facility		2016 CQP Credit Facilities		2015 CCH Term Loan Facilities
Original facility size	$	4,600,000	$	1,200,000	$	2,800,000	$	8,403,714
Outstanding balance	832,695		—		450,000		2,730,340
Commitments terminated	1,287,305		—		—		1,050,660
Letters of credit issued	—		237,270		7,500		—
Available commitment	$	2,480,000	$	962,730	$	2,342,500	$	4,622,714
Interest rate	LIBOR plus 1.30% - 1.75% or base rate plus 1.75%		LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)		LIBOR plus 2.25% or base rate plus 1.25% (2)
Maturity date	Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date		December 31, 2020, with various terms for underlying loans		February 25, 2020, with principals due quarterly commencing on February 19, 2019		Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date

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

(2) There is a 0.25% step-up for both LIBOR and base rate loans following completion of the first two Trains of the CCL Project.

Convertible Notes

Below is a summary of our convertible notes outstanding as of June 30, 2016 (in thousands):

	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000,000		$	1,000,000		$	625,000
Debt component, net of discount	$	921,690		$	1,109,165		$	307,006
Equity component	$	203,892		$	—		$	194,082
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			March 1, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate	9.1		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (8)	4.9 years			4.3 years			28.7 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) 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 into our common stock.

Interest Expense

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Interest cost on convertible notes:
Interest per contractual rate	$	49,853		$	33,603		$	98,893		$	47,542
Amortization of debt discount	9,100			7,116			17,985			13,714
Amortization of debt issuance costs	1,254			601			2,405			615
Total interest cost related to convertible notes	60,207			41,320			119,283			61,871
Interest cost on other debt	255,853			199,911			490,069			359,998
Total interest cost	316,060			241,231			609,352			421,869
Capitalized interest	(210,093		)	(155,745		)	(427,048		)	(276,771		)
Total interest expense, net	$	105,967		$	85,486		$	182,304		$	145,098

Fair Value Disclosures

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

	June 30, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior Notes, net of premium or discount (1)	$	13,347,532	$	13,447,629	$	10,596,307	$	9,525,809
CTPL Term Loan, net of discount (2)	—		—		398,571		400,000
Credit facilities (2) (3)	4,028,254		4,028,254		3,573,000		3,573,000
2021 Cheniere Convertible Unsecured Notes, net of discount (4)	921,690		918,414		879,938		825,413
2025 CCH HoldCo II Convertible Senior Notes (4)	1,109,165		1,153,534		1,050,588		914,363
2045 Cheniere Convertible Senior Notes, net of discount (5)	307,006		356,250		305,938		331,919

(1) Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes; 2025 SPL Senior Notes; 2026 SPL Senior Notes; and 2024 CCH Senior Notes(collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the Senior Notes and other similar instruments.

(2) 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. 

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility, 2016 CQP Credit Facilities, 2015 CCH Credit Facility and Cheniere Marketing trade finance facilities.

(4) 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. 

(5) 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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Income Taxes

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

We are not presently a taxpayer for federal or state income tax purposes and have not recorded a provision for federal or state income taxes in any of the periods included in the accompanying Consolidated Financial Statements. However, we are presently a foreign taxpayer and have recorded a net benefit (provision) of $0.3 million and $0.5 million for the three months ended June 30, 2016 and 2015, respectively, and $(0.3) million and $(0.2) million for the six months ended June 30, 2016 and 2015, respectively, for foreign income taxes.

We experienced an ownership change within the provisions of Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of our net operating losses (“NOLs”) was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of our NOLs in full over the carryover period. We will continue to monitor trading activity in our shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize our existing tax NOL carryforwards.

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Share-Based Compensation

6 Months Ended

Jun. 30, 2016

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

Share-Based Compensation

SHARE-BASED COMPENSATION

We have granted stock, restricted stock, phantom units and options to purchase common stock to employees, outside directors and a consultant under the Amended and Restated 2003 Stock Incentive Plan, as amended (the “2003 Plan”), 2011 Incentive Plan, as amended (the “2011 Plan”), the 2015 Long-Term Cash Incentive Plan (the “2015 Plan”) and the 2015 Employee Inducement Incentive Plan (the “Inducement Plan”).

The 2003 Plan and 2011 Plan provide for the issuance of 21.0 million shares and 35.0 million shares, respectively, of our common stock that may be in the form of non-qualified stock options, incentive stock options, purchased stock, restricted (non-vested) stock, bonus (unrestricted) stock, stock appreciation rights, phantom units and other share-based performance awards deemed by the Compensation Committee of our Board of Directors (the “Compensation Committee”) to be consistent with the purposes of the 2003 Plan and 2011 Plan. As of June 30, 2016, all of the shares under the 2003 Plan have been granted and 26.8 million shares, net of cancellations, have been granted under the 2011 Plan. The 2015 Plan generally provides for cash-settled awards in the form of stock appreciation rights, phantom unit awards, performance unit awards, other-stock based awards and cash awards. As of June 30, 2016, 6.1 million phantom units have been granted under the 2015 Plan. The Inducement Plan provides for the issuance of up to 1.0 million shares of our common stock in the form of non-qualified stock options, restricted stock awards, stock appreciation rights, performance awards, phantom stock awards and other stock-based awards deemed by the Compensation Committee to provide us with an opportunity to attract employees. As of June 30, 2016, 0.2 million shares of restricted stock have been granted under the Inducement Plan.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Total share-based compensation	$	40,535		$	68,665		$	58,060		$	86,655
Capitalized share-based compensation	(4,982		)	(18,427		)	(6,336		)	(20,277		)
Total share-based compensation expense	$	35,553		$	50,238		$	51,724		$	66,378

Total share-based compensation expense for the three and six months ended June 30, 2016 includes $15.6 million and $22.1 million, respectively, related to employee separations. The total unrecognized compensation cost at June 30, 2016 relating to non-vested share-based compensation arrangements was $154.5 million, which is expected to be recognized over a weighted average period of 1.8 years.

We did not receive any proceeds from the exercise of stock options in the three and six months ended June 30, 2016 and received $0.9 million and $1.9 million in the three and six months ended June 30, 2015, respectively.

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Net Loss Per Share Attributable to Common Stockholders

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Net Loss Per Share Attributable to Common Stockholders

NET LOSS PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

Basic net 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 following table (in thousands, except for loss per share) reconciles basic and diluted weighted average common shares outstanding for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Weighted average common shares outstanding:
Basic	228,323			226,481			228,231			226,405
Dilutive common stock options and unvested stock (1)	—			—			—			—
Diluted	228,323			226,481			228,231			226,405
Basic and diluted net loss per share attributable to common stockholders	$	(1.31	)	$	(0.52	)	$	(2.71	)	$	(1.71	)

(1) Stock options and unvested stock of 7.1 million shares for each of the three and six months ended June 30, 2016 and 10.1 million shares for each of the three and six months ended June 30, 2015, representing securities that could potentially dilute basic EPS in the future, were not included in the diluted net loss per share computations because their effect would have been anti-dilutive. In addition, 16.0 million shares in aggregate for the three and six months ended June 30, 2016 and 15.5 million shares in aggregate for the three and six months ended June 30, 2015, issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes, were not included in the computation of diluted net loss per share because the computation of diluted net loss per share utilizing the “if-converted” method would be anti-dilutive. There were no shares included in the computation of diluted net loss per share for the 2025 CCH HoldCo II Convertible Senior Notes because non-market-based contingencies underlying the eligible conversion date have not been met as of June 30, 2016.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Cheniere has 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 June 30, 2016, are not recognized as liabilities.

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 Suit”). CLNGT asserted claims in the Texas 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 Suit moved to dismiss the suit for lack of subject matter jurisdiction. CLNGT has responded to that motion, and it remains pending before the court.

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 seeks $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, where it is pending as Civil Action No. 2:16-cv-03209-CJB-SS. On April 22, 2016, we and CLNGT filed a motion in the Louisiana Suit seeking (1) dismissal of all claims against us for lack of personal jurisdiction, (2) dismissal, stay, or transfer of the suit to the United States District Court for the Southern District of Texas in deference to the first-filed Texas Suit, and (3) alternatively, transfer of the suit for convenience of the parties and witnesses. On May 4, 2016, Parallax Enterprises filed a motion to remand the Louisiana Suit to state court. On June 6, 2016, the court granted our request to transfer the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was then transferred to the same judge before which the Texas Suit is pending.  Parallax Enterprises’ motion to remand the Louisiana Suit to Louisiana state court and our motion to dismiss the Louisiana Suit in deference to the first-filed Texas Suit remain pending. We do not expect that the resolution of this litigation will have a material adverse impact on our financial results.

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 June 30, 2016 and December 31, 2015, there were no liabilities recognized under these guarantee arrangements.

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Business Segment Information

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Business Segment Information

BUSINESS SEGMENT INFORMATION

We have two reportable segments: LNG terminal segment and LNG and natural gas marketing segment. We determine our reportable segments by identifying each segment that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the entities’ chief operating decision maker for purposes of resource allocation and performance assessment, and had discrete financial information. Revenues from external customers that were derived from customers outside of the United States were $28.7 million and $31.4 million for the three and six months ended June 30, 2016, respectively. We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

Our LNG terminal segment consists of the Sabine Pass and Corpus Christi LNG terminals. We own and operate the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast through our ownership interest in and management agreements with Cheniere Partners. We own 100% of the general partner interest in Cheniere Partners and 80.1% of the common shares of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners. We are also developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal near Corpus Christi, Texas.

Our LNG and natural gas marketing segment consists of LNG and natural gas marketing activities by Cheniere Marketing. Cheniere Marketing is developing a platform for LNG sales to international markets with professional staff based in the United States, United Kingdom, Singapore and Chile.

The following table (in thousands) summarizes revenues (losses) and income (loss) from operations for each of our reporting segments: 

	Segments
	LNG Terminal			LNG & Natural Gas Marketing			Corporate and Other (1)			Total Consolidation
Three Months Ended June 30, 2016
Revenues (losses) from external customers	$	150,977		$	43,969		$	(18,119	)	$	176,827
Intersegment revenues (losses) (2)	6			7,029			(7,035		)	—
Depreciation and amortization expense	26,711			306			5,764			32,781
Income (loss) from operations	10,115			(31,917		)	(54,652		)	(76,454		)
Interest expense, net of capitalized interest	(80,127		)	—			(25,840		)	(105,967		)
Loss before income taxes and non-controlling interest (3)	(210,561		)	(31,870		)	(92,856		)	(335,287		)
Share-based compensation	7,045			10,257			23,233			40,535
Expenditures for additions to long-lived assets	1,089,190			1,296			3,206			1,093,692
Three Months Ended June 30, 2015
Revenues (losses) from external customers	$	68,532		$	(706	)	$	199		$	68,025
Intersegment revenues (losses) (2)	491			6,354			(6,845		)	—
Depreciation and amortization expense	16,071			244			3,839			20,154
Loss from operations	(18,061		)	(26,367		)	(51,446		)	(95,874		)
Interest expense, net of capitalized interest	(59,465		)	—			(26,021		)	(85,486		)
Loss before income taxes and non-controlling interest (3)	(33,403		)	(26,816		)	(82,090		)	(142,309		)
Share-based compensation	25,778			6,052			36,835			68,665
Expenditures for additions to long-lived assets	3,944,191			1,400			20,874			3,966,465
Six Months Ended June 30, 2016
Revenues (losses) from external customers	$	216,528		$	46,673		$	(17,293	)	$	245,908
Intersegment revenues (losses) (2)	924			14,623			(15,547		)	—
Depreciation and amortization expense	44,684			621			11,565			56,870
Loss from operations	(2,434		)	(62,464		)	(102,115		)	(167,013		)
Interest expense, net of capitalized interest	(131,493		)	—			(50,811		)	(182,304		)
Loss before income taxes and non-controlling interest (3)	(451,532		)	(62,550		)	(169,563		)	(683,645		)
Share-based compensation	9,822			15,146			33,092			58,060
Expenditures for additions to long-lived assets	2,590,568			1,531			9,652			2,601,751
Six Months Ended June 30, 2015
Revenues (losses) from external customers	$	136,112		$	(44	)	$	326		$	136,394
Intersegment revenues (losses) (2)	594			13,371			(13,965		)	—
Depreciation and amortization expense	31,012			444			6,467			37,923
Loss from operations	(42,396		)	(31,550		)	(82,172		)	(156,118		)
Interest expense, net of capitalized interest	(102,310		)	—			(42,788		)	(145,098		)
Loss before income taxes and non-controlling interest (3)	(311,058		)	(32,206		)	(134,211		)	(477,475		)
Share-based compensation	28,917			10,087			47,651			86,655
Expenditures for additions to long-lived assets	4,534,436			2,114			49,655			4,586,205

(1) Includes corporate activities, business development, strategic activities and certain intercompany eliminations. These activities have been included in the corporate and other column.

(2) Intersegment revenues (losses) related to our LNG and natural gas marketing segment are primarily a result of international revenue allocations using a cost plus transfer pricing methodology. These LNG and natural gas marketing segment intersegment revenues (losses) are eliminated with intersegment revenues (losses) in our Consolidated Statements of Operations.

(3) Items to reconcile loss from operations and loss before income taxes and non-controlling interest include consolidated other income (expense) amounts as presented on our Consolidated Statements of Operations primarily related to our LNG terminal segment.

The following table (in thousands) shows total assets for each of our reporting segments: 

	June 30,		December 31,
	2016		2015
LNG Terminal	$	20,130,382	$	17,363,750
LNG & Natural Gas Marketing	540,454		550,896
Corporate and Other	766,015		894,407
Total Consolidation	$	21,436,851	$	18,809,053

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended June 30,
	2016		2015
Cash paid during the period for interest, net of amounts capitalized	$	59,260	$	46,165

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $472.4 million and $383.7 million as of June 30, 2016 and 2015, respectively.

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Recent Accounting Standards

6 Months Ended

Jun. 30, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards

RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by the Company as of June 30, 2016:

Standard	Description	Expected 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 amends 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. This guidance may be early adopted beginning January 1, 2017, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	This standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted.	December 31, 2016	The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a 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 must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	This standard primarily requires the recognition of excess tax benefits for share-based awards in the statement of operations and the classification of excess tax benefits as an operating activity within the statement of cash flows. The guidance also allows an entity to elect to account for forfeitures when they occur. This guidance may be early adopted, but all of the guidance must be adopted in the same period.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	These amendments primarily affect asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2016	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	These standards require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 11—Debt for additional disclosures.
ASU 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement	This standard clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. This guidance may be early adopted, and may be adopted as either retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date.	January 1, 2016	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

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. 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 had no effect on our overall consolidated financial position, operating results or cash flows.

In 2016, we started production at our natural gas liquefaction facilities at the Sabine Pass LNG terminal (the “SPL Project”). As a result, we introduced two new line items entitled “Cost of sales” and “Marketing expense”, and modified the components of activity included in “Operating and maintenance expense” and “General and administrative expense” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made to the prior periods. The components of these line items are as follows:

• Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the SPL Project, vessel chartering costs and other costs related to converting natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense. Also included in cost of sales are purchase and delivery costs of our LNG and natural gas marketing business incurred by Cheniere Marketing.

• Operating and maintenance expense now primarily includes costs associated with operating and maintaining the SPL Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs.

• Marketing expense includes costs directly associated with our LNG and natural gas marketing activities by Cheniere Marketing such as payroll and benefit costs of LNG marketing and origination personnel, professional services and other support costs to contract LNG customers throughout the global marketplace for the SPL Project and our second natural gas liquefaction and export facility at the Corpus Christi LNG terminal (the “CCL Project”) and to place volumes in the market for our portfolio. These costs were reclassified from general and administrative expense.

Additionally, we distinguished and reclassified our historical “LNG terminal revenues” line item into “regasification revenues” and “LNG revenues.”

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Restricted Cash (Tables)

6 Months Ended

Jun. 30, 2016

Cash and Cash Equivalents [Abstract]

Schedule of Restricted Cash

As of June 30, 2016 and December 31, 2015, restricted cash consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Current restricted cash
SPLNG debt service and interest payment	$	77,415	$	77,415
SPL Project	263,114		189,260
CTPL construction and interest payment	—		7,882
CQP and cash held by guarantor subsidiaries	109,977		—
CCL Project	223,117		46,770
Cash held by our subsidiaries restricted to Cheniere	12,821		147,138
Other	38,014		34,932
Total current restricted cash	$	724,458	$	503,397
Non-current restricted cash
SPLNG debt service	$	13,650	$	13,650
Other	18,076		18,072
Total non-current restricted cash	$	31,726	$	31,722

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Accounts and Other Receivables (Tables)

6 Months Ended

Jun. 30, 2016

Receivables [Abstract]

Schedule of Accounts and Other Receivables

As of June 30, 2016 and December 31, 2015, accounts and other receivables consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
SPL trade receivable	$	67,266	$	—
Interest receivable	259		95
Other accounts receivable	6,758		5,654
Total accounts and other receivables	$	74,283	$	5,749

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Inventory (Tables)

6 Months Ended

Jun. 30, 2016

Inventory Disclosure [Abstract]

Schedule of Inventory

As of June 30, 2016 and December 31, 2015, inventory consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Natural gas	$	5,338	$	5,724
LNG	35,526		5,148
Materials and other	25,458		7,253
Total inventory	$	66,322	$	18,125

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Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment consists of LNG terminal costs and fixed assets and other, as follows (in thousands):

	June 30,			December 31,
	2016			2015
LNG terminal costs
LNG terminal	$	5,459,151		$	2,487,759
LNG terminal construction-in-process	13,487,338			13,875,204
LNG site and related costs, net	38,753			33,512
Accumulated depreciation	(456,716		)	(413,545		)
Total LNG terminal costs, net	18,528,526			15,982,930
Fixed assets and other
Computer and office equipment	12,491			12,153
Furniture and fixtures	17,393			17,101
Computer software	76,471			69,340
Leasehold improvements	44,064			40,136
Land	60,582			60,612
Other	37,476			49,376
Accumulated depreciation	(47,826		)	(37,741		)
Total fixed assets and other, net	200,651			210,977
Property, plant and equipment, net	$	18,729,177		$	16,193,907

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

The following table (in thousands) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of June 30, 2016 and December 31, 2015, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	June 30, 2016											December 31, 2015
	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
SPL Interest Rate Derivatives liability	$	—		$	(20,666	)	$	—	$	(20,666	)	$	—	$	(8,740	)	$	—	$	(8,740	)
CQP Interest Rate Derivatives liability	—			(19,148		)	—		(19,148		)	—		—			—		—
CCH Interest Rate Derivatives liability	—			(327,342		)	—		(327,342		)	—		(104,999		)	—		(104,999		)
Liquefaction Supply Derivatives asset (liability)	(2,850		)	381			22,434		19,965			—		(25		)	32,492		32,467
LNG Trading Derivatives asset (liability)	(1,443		)	(10,907		)	—		(12,350		)	—		1,053			—		1,053
Natural Gas Derivatives liability	—			—			—		—			—		(66		)	—		(66		)
FX Derivatives asset	—			160			—		160			—		—			—		—

Fair Value Inputs, Assets, Quantitative Information

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2016:

	Net Fair Value Asset (in thousands)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$22,434	Income Approach	Basis Spread	$(0.35) - $(0.02)

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

The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
Balance, beginning of period	$	30,054		$	342	$	32,492		$	342
Realized and mark-to-market losses:
Included in cost of sales (1)	(7,855		)	27		(10,204		)	27
Purchases and settlements:
Purchases	(16		)	71		31			71
Settlements (1)	(71		)	—		(128		)	—
Transfers out of Level 3 (2)	322			—		243			—
Balance, end of period	$	22,434		$	440	$	22,434		$	440
Change in unrealized gains relating to instruments still held at end of period	$	(7,795	)	$	27	$	(9,484	)	$	27

(1) Does not include the decrease in fair value of $0.1 million and $0.7 million related to the realized gains capitalized during the three and six months ended June 30, 2016, respectively.

Derivative Net Presentation on Consolidated Balance Sheets

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

	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 June 30, 2016
SPL Interest Rate Derivatives	$	(20,666	)	$	—		$	(20,666	)
CQP Interest Rate Derivatives	(19,148		)	—			(19,148		)
CCH Interest Rate Derivatives	(327,342		)	—			(327,342		)
Liquefaction Supply Derivatives	23,165			(167		)	22,998
Liquefaction Supply Derivatives	(4,505		)	1,472			(3,033		)
LNG Trading Derivatives	475			—			475
LNG Trading Derivatives	(22,455		)	9,630			(12,825		)
FX Derivatives	860			(505		)	355
FX Derivatives	(376		)	181			(195		)
As of December 31, 2015
SPL Interest Rate Derivatives	$	(8,740	)	$	—		$	(8,740	)
CCH Interest Rate Derivatives	(104,999		)	—			(104,999		)
Liquefaction Supply Derivatives	33,636			(595		)	33,041
Liquefaction Supply Derivatives	(574		)	—			(574		)
LNG Trading Derivatives	1,922			(699		)	1,223
LNG Trading Derivatives	(2,826		)	2,656			(170		)
Natural Gas Derivatives	188			(254		)	(66		)

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of June 30, 2016, 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
SPL Interest Rate Derivatives	$20.0 million	$628.8 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
CQP Interest Rate Derivatives	$225.0 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR
CCH Interest Rate Derivatives	$28.8 million	$5.5 billion	May 20, 2015	May 31, 2022	2.29%	One-month LIBOR

Fair Value of Derivative Instruments by Balance Sheet Location

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

	June 30, 2016												December 31, 2015
	SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			CCH Interest Rate Derivatives			Total			SPL Interest Rate Derivatives			CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total
Balance Sheet Location
Derivative liabilities	$	(7,340	)	$	(5,570	)	$	(45,149	)	$	(58,059	)	$	(5,940	)	$	—	$	(28,559	)	$	(34,499	)
Non-current derivative liabilities	(13,326		)	(13,578		)	(282,193		)	(309,097		)	(2,800		)	—		(76,440		)	(79,240		)
Total derivative liabilities	$	(20,666	)	$	(19,148	)	$	(327,342	)	$	(367,156	)	$	(8,740	)	$	—	$	(104,999	)	$	(113,739	)

Derivative Instruments, Gain (Loss)

The following table (in thousands) 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 six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
SPL Interest Rate Derivatives gain (loss)	$	(4,752	)	$	1,469	$	(16,030	)	$	(35,669	)
CQP Interest Rate Derivatives loss	(10,040		)	—		(19,570		)	—
CCH Interest Rate Derivatives gain (loss)	(75,877		)	44,580		(236,053		)	(44,972		)

Commodity Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Instruments by Balance Sheet Location

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

	June 30, 2016											December 31, 2015
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Natural Gas Derivatives		Total			Liquefaction Supply Derivatives			LNG Trading Derivatives (2)			Natural Gas Derivatives (3)			Total
Balance Sheet Location
Other current assets	$	2,526		$	232		$	—	$	2,758		$	2,737		$	640		$	—		$	3,377
Non-current derivative assets	20,472			243			—		20,715			30,304			583			—			30,887
Total derivative assets	22,998			475			—		23,473			33,041			1,223			—			34,264
Derivative liabilities	(3,033		)	(10,778		)	—		(13,811		)	(490		)	(107		)	(66		)	(663		)
Non-current derivative liabilities	—			(2,047		)	—		(2,047		)	(84		)	(63		)	—			(147		)
Total derivative liabilities	(3,033		)	(12,825		)	—		(15,858		)	(574		)	(170		)	(66		)	(810		)
Derivative asset (liabilities), net	$	19,965		$	(12,350	)	$	—	$	7,615		$	32,467		$	1,053		$	(66	)	$	33,454

(1) Does not include collateral of $0.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of June 30, 2016.

(2) Does not include collateral of $15.6 million and $11.0 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015, respectively.

(3) Does not include collateral of $5.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

Derivative Instruments, Gain (Loss)

The following table (in thousands) 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 six months ended June 30, 2016 and 2015:

		Three Months Ended June 30,						Six Months Ended June 30,
	Statement of Operations Location	2016			2015			2016			2015
Liquefaction Supply Derivatives loss	LNG revenues (losses)	$	(34	)	$	—		$	(6	)	$	—
Liquefaction Supply Derivatives gain (loss) (1)	Cost of sales	(8,670		)	81			(12,264		)	81
LNG Trading Derivatives loss	LNG revenues (losses)	(16,976		)	—			(12,214		)	—
Natural Gas Derivatives gain (loss)	LNG revenues (losses)	—			67			(5		)	(98		)
Natural Gas Derivatives gain (loss)	Operating and maintenance expense	—			(294		)	174			460

(1)    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 (in thousands) shows the fair value and location of our FX Derivatives on our Consolidated Balance Sheets:

		Fair Value Measurements as of
	Balance Sheet Location	June 30, 2016			December 31, 2015
FX Derivatives	Other current assets	$	355		$	—
FX Derivatives	Derivative liabilities	(132		)	—
FX Derivatives	Non-current derivative liabilities	(63		)	—

Derivative Instruments, Gain (Loss)

The following table (in thousands) shows the changes in the fair value of our FX Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2016 and 2015:

		Three Months Ended June 30,					Six Months Ended June 30,
	Statement of Operations Location	2016			2015		2016			2015
FX Derivatives gain	LNG revenues (losses)	$	2,641		$	—	$	40		$	—
FX Derivatives gain	Derivative gain (loss), net	48			—		98			—
FX Derivatives loss	Other income (expense)	(87		)	—		(87		)	—

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Other Non-Current Assets (Tables)

6 Months Ended

Jun. 30, 2016

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

As of June 30, 2016 and December 31, 2015, other non-current assets consisted of the following (in thousands):

	June 30,		December 31,
	2016		2015
Advances made under EPC and non-EPC contracts	$	14,000	$	83,579
Advances made to municipalities for water system enhancements	95,584		89,953
Tax-related payments and receivables	29,351		31,712
Equity method investments	11,983		20,295
Other	100,540		88,916
Total other non-current assets	$	251,458	$	314,455

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Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2016

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

As of June 30, 2016 and December 31, 2015, accrued liabilities consisted of the following (in thousands): 

	June 30,		December 31,
	2016		2015
Interest costs and related debt fees	$	173,907	$	159,968
Compensation and benefits	69,975		99,511
SPL Project and CCL Project costs	326,788		145,759
LNG terminal costs	4,795		3,918
Other accrued liabilities	14,139		18,043
Total accrued liabilities	$	589,604	$	427,199

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Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Schedule of Debt Instruments

As of June 30, 2016 and December 31, 2015, our debt consisted of the following (in thousands): 

	June 30,			December 31,
	2016			2015
Long-term debt:
SPLNG
6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) (1)	$	420,000		$	420,000
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7,959 and $8,718	2,007,959			2,008,718
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000,000			1,000,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $6,029 and $6,392	1,506,029			1,506,392
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000,000			2,000,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000,000			2,000,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500,000			—
2015 SPL Credit Facilities	832,695			845,000
CTPL
$400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429	—			398,571
Cheniere Partners
2016 CQP Credit Facilities	450,000			—
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250,000			—
2015 CCH Credit Facility	2,730,340			2,713,000
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,109,165			1,050,588
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”), net of unamortized discount of $158,036 and $174,095	921,690			879,938
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”), net of unamortized discount of $317,994 and $319,062	307,006			305,938
Unamortized debt issuance costs (2)	(245,810		)	(207,718		)
Total long-term debt, net	17,789,074			14,920,427
Current debt:
7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of $1,956 and $4,303 (3)	1,663,544			1,661,197
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			15,000
Cheniere Marketing trade finance facilities	15,219			—
Unamortized debt issuance costs (2)	(1,287		)	(2,818		)
Total current debt, net	1,677,476			1,673,379
Total debt, net	$	19,466,550		$	16,593,806

(1) Must be redeemed or repaid concurrently with the 2016 SPLNG Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 SPLNG Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities.

(2) Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $207.8 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.

(3) Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2016 (in thousands):

	2015 SPL Credit Facilities		SPL Working Capital Facility		2016 CQP Credit Facilities		2015 CCH Term Loan Facilities
Original facility size	$	4,600,000	$	1,200,000	$	2,800,000	$	8,403,714
Outstanding balance	832,695		—		450,000		2,730,340
Commitments terminated	1,287,305		—		—		1,050,660
Letters of credit issued	—		237,270		7,500		—
Available commitment	$	2,480,000	$	962,730	$	2,342,500	$	4,622,714
Interest rate	LIBOR plus 1.30% - 1.75% or base rate plus 1.75%		LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)		LIBOR plus 2.25% or base rate plus 1.25% (2)
Maturity date	Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date		December 31, 2020, with various terms for underlying loans		February 25, 2020, with principals due quarterly commencing on February 19, 2019		Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date

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

(2) There is a 0.25% step-up for both LIBOR and base rate loans following completion of the first two Trains of the CCL Project.

Schedule of Convertible Debt

Below is a summary of our convertible notes outstanding as of June 30, 2016 (in thousands):

	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000,000		$	1,000,000		$	625,000
Debt component, net of discount	$	921,690		$	1,109,165		$	307,006
Equity component	$	203,892		$	—		$	194,082
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			March 1, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate	9.1		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (8)	4.9 years			4.3 years			28.7 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) 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 into our common stock.

Schedule of Interest Expense

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Interest cost on convertible notes:
Interest per contractual rate	$	49,853		$	33,603		$	98,893		$	47,542
Amortization of debt discount	9,100			7,116			17,985			13,714
Amortization of debt issuance costs	1,254			601			2,405			615
Total interest cost related to convertible notes	60,207			41,320			119,283			61,871
Interest cost on other debt	255,853			199,911			490,069			359,998
Total interest cost	316,060			241,231			609,352			421,869
Capitalized interest	(210,093		)	(155,745		)	(427,048		)	(276,771		)
Total interest expense, net	$	105,967		$	85,486		$	182,304		$	145,098

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	June 30, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior Notes, net of premium or discount (1)	$	13,347,532	$	13,447,629	$	10,596,307	$	9,525,809
CTPL Term Loan, net of discount (2)	—		—		398,571		400,000
Credit facilities (2) (3)	4,028,254		4,028,254		3,573,000		3,573,000
2021 Cheniere Convertible Unsecured Notes, net of discount (4)	921,690		918,414		879,938		825,413
2025 CCH HoldCo II Convertible Senior Notes (4)	1,109,165		1,153,534		1,050,588		914,363
2045 Cheniere Convertible Senior Notes, net of discount (5)	307,006		356,250		305,938		331,919

(1) Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes; 2025 SPL Senior Notes; 2026 SPL Senior Notes; and 2024 CCH Senior Notes(collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the Senior Notes and other similar instruments.

(2) 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. 

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility, 2016 CQP Credit Facilities, 2015 CCH Credit Facility and Cheniere Marketing trade finance facilities.

(4) 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. 

(5) 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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Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2016

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

Schedule of Share-based Compensation Expense, Net

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Total share-based compensation	$	40,535		$	68,665		$	58,060		$	86,655
Capitalized share-based compensation	(4,982		)	(18,427		)	(6,336		)	(20,277		)
Total share-based compensation expense	$	35,553		$	50,238		$	51,724		$	66,378

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Net Loss Per Share Attributable to Common Stockholders (Tables)

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The following table (in thousands, except for loss per share) reconciles basic and diluted weighted average common shares outstanding for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Weighted average common shares outstanding:
Basic	228,323			226,481			228,231			226,405
Dilutive common stock options and unvested stock (1)	—			—			—			—
Diluted	228,323			226,481			228,231			226,405
Basic and diluted net loss per share attributable to common stockholders	$	(1.31	)	$	(0.52	)	$	(2.71	)	$	(1.71	)

(1) Stock options and unvested stock of 7.1 million shares for each of the three and six months ended June 30, 2016 and 10.1 million shares for each of the three and six months ended June 30, 2015, representing securities that could potentially dilute basic EPS in the future, were not included in the diluted net loss per share computations because their effect would have been anti-dilutive. In addition, 16.0 million shares in aggregate for the three and six months ended June 30, 2016 and 15.5 million shares in aggregate for the three and six months ended June 30, 2015, issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes, were not included in the computation of diluted net loss per share because the computation of diluted net loss per share utilizing the “if-converted” method would be anti-dilutive. There were no shares included in the computation of diluted net loss per share for the 2025 CCH HoldCo II Convertible Senior Notes because non-market-based contingencies underlying the eligible conversion date have not been met as of June 30, 2016.

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Business Segment Information (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

The following table (in thousands) summarizes revenues (losses) and income (loss) from operations for each of our reporting segments: 

	Segments
	LNG Terminal			LNG & Natural Gas Marketing			Corporate and Other (1)			Total Consolidation
Three Months Ended June 30, 2016
Revenues (losses) from external customers	$	150,977		$	43,969		$	(18,119	)	$	176,827
Intersegment revenues (losses) (2)	6			7,029			(7,035		)	—
Depreciation and amortization expense	26,711			306			5,764			32,781
Income (loss) from operations	10,115			(31,917		)	(54,652		)	(76,454		)
Interest expense, net of capitalized interest	(80,127		)	—			(25,840		)	(105,967		)
Loss before income taxes and non-controlling interest (3)	(210,561		)	(31,870		)	(92,856		)	(335,287		)
Share-based compensation	7,045			10,257			23,233			40,535
Expenditures for additions to long-lived assets	1,089,190			1,296			3,206			1,093,692
Three Months Ended June 30, 2015
Revenues (losses) from external customers	$	68,532		$	(706	)	$	199		$	68,025
Intersegment revenues (losses) (2)	491			6,354			(6,845		)	—
Depreciation and amortization expense	16,071			244			3,839			20,154
Loss from operations	(18,061		)	(26,367		)	(51,446		)	(95,874		)
Interest expense, net of capitalized interest	(59,465		)	—			(26,021		)	(85,486		)
Loss before income taxes and non-controlling interest (3)	(33,403		)	(26,816		)	(82,090		)	(142,309		)
Share-based compensation	25,778			6,052			36,835			68,665
Expenditures for additions to long-lived assets	3,944,191			1,400			20,874			3,966,465
Six Months Ended June 30, 2016
Revenues (losses) from external customers	$	216,528		$	46,673		$	(17,293	)	$	245,908
Intersegment revenues (losses) (2)	924			14,623			(15,547		)	—
Depreciation and amortization expense	44,684			621			11,565			56,870
Loss from operations	(2,434		)	(62,464		)	(102,115		)	(167,013		)
Interest expense, net of capitalized interest	(131,493		)	—			(50,811		)	(182,304		)
Loss before income taxes and non-controlling interest (3)	(451,532		)	(62,550		)	(169,563		)	(683,645		)
Share-based compensation	9,822			15,146			33,092			58,060
Expenditures for additions to long-lived assets	2,590,568			1,531			9,652			2,601,751
Six Months Ended June 30, 2015
Revenues (losses) from external customers	$	136,112		$	(44	)	$	326		$	136,394
Intersegment revenues (losses) (2)	594			13,371			(13,965		)	—
Depreciation and amortization expense	31,012			444			6,467			37,923
Loss from operations	(42,396		)	(31,550		)	(82,172		)	(156,118		)
Interest expense, net of capitalized interest	(102,310		)	—			(42,788		)	(145,098		)
Loss before income taxes and non-controlling interest (3)	(311,058		)	(32,206		)	(134,211		)	(477,475		)
Share-based compensation	28,917			10,087			47,651			86,655
Expenditures for additions to long-lived assets	4,534,436			2,114			49,655			4,586,205

(1) Includes corporate activities, business development, strategic activities and certain intercompany eliminations. These activities have been included in the corporate and other column.

(2) Intersegment revenues (losses) related to our LNG and natural gas marketing segment are primarily a result of international revenue allocations using a cost plus transfer pricing methodology. These LNG and natural gas marketing segment intersegment revenues (losses) are eliminated with intersegment revenues (losses) in our Consolidated Statements of Operations.

(3) Items to reconcile loss from operations and loss before income taxes and non-controlling interest include consolidated other income (expense) amounts as presented on our Consolidated Statements of Operations primarily related to our LNG terminal segment.

The following table (in thousands) shows total assets for each of our reporting segments: 

	June 30,		December 31,
	2016		2015
LNG Terminal	$	20,130,382	$	17,363,750
LNG & Natural Gas Marketing	540,454		550,896
Corporate and Other	766,015		894,407
Total Consolidation	$	21,436,851	$	18,809,053

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Six Months Ended June 30,
	2016		2015
Cash paid during the period for interest, net of amounts capitalized	$	59,260	$	46,165

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Recent Accounting Standards (Tables)

6 Months Ended

Jun. 30, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards, Not Yet Adopted

The following table provides a brief description of recent accounting standards that had not been adopted by the Company as of June 30, 2016:

Standard	Description	Expected 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 amends 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. This guidance may be early adopted beginning January 1, 2017, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	This standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted.	December 31, 2016	The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a 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 must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	This standard primarily requires the recognition of excess tax benefits for share-based awards in the statement of operations and the classification of excess tax benefits as an operating activity within the statement of cash flows. The guidance also allows an entity to elect to account for forfeitures when they occur. This guidance may be early adopted, but all of the guidance must be adopted in the same period.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

Recent Accounting Standards, Adopted

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	These amendments primarily affect asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2016	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	These standards require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 11—Debt for additional disclosures.
ASU 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement	This standard clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. This guidance may be early adopted, and may be adopted as either retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date.	January 1, 2016	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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Basis of Presentation (Details) - customer	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016
Customer Concentration Risk [Member] | LNG Revenues [Member] | LNG terminal business [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	74.00%	72.00%
TUA Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Number Of Significant Customers		2
SPA Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Number Of Significant Customers		1

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Restricted Cash (Details)	6 Months Ended
	Jun. 30, 2016 USD ($) Rate item	Jun. 30, 2015 USD ($)	Feb. 29, 2016 USD ($)	Dec. 31, 2015 USD ($)
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 724,458,000			$ 503,397,000
Non-current restricted cash	31,726,000			31,722,000
SPLNG debt service and interest payment [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	77,415,000			77,415,000
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	263,114,000			189,260,000
CTPL construction and interest payment [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	0			7,882,000
CQP And Cash Held By Guarantor Subsidiaries [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	109,977,000			0
CCL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	223,117,000			46,770,000
Cash held by our subsidiaries restricted to Cheniere [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	12,821,000			147,138,000
Other [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	38,014,000			34,932,000
Non-current restricted cash	18,076,000			18,072,000
SPLNG debt service [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Non-current restricted cash	13,650,000			$ 13,650,000
SPLNG [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Partners' Capital Account, Distributions	$ 145,300,000	$ 199,600,000
SPLNG [Member] | SPLNG Senior Notes [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Debt Instrument, Number of Months Interest Required For Distribution Per Month Elapsed Since Last Interest Payment | item	1
Debt Instrument, Number of Semi-Annual Interest Payments Required To Be On Deposit In Permanent Debt Service Fund For Distribution | item	1
Debt Instrument, Fixed Charge, Coverage Ratio | Rate	2
Cheniere Partners [Member] | 2016 CQP Credit Facilities [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 2,800,000,000.0

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Accounts and Other Receivables (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Receivables [Abstract]
SPL trade receivable	$ 67,266	$ 0
Interest receivable	259	95
Other accounts receivable	6,758	5,654
Total accounts and other receivables	$ 74,283	$ 5,749

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Inventory (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Inventory [Line Items]
Inventory	$ 66,322	$ 18,125
Natural gas [Member]
Inventory [Line Items]
Inventory	5,338	5,724
LNG [Member]
Inventory [Line Items]
Inventory	35,526	5,148
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 25,458	$ 7,253

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Property, Plant and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 18,729,177	$ 18,729,177	$ 16,193,907
Property, plant and equipment, reduction for testing costs recovered	131,800	146,000
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(456,716)	(456,716)	(413,545)
Property, plant and equipment, net	18,528,526	18,528,526	15,982,930
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	5,459,151	5,459,151	2,487,759
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	13,487,338	13,487,338	13,875,204
LNG site and related costs, net [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	38,753	38,753	33,512
Fixed assets and other [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(47,826)	(47,826)	(37,741)
Property, plant and equipment, net	200,651	200,651	210,977
Computer and office equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	12,491	12,491	12,153
Furniture and fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	17,393	17,393	17,101
Computer software [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	76,471	76,471	69,340
Leasehold improvements [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	44,064	44,064	40,136
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	60,582	60,582	60,612
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 37,476	$ 37,476	$ 49,376

XML

Derivative Instruments - Narrative (Details) MMBTU in Millions, $ in Millions	1 Months Ended		6 Months Ended
	May 31, 2015 USD ($)	Mar. 31, 2015 USD ($)	Jun. 30, 2016 USD ($) MMBTU
SPL Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount			$ 20.0
SPL Interest Rate Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount			628.8
CCH Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount			28.8
CCH Interest Rate Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount			$ 5,500.0
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU			1,114.5
Liquefaction Supply Derivatives [Member] | Minimum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract			1 year
Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract			7 years
LNG Trading Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount			$ 0.8
Derivative, Nonmonetary Notional Amount | MMBTU			18.2
SPL [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Energy Units Secured Through Long-Term Purchase Agreements | MMBTU			2,027.5
SPL [Member] | SPL Previous Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease, Net		$ 1,800.0
SPL [Member] | SPL Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Loss, Net		$ 34.7
CCH [Member] | CCH Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract			7 years
Derivative, Cost of Hedge	$ 50.1
Cheniere Marketing [Member] | FX Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount			$ 102.1

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
SPL Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (20,666)	$ (8,740)
SPL 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
SPL 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	(20,666)	(8,740)
SPL 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
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	(19,148)	0
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	(19,148)	0
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	(327,342)	(104,999)
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	(327,342)	(104,999)
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	19,965	32,467
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	(2,850)	0
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	381	(25)
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	22,434	32,492
LNG Trading Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(12,350)	1,053
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	(1,443)	0
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	(10,907)	1,053
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
Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	(66)
Natural Gas 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
Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	(66)
Natural Gas 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	160	0
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	160	0
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] - USD ($)	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Net Fair Value Asset	$ 19,965,000	$ 32,467,000
Fair Value, Inputs, Level 3 [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Net Fair Value Asset	$ 22,434,000	$ 32,492,000
Valuation Technique	Income Approach
Significant Unobservable Input	Basis Spread
Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Significant Unobservable Inputs Range	$ (0.350)
Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Significant Unobservable Inputs Range	$ (0.020)

XML

Derivative Instruments - Schedule of Level 3 Derivatives Activity (Details) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ 30,054	$ 342	$ 32,492	$ 342
Realized and mark-to-market losses:
Included in cost of sales	[1]	(7,855)	27	(10,204)	27
Purchases and settlements:
Purchases		(16)	71	31	71
Settlements	[1]	(71)	0	(128)	0
Transfers out of Level 3	[2]	322	0	243	0
Balance, end of period		22,434	440	22,434	440
Change in unrealized gains relating to instruments still held at end of period		(7,795)	$ 27	(9,484)	$ 27
Decrease in Fair Value Realized and Capitalized During Period		$ 100		$ 700

[1] Does not include the decrease in fair value of $0.1 million and $0.7 million related to the realized gains capitalized during the three and six months ended June 30, 2016, respectively.

[2] 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	6 Months Ended
	Jun. 30, 2016 USD ($)
SPL Interest Rate Derivatives [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 20.0
Effective Date	Aug. 14, 2012
Maturity Date	Jul. 31, 2019
Weighted Average Fixed Interest Rate Paid	1.98%
Variable Interest Rate Received	One-month LIBOR
SPL Interest Rate Derivatives [Member] | Maximum [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 628.8
CQP Interest Rate Derivatives [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 225.0
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 of Interest Rate Derivatives	$ 1,300.0
CCH Interest Rate Derivatives [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 28.8
Effective Date	May 20, 2015
Maturity Date	May 31, 2022
Weighted Average Fixed Interest Rate Paid	2.29%
Variable Interest Rate Received	One-month LIBOR
CCH Interest Rate Derivatives [Member] | Maximum [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 5,500.0

XML

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Thousands		Jun. 30, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Non-current derivative assets		$ 20,715		$ 30,887
Derivative liabilities		(72,002)		(35,201)
Non-current derivative liabilities		(311,207)		(79,387)
Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities		(367,156)		(113,739)
Interest Rate Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(58,059)		(34,499)
Interest Rate Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		(309,097)		(79,240)
SPL Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities		(20,666)		(8,740)
SPL Interest Rate Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(7,340)		(5,940)
SPL Interest Rate Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		(13,326)		(2,800)
CQP Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities		(19,148)		0
CQP Interest Rate Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(5,570)		0
CQP Interest Rate Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		(13,578)		0
CCH Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities		(327,342)		(104,999)
CCH Interest Rate Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(45,149)		(28,559)
CCH Interest Rate Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		(282,193)		(76,440)
Commodity Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		23,473		34,264
Total derivative liabilities		(15,858)		(810)
Derivative asset (liability), net		7,615		33,454
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets		2,758		3,377
Commodity Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		20,715		30,887
Commodity Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(13,811)		(663)
Commodity Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		(2,047)		(147)
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		22,998	[1]	33,041
Total derivative liabilities		(3,033)	[1]	(574)
Derivative asset (liability), net		19,965	[1]	32,467
Liquefaction Supply Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets		2,526	[1]	2,737
Derivative, Collateral, Right to Reclaim Cash		500
Liquefaction Supply Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		20,472	[1]	30,304
Liquefaction Supply Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(3,033)	[1]	(490)
Liquefaction Supply Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0	[1]	(84)
LNG Trading Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[2]	475		1,223
Total derivative liabilities	[2]	(12,825)		(170)
Derivative asset (liability), net	[2]	(12,350)		1,053
LNG Trading Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets	[2]	232		640
Derivative, Collateral, Right to Reclaim Cash		15,600		11,000
LNG Trading Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[2]	243		583
LNG Trading Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[2]	(10,778)		(107)
LNG Trading Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[2]	(2,047)		(63)
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		0		0	[3]
Total derivative liabilities		0		(66)	[3]
Derivative asset (liability), net		0		(66)	[3]
Natural Gas Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets		0		0	[3]
Derivative, Collateral, Right to Reclaim Cash				5,500
Natural Gas Derivatives [Member] | Non-current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		0		0	[3]
Natural Gas Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		0		(66)	[3]
Natural Gas Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0		0	[3]
FX Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets		355		0
FX Derivatives [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(132)		0
FX Derivatives [Member] | Non-current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		$ (63)		$ 0

[1] Does not include collateral of $0.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of June 30, 2016.

[2] Does not include collateral of $15.6 million and $11.0 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015, respectively.

[3] Does not include collateral of $5.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

XML

Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
SPL Interest Rate Derivatives [Member] | Derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ (4,752)	$ 1,469	$ (16,030)	$ (35,669)
CQP Interest Rate Derivatives [Member] | Derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(10,040)	0	(19,570)	0
CCH Interest Rate Derivatives [Member] | Derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(75,877)	44,580	(236,053)	(44,972)
Liquefaction Supply Derivatives [Member] | LNG revenues (losses) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(34)	0	(6)	0
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	[1]	(8,670)	81	(12,264)	81
LNG Trading Derivatives [Member] | LNG revenues (losses) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(16,976)	0	(12,214)	0
Natural Gas Derivatives [Member] | LNG revenues (losses) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		0	67	(5)	(98)
Natural Gas Derivatives [Member] | Operating and maintenance expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		0	(294)	174	460
FX Derivatives [Member] | Derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		48	0	98	0
FX Derivatives [Member] | LNG revenues (losses) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		2,641	0	40	0
FX Derivatives [Member] | Other income (expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ (87)	$ 0	$ (87)	$ 0

[1] 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 Thousands	Jun. 30, 2016	Dec. 31, 2015
SPL Interest Rate Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	$ (20,666)	$ (8,740)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	0	0
Derivative Assets (Liabilities), at Fair Value, Net	(20,666)	(8,740)
CQP Interest Rate Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(19,148)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	0
Derivative Assets (Liabilities), at Fair Value, Net	(19,148)
CCH Interest Rate Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(327,342)	(104,999)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	0	0
Derivative Assets (Liabilities), at Fair Value, Net	(327,342)	(104,999)
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	23,165	33,636
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(167)	(595)
Derivative Assets (Liabilities), at Fair Value, Net	22,998	33,041
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(4,505)	(574)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	1,472	0
Derivative Assets (Liabilities), at Fair Value, Net	(3,033)	(574)
LNG Trading Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	475	1,922
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	0	(699)
Derivative Assets (Liabilities), at Fair Value, Net	475	1,223
LNG Trading Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(22,455)	(2,826)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	9,630	2,656
Derivative Assets (Liabilities), at Fair Value, Net	(12,825)	(170)
Foreign Exchange Contract Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	860
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(505)
Derivative Assets (Liabilities), at Fair Value, Net	355
Foreign Exchange Contract Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(376)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	181
Derivative Assets (Liabilities), at Fair Value, Net	$ (195)
Natural Gas Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		188
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		(254)
Derivative Assets (Liabilities), at Fair Value, Net		$ (66)

XML

Other Non-Current Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Other Assets, Noncurrent [Abstract]
Advances made under EPC and non-EPC contracts	$ 14,000	$ 83,579
Advances made to municipalities for water system enhancements	95,584	89,953
Tax-related payments and receivables	29,351	31,712
Equity method investments	11,983	20,295
Other	100,540	88,916
Other non-current assets	$ 251,458	$ 314,455

XML

Variable Interest Entity (Details) - Cheniere Holdings [Member]	Jun. 30, 2016	Dec. 31, 2015
Variable Interest Entity [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	80.10%	80.10%
Ownership Percentage of Outstanding Shares Required To Control Company [Member]
Variable Interest Entity [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	25.00%

XML

Non-Controlling Interest (Details) - shares shares in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Cheniere Holdings [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	80.10%	80.10%
Cheniere Partners [Member]
Noncontrolling Interest [Line Items]
General Partner ownership percentage	100.00%
Cheniere Holdings [Member] | Cheniere Partners [Member]
Noncontrolling Interest [Line Items]
Limited Partner ownership percentage	55.90%
Common Units [Member] | Cheniere Holdings [Member] | Cheniere Partners [Member]
Noncontrolling Interest [Line Items]
Partners Capital Account, Units, Units Held	12.0
Class B Units [Member] | Cheniere Holdings [Member] | Cheniere Partners [Member]
Noncontrolling Interest [Line Items]
Partners Capital Account, Units, Units Held	45.3
Subordinated Units [Member] | Cheniere Holdings [Member] | Cheniere Partners [Member]
Noncontrolling Interest [Line Items]
Partners Capital Account, Units, Units Held	135.4

XML

Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 173,907	$ 159,968
Compensation and benefits	69,975	99,511
SPL Project and CCL Project costs	326,788	145,759
LNG terminal costs	4,795	3,918
Other accrued liabilities	14,139	18,043
Total accrued liabilities	$ 589,604	$ 427,199

XML

Debt - Schedule of Debt Instruments (Details) - USD ($)		Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 17,789,074,000	$ 14,920,427,000
Unamortized Debt Issuance Costs, Noncurrent	[1]	(245,810,000)	(207,718,000)
Current debt, net		1,677,476,000	1,673,379,000
Unamortized Debt Issuance Costs, Current	[1]	(1,287,000)	(2,818,000)
Total Debt, Net		19,466,550,000	16,593,806,000
2020 SPLNG Senior Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net	[2]	$ 420,000,000	420,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.50%
2021 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 2,007,959,000	2,008,718,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
Debt Instrument, Unamortized Premium		$ 7,959,000	8,718,000
2022 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 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, Net		$ 1,506,029,000	1,506,392,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
Debt Instrument, Unamortized Premium		$ 6,029,000	6,392,000
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 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, Net		$ 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, Net		$ 1,500,000,000	0
Debt Instrument, Interest Rate, Stated Percentage		5.875%
2015 SPL Credit Facilities [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 832,695,000	845,000,000
CTPL Term Loan [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		0	398,571,000
Line of Credit Facility, Maximum Borrowing Capacity			400,000,000.0
Debt Instrument, Unamortized Discount		0	1,429,000
2016 CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		450,000,000	0
2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 1,250,000,000	0
Debt Instrument, Interest Rate, Stated Percentage		7.00%
2015 CCH Credit Facility [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 2,730,340,000	2,713,000,000
2025 CCH Holdco II Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 1,109,165,000	1,050,588,000
Debt Instrument, Interest Rate, Stated Percentage		11.00%
2021 Cheniere Convertible Unsecured Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 921,690,000	879,938,000
Debt Instrument, Interest Rate, Stated Percentage		4.875%
Debt Instrument, Unamortized Discount		$ 158,036,000	174,095,000
2045 Cheniere Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt, Net		$ 307,006,000	305,938,000
Debt Instrument, Interest Rate, Stated Percentage		4.25%
Debt Instrument, Unamortized Discount		$ 317,994,000	319,062,000
2016 SPLNG Senior Notes [Member]
Debt Instrument [Line Items]
Current debt, net	[3]	$ 1,663,544,000	1,661,197,000
Debt Instrument, Interest Rate, Stated Percentage		7.50%
Debt Instrument, Unamortized Discount		$ 1,956,000	4,303,000
SPL Working Capital Facility [Member]
Debt Instrument [Line Items]
Current debt, net		0	15,000,000
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		$ 15,219,000	$ 0

[1] Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $207.8 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.

[2] Must be redeemed or repaid concurrently with the 2016 SPLNG Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 SPLNG Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities.

[3] Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities.

XML

Debt - Debt Issuances and Redemptions - Senior Notes (Details) - USD ($)	1 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2016	May 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Debt Instrument [Line Items]
Loss on early extinguishment of debt			$ 55,315,000	$ 7,281,000	$ 56,772,000	$ 96,273,000
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.875%		5.875%		5.875%
2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.00%		7.00%		7.00%
SPL [Member] | 2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 1,500,000,000.0		$ 1,500,000,000.0		$ 1,500,000,000.0
Proceeds from issuances of debt	$ 1,300,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.875%		5.875%		5.875%
Debt Instrument Registration Period					360 days
SPL [Member] | 2015 SPL Credit Facilities [Member]
Debt Instrument [Line Items]
Loss on early extinguishment of debt			$ 26,000,000		$ 26,000,000
CCH [Member] | 2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount		$ 1,250,000,000.00
Proceeds from issuances of debt		$ 1,100,000,000
Debt Instrument, Interest Rate, Stated Percentage	7.00%		7.00%		7.00%
Debt Instrument, Redemption Price, Percentage					100.00%
Debt Instrument Registration Period					360 days
CCH [Member] | 2015 CCH Credit Facility [Member]
Debt Instrument [Line Items]
Loss on early extinguishment of debt			$ 29,000,000		$ 29,000,000

XML

Debt - Debt Issuances and Redemptions - Credit Facilities (Details)		1 Months Ended	3 Months Ended		6 Months Ended
		Feb. 29, 2016 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) Rate	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Line of Credit Facility [Line Items]
Debt Instrument, Description of Variable Rate Basis					LIBOR or the base rate
Loss on early extinguishment of debt			$ 55,315,000	$ 7,281,000	$ 56,772,000	$ 96,273,000
2016 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Description of Variable Rate Basis	[1]				LIBOR or base rate
2016 CQP Credit Facilities [Member] | February 25, 2019 [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase					0.50%
2016 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%
2016 CQP Credit Facilities [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]				1.25%
CTPL Term Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 400,000,000.0
Cheniere Partners [Member] | 2016 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 2,800,000,000.0
Debt Instrument, Balance Required in Reserve Account, Period of Debt Service					6 months
Debt Issuance Costs, Net			$ 48,700,000		$ 48,700,000
Line of Credit Facility, Commitment Fee Percentage					40.00%
Debt Instrument, Fixed Charge, Coverage Ratio, Projected | Rate					1.55
Cheniere Partners [Member] | 2016 CQP Credit Facilities [Member] | February 25, 2019 [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase					0.50%
Cheniere Partners [Member] | 2016 CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					2.25%
Cheniere Partners [Member] | 2016 CQP Credit Facilities [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					1.25%
Cheniere Partners [Member] | 2016 CQP Credit Facilities [Member] | Base Rate [Member] | Base Rate Determination Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					0.50%
Cheniere Partners [Member] | 2016 CQP Credit Facilities [Member] | Base Rate [Member] | Base Rate Determination LIBOR [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate					1.00%
Cheniere Partners [Member] | 2016 CQP Credit Facilities [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives			50.00%		50.00%
Debt Instrument, Fixed Charge, Coverage Ratio | Rate					1.15
Cheniere Partners [Member] | 2016 CQP Credit Facilities - CTPL Tranche Term Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 450,000,000.0		$ 450,000,000.0
Cheniere Partners [Member] | 2016 CQP Credit Facilities - SPLNG Tranche Term Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			2,100,000,000		2,100,000,000
Debt Issuance Costs, Net			21,500,000		21,500,000
Cheniere Partners [Member] | 2016 CQP Credit Facilities - Debt Service Reserve Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			125,000,000.0		125,000,000.0
Cheniere Partners [Member] | 2016 CQP Credit Facilities - Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			115,000,000.0		$ 115,000,000.0
Cheniere Partners [Member] | 2016 CQP Credit Facilities - Letter of Credit [Member] | Portion issued and not drawn [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage					2.25%
Cheniere Partners [Member] | 2016 CQP Credit Facilities - Letter of Credit [Member] | Portion issued and not drawn [Member] | February 25, 2019 [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase					0.50%
Cheniere Partners [Member] | CTPL Term Loan [Member]
Line of Credit Facility [Line Items]
Repayments of Long-term Debt		$ 400,000,000.0
Loss on early extinguishment of debt					$ 1,500,000
Cheniere Partners [Member] | SPLNG Senior Notes [Member]
Line of Credit Facility [Line Items]
Aggregate principal amount			$ 2,100,000,000		$ 2,100,000,000

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

XML

Debt - Credit Facilities (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Outstanding balance		$ 17,789,074	$ 14,920,427
Outstanding balance - current		$ 1,677,476	1,673,379
Debt Instrument, Description of Variable Rate Basis		LIBOR or the base rate
2015 SPL Credit Facilities [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 4,600,000
Outstanding balance		832,695	845,000
Commitments terminated		1,287,305
Letters of credit issued		0
Available commitment		$ 2,480,000
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date
2015 SPL Credit Facilities [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
2015 SPL Credit Facilities [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.30%
2015 SPL Credit Facilities [Member] | Maximum [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]
Line of Credit Facility [Line Items]
Original facility size		$ 1,200,000
Outstanding balance - current		0	15,000
Commitments terminated		0
Letters of credit issued		237,270
Available commitment		$ 962,730
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%
2016 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 2,800,000
Outstanding balance		450,000	0
Commitments terminated		0
Letters of credit issued		7,500
Available commitment		$ 2,342,500
Debt Instrument, Description of Variable Rate Basis	[1]	LIBOR or base rate
Debt Instrument, Maturity Date, Description		February 25, 2020, with principals due quarterly commencing on February 19, 2019
2016 CQP Credit Facilities [Member] | February 25, 2019 [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase		0.50%
2016 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%
2016 CQP Credit Facilities [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]	1.25%
2015 CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 8,403,714
Outstanding balance		2,730,340	$ 2,713,000
Commitments terminated		1,050,660
Letters of credit issued		0
Available commitment		$ 4,622,714
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR or base rate
Debt Instrument, Maturity Date, Description		Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date
2015 CCH Credit Facility [Member] | Completion Of First Two Trains [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase		0.25%
2015 CCH Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	2.25%
2015 CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	1.25%

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

[2] There is a 0.25% step-up for both LIBOR and base rate loans following completion of the first two Trains of the CCL Project.

XML

Debt - Convertible Notes (Details)	6 Months Ended
	Jun. 30, 2016 USD ($) $ / shares
2021 Cheniere Convertible Unsecured Notes [Member]
Debt Instrument [Line Items]
Aggregate original principal	$ 1,000,000,000
Debt component, net of discount	921,690,000
Equity component	203,892,000
Conversion value in excess of principal	$ 0
Maturity date	May 28, 2021
Contractual interest rate	4.875%
Effective interest rate	9.10%
Remaining debt discount and debt issuance costs amortization period	4 years 333 days	[1]
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	1,109,165,000
Equity component	0
Conversion value in excess of principal	$ 0
Maturity date	Mar. 01, 2025
Contractual interest rate	11.00%
Effective interest rate	11.90%
Remaining debt discount and debt issuance costs amortization period	4 years 93 days	[1]
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, Threshold Consecutive Trading Days	90 days
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, Threshold Consecutive Trading Days	90 days
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	307,006,000
Equity component	194,082,000
Conversion value in excess of principal	$ 0
Maturity date	Mar. 15, 2045
Contractual interest rate	4.25%
Effective interest rate	9.40%
Remaining debt discount and debt issuance costs amortization period	28 years 265 days	[1]
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] 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 into our common stock.

XML

Debt - Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Debt Instrument [Line Items]
Total interest cost	$ 316,060	$ 241,231	$ 609,352	$ 421,869
Capitalized interest	(210,093)	(155,745)	(427,048)	(276,771)
Total interest expense, net	105,967	85,486	182,304	145,098
Convertible Debt [Member]
Debt Instrument [Line Items]
Interest per contractual rate	49,853	33,603	98,893	47,542
Amortization of debt discount	9,100	7,116	17,985	13,714
Amortization of debt issuance costs	1,254	601	2,405	615
Total interest cost	60,207	41,320	119,283	61,871
Debt Excluding Convertible Debt [Member]
Debt Instrument [Line Items]
Total interest cost	$ 255,853	$ 199,911	$ 490,069	$ 359,998

XML

Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 19,466,550	$ 16,593,806
Senior Notes, net of premium or discount [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	13,347,532	10,596,307
Senior Notes, net of premium or discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	13,447,629	9,525,809
CTPL Term Loan, net of discount [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	0	398,571
CTPL Term Loan, net of discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
CTPL Term Loan, Estimated Fair Value	[2]	0	400,000
Credit Facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2],[3]	4,028,254	3,573,000
Credit Facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facilities, Estimated Fair Value	[2],[3]	4,028,254	3,573,000
2021 Cheniere Convertible Unsecured Notes, net of discount [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[4]	921,690	879,938
2021 Cheniere Convertible Unsecured Notes, net of discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible Debt, Estimated Fair Value	[4]	918,414	825,413
2025 CCH Holdco II Convertible Senior Notes, net of discount [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[4]	1,109,165	1,050,588
2025 CCH Holdco II Convertible Senior Notes, net of discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible Debt, Estimated Fair Value	[4]	1,153,534	914,363
2045 Cheniere Convertible Senior Notes, net of discount [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[5]	307,006	305,938
2045 Cheniere Convertible Senior Notes, net of discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible Debt, Estimated Fair Value	[5]	$ 356,250	$ 331,919

[1] Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes; 2025 SPL Senior Notes; 2026 SPL Senior Notes; and 2024 CCH Senior Notes (collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the Senior Notes and other similar instruments.

[2] 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.

[3] Includes 2015 SPL Credit Facilities, SPL Working Capital Facility, 2016 CQP Credit Facilities, 2015 CCH Credit Facility and Cheniere Marketing trade finance facilities.

[4] 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.

[5] 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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Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income tax benefit (provision)	$ 343	$ 507	$ (273)	$ (171)

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Share-Based Compensation (Details) - USD ($) $ in Thousands, shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share-based Compensation Expense, Net Components
Total share-based compensation	$ 40,535	$ 68,665	$ 58,060	$ 86,655
Capitalized share-based compensation	(4,982)	(18,427)	(6,336)	(20,277)
Total share-based compensation expense	35,553	50,238	51,724	66,378
Share-based compensation, unrecognized compensation	154,500		$ 154,500
Share-based compensation, unrecognized compensation, period for recognition			1 year 10 months 1 day
Proceeds from exercise of stock options	0	$ 900	$ 0	1,914
Separated Employees [Member]
Share-based Compensation Expense, Net Components
Total share-based compensation	$ 15,600			$ 22,100
2003 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized	21.0		21.0
Number of Shares Granted Plan-to-Date, Net of Cancellations	21.0		21.0
2011 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized	35.0		35.0
Number of Shares Granted Plan-to-Date, Net of Cancellations	26.8		26.8
2015 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Granted Plan-to-Date, Net of Cancellations	6.1		6.1
2015 Inducement Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized	1.0		1.0
Number of Shares Granted Plan-to-Date, Net of Cancellations	0.2		0.2

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Net Loss Per Share Attributable to Common Stockholders (Details) - $ / shares shares in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Weighted Average Number of Common Shares Outstanding, Basic		228,323	226,481	228,231	226,405
Dilutive Common Stock Options and Unvested Stock	[1]	0	0	0	0
Weighted Average Number of Shares Outstanding, Diluted		228,323	226,481	228,231	226,405
Basic and diluted net loss per share attributable to common stockholders		$ (1.31)	$ (0.52)	$ (2.71)	$ (1.71)
Stock options and 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, Amount		7,100	10,100	7,100	10,100
Convertible Debt Securities [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		75,600	38,600	16,000	15,500

[1] Stock options and unvested stock of 7.1 million shares for each of the three and six months ended June 30, 2016 and 10.1 million shares for each of the three and six months ended June 30, 2015, representing securities that could potentially dilute basic EPS in the future, were not included in the diluted net loss per share computations because their effect would have been anti-dilutive. In addition, 16.0 million shares in aggregate for the three and six months ended June 30, 2016 and 15.5 million shares in aggregate for the three and six months ended June 30, 2015, issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes, were not included in the computation of diluted net loss per share because the computation of diluted net loss per share utilizing the “if-converted” method would be anti-dilutive. There were no shares included in the computation of diluted net loss per share for the 2025 CCH HoldCo II Convertible Senior Notes because non-market-based contingencies underlying the eligible conversion date have not been met as of June 30, 2016.

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Commitments and Contingencies (Details)	6 Months Ended
	Jun. 30, 2016 USD ($)
Guarantee Obligations [Member]
Loss Contingencies [Line Items]
Loss Contingency Accrual	$ 0
Cheniere LNG Terminals, LLC [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	400,000,000
Cheniere LNG Terminals, LLC [Member] | Parallax Enterprises [Member]
Loss Contingencies [Line Items]
Secured note receivable	$ 46,000,000

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Business Segment Information (Details) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) item	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | item				2
Revenues (losses) from external customers		$ 176,827	$ 68,025	$ 245,908	$ 136,394
Intersegment revenues (losses)	[1]	0	0	0	0
Depreciation and amortization expense		32,781	20,154	56,870	37,923
Income (loss) from operations		(76,454)	(95,874)	(167,013)	(156,118)
Interest expense, net of capitalized interest		(105,967)	(85,486)	(182,304)	(145,098)
Loss before income taxes and non-controlling interest	[2]	(335,287)	(142,309)	(683,645)	(477,475)
Share-based compensation		40,535	68,665	58,060	86,655
Expenditures for additions to long-lived assets		1,093,692	3,966,465	2,601,751	4,586,205
Total assets		21,436,851		21,436,851		$ 18,809,053
Non-US [Member]
Segment Reporting Information [Line Items]
Revenues (losses) from external customers		28,700		31,400
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues (losses) from external customers	[3]	(18,119)	199	(17,293)	326
Intersegment revenues (losses)	[1],[3]	(7,035)	(6,845)	(15,547)	(13,965)
Depreciation and amortization expense	[3]	5,764	3,839	11,565	6,467
Income (loss) from operations	[3]	(54,652)	(51,446)	(102,115)	(82,172)
Interest expense, net of capitalized interest	[3]	(25,840)	(26,021)	(50,811)	(42,788)
Loss before income taxes and non-controlling interest	[2],[3]	(92,856)	(82,090)	(169,563)	(134,211)
Share-based compensation	[3]	23,233	36,835	33,092	47,651
Expenditures for additions to long-lived assets	[3]	3,206	20,874	9,652	49,655
Total assets		766,015		766,015		894,407
LNG terminal business [Member]
Segment Reporting Information [Line Items]
Revenues (losses) from external customers		150,977	68,532	216,528	136,112
Intersegment revenues (losses)	[1]	6	491	924	594
Depreciation and amortization expense		26,711	16,071	44,684	31,012
Income (loss) from operations		10,115	(18,061)	(2,434)	(42,396)
Interest expense, net of capitalized interest		(80,127)	(59,465)	(131,493)	(102,310)
Loss before income taxes and non-controlling interest	[2]	(210,561)	(33,403)	(451,532)	(311,058)
Share-based compensation		7,045	25,778	9,822	28,917
Expenditures for additions to long-lived assets		1,089,190	3,944,191	2,590,568	4,534,436
Total assets		20,130,382		20,130,382		17,363,750
LNG and natural gas marketing business [Member]
Segment Reporting Information [Line Items]
Revenues (losses) from external customers		43,969	(706)	46,673	(44)
Intersegment revenues (losses)	[1]	7,029	6,354	14,623	13,371
Depreciation and amortization expense		306	244	621	444
Income (loss) from operations		(31,917)	(26,367)	(62,464)	(31,550)
Interest expense, net of capitalized interest		0	0	0	0
Loss before income taxes and non-controlling interest	[2]	(31,870)	(26,816)	(62,550)	(32,206)
Share-based compensation		10,257	6,052	15,146	10,087
Expenditures for additions to long-lived assets		1,296	$ 1,400	1,531	$ 2,114
Total assets		$ 540,454		$ 540,454		$ 550,896
Cheniere Partners [Member]
Segment Reporting Information [Line Items]
General Partner ownership percentage				100.00%
Cheniere Holdings [Member]
Segment Reporting Information [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent		80.10%		80.10%		80.10%
Cheniere Holdings [Member] | Cheniere Partners [Member]
Segment Reporting Information [Line Items]
Limited Partner ownership percentage				55.90%

[1] Intersegment revenues (losses) related to our LNG and natural gas marketing segment are primarily a result of international revenue allocations using a cost plus transfer pricing methodology. These LNG and natural gas marketing segment intersegment revenues (losses) are eliminated with intersegment revenues (losses) in our Consolidated Statements of Operations.

[2] Items to reconcile loss from operations and loss before income taxes and non-controlling interest include consolidated other income (expense) amounts as presented on our Consolidated Statements of Operations primarily related to our LNG terminal segment.

[3] Includes corporate activities, business development, strategic activities and certain intercompany eliminations. These activities have been included in the corporate and other column.

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 59,260	$ 46,165
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities	$ 472,400	$ 383,700