Cheniere Energy - 10-Q quarterly report FY2016 Q3

Cheniere Energy - 10-Q quarterly report FY2016 Q3

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2016

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

For the transition period from to

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):

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 October 27, 2016, the issuer had 234,985,131 shares of Common Stock outstanding.

CHENIERE ENERGY, INC.

TABLE OF CONTENTS

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

Abbreviated Organizational Structure

The following diagram depicts our abbreviated organizational structure as of September 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.


PART I.	FINANCIAL INFORMATION


ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)



	September 30,			December 31,
	2016			2015
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	990,132		$	1,201,112
Restricted cash	827,545			503,397
Accounts and other receivables	154,167			5,749
Inventory	63,853			18,125
Other current assets	69,030			54,203
Total current assets	2,104,727			1,782,586

Non-current restricted cash	31,128			31,722
Property, plant and equipment, net	19,891,666			16,193,907
Debt issuance costs, net	294,059			378,677
Non-current derivative assets	11,247			30,887
Goodwill	76,819			76,819
Other non-current assets	279,434			314,455
Total assets	$	22,689,080		$	18,809,053

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	38,569		$	22,820
Accrued liabilities	699,996			427,199
Current debt, net	1,781,511			1,673,379
Deferred revenue	26,709			26,669
Derivative liabilities	61,829			35,201
Other current liabilities	264			—
Total current liabilities	2,608,878			2,185,268

Long-term debt, net	19,033,513			14,920,427
Non-current deferred revenue	6,500			9,500
Non-current derivative liabilities	268,601			79,387
Other non-current liabilities	65,849			53,068

Commitments and contingencies (see Note 16)

Stockholders’ equity
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—			—
Common stock, $0.003 par value
Authorized: 480.0 million shares at September 30, 2016 and December 31, 2015
Issued and outstanding: 235.1 million shares and 235.6 million shares at September 30, 2016 and December 31, 2015, respectively	705			708
Treasury stock: 12.1 million shares and 11.6 million shares at September 30, 2016 and December 31, 2015, respectively, at cost	(372,531		)	(353,927		)
Additional paid-in-capital	3,112,753			3,075,317
Accumulated deficit	(4,343,646		)	(3,623,948		)
Total stockholders’ deficit	(1,602,719		)	(901,850		)
Non-controlling interest	2,308,458			2,463,253
Total equity	705,739			1,561,403
Total liabilities and equity	$	22,689,080		$	18,809,053

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Revenues
Regasification revenues	$	66,970		$	66,597		$	198,143		$	199,888
LNG revenues (losses)	398,554			(1,557		)	511,993			(1,601		)
Other revenues	149			1,019			1,445			4,166
Total revenues	465,673			66,059			711,581			202,453

Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	252,343			(24,214		)	352,559			(22,077		)
Operating and maintenance expense	61,610			17,963			143,489			71,396
Development expense	1,546			4,935			4,709			37,640
Selling, general and administrative expense	59,418			97,332			196,999			263,205
Depreciation and amortization expense	49,212			21,638			106,082			59,561
Restructuring expense	26,241			—			49,196			—
Impairment expense	—			396			10,095			572
Other	27			83			189			348
Total operating costs and expenses	450,397			118,133			863,318			410,645

Income (loss) from operations	15,276			(52,074		)	(151,737		)	(208,192		)

Other income (expense)
Interest expense, net of capitalized interest	(148,053		)	(93,566		)	(330,357		)	(238,664		)
Loss on early extinguishment of debt	(25,765		)	—			(82,537		)	(96,273		)
Derivative gain (loss), net	29,327			(161,482		)	(242,228		)	(242,123		)
Other income (expense)	437			(39		)	(5,564		)	616
Total other expense	(144,054		)	(255,087		)	(660,686		)	(576,444		)

Loss before income taxes and non-controlling interest	(128,778		)	(307,161		)	(812,423		)	(784,636		)
Income tax benefit (provision)	(1,638		)	69			(1,911		)	(102		)
Net loss	(130,416		)	(307,092		)	(814,334		)	(784,738		)
Less: net loss attributable to non-controlling interest	(29,974		)	(9,284		)	(94,636		)	(100,726		)
Net loss attributable to common stockholders	$	(100,442	)	$	(297,808	)	$	(719,698	)	$	(684,012	)

Net loss per share attributable to common stockholders—basic and diluted	$	(0.44	)	$	(1.31	)	$	(3.15	)	$	(3.02	)

Weighted average number of common shares outstanding—basic and diluted	228,924			227,126			228,463			226,648

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

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			Additional Paid-in Capital			Accumulated Deficit			Non-controlling Interest			Total Equity
Balance at December 31, 2015	235,639		$	708		11,649	$	(353,927	)	$	3,075,317		$	(3,623,948	)	$	2,463,253		$	1,561,403
Exercise of stock options	2		—			—	—			50			—			—			50
Issuances of restricted stock	273		1			—	—			(1		)	—			—			—
Forfeitures of restricted stock	(377	)	(2		)	10	—			2			—			—			—
Share-based compensation	—		—			—	—			36,526			—			—			36,526
Shares repurchased related to share-based compensation	(464	)	(2		)	464	(18,604		)	2			—			—			(18,604		)
Loss attributable to non-controlling interest	—		—			—	—			—			—			(94,636		)	(94,636		)
Equity portion of convertible notes, net	—		—			—	—			857			—			—			857
Distributions to non-controlling interest	—		—			—	—			—			—			(60,159		)	(60,159		)
Net loss	—		—			—	—			—			(719,698		)	—			(719,698		)
Balance at September 30, 2016	235,073		$	705		12,123	$	(372,531	)	$	3,112,753		$	(4,343,646	)	$	2,308,458		$	705,739

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)



	Nine Months Ended September 30,
	2016			2015
Cash flows from operating activities
Net loss	$	(814,334	)	$	(784,738	)
Adjustments to reconcile net loss to net cash used in operating activities:
Non-cash LNG inventory write-downs	—			17,826
Depreciation and amortization expense	106,082			59,561
Share-based compensation	85,128			92,627
Amortization of debt issuance costs and discount	38,826			28,552
Loss on early extinguishment of debt	82,537			96,273
Total losses on derivatives, net	269,399			208,769
Net cash used for settlement of derivative instruments	(34,567		)	(94,170		)
Impairment expense	10,095			572
Other	9,803			834
Changes in restricted cash for certain operating activities	119,831			92,589
Changes in operating assets and liabilities:
Accounts and other receivables	(128,042		)	(2,226		)
Inventory	(28,051		)	(25,966		)
Accounts payable and accrued liabilities	39,599			16,671
Deferred revenue	(2,960		)	(3,003		)
Other, net	47,627			21,252
Net cash used in operating activities	(199,027		)	(274,577		)

Cash flows from investing activities
Property, plant and equipment, net	(3,449,161		)	(5,747,596		)
Use of restricted cash for the acquisition of property, plant and equipment	3,488,263			5,330,526
Other	(51,308		)	(111,518		)
Net cash used in investing activities	(12,206		)	(528,588		)

Cash flows from financing activities
Proceeds from issuances of debt	8,308,306			6,178,000
Repayments of debt	(4,180,660		)	—
Debt issuance and deferred financing costs	(116,715		)	(519,699		)
Investment in restricted cash	(3,931,648		)	(5,161,701		)
Distributions and dividends to non-controlling interest	(60,159		)	(60,154		)
Proceeds from exercise of stock options	50			2,279
Payments related to tax withholdings for share-based compensation	(18,604		)	(44,305		)
Other	(317		)	1,424
Net cash provided by financing activities	253			395,844

Net decrease in cash and cash equivalents	(210,980		)	(407,321		)
Cash and cash equivalents—beginning of period	1,201,112			1,747,583
Cash and cash equivalents—end of period	$	990,132		$	1,340,262

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—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.

Directly and through our subsidiary, Cheniere Partners, we are developing, constructing and operating liquefaction projects near Corpus Christi, Texas (the “CCL Project”) and at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana (the “SPL Project”), respectively. In 2016, we started production at the SPL Project. As a result, we introduced a new line item entitled “cost of sales” and modified the components of activity included in “operating and maintenance expense” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made to the prior periods. 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.

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 nine months ended September 30, 2016, we received 44% and 50%, 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 nine months ended September 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 2—RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2016 and December 31, 2015, restricted cash consisted of the following (in thousands):



	September 30,		December 31,
	2016		2015
Current restricted cash
SPLNG debt service and interest payment	$	115,490	$	77,415
SPL Project	325,630		189,260
CTPL construction and interest payment	—		7,882
CQP and cash held by guarantor subsidiaries	127,429		—
CCL Project	192,812		46,770
Cash held by our subsidiaries restricted to Cheniere	12,930		147,138
Other	53,254		34,932
Total current restricted cash	$	827,545	$	503,397

Non-current restricted cash
SPLNG debt service	$	13,650	$	13,650
Other	17,478		18,072
Total non-current restricted cash	$	31,128	$	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 nine months ended September 30, 2016 and 2015, SPLNG made distributions of $230.4 million and $267.9 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 September 30, 2016 and December 31, 2015, accounts and other receivables consisted of the following (in thousands):



	September 30,		December 31,
	2016		2015
SPL trade receivable	$	38,432	$	—
Cheniere Marketing trade receivable	100,555		—
Interest receivable	234		95
Other accounts receivable	14,946		5,654
Total accounts and other receivables	$	154,167	$	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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 4—INVENTORY

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



	September 30,		December 31,
	2016		2015
Natural gas	$	4,181	$	5,724
LNG	29,111		5,148
Materials and other	30,561		7,253
Total inventory	$	63,853	$	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):



	September 30,			December 31,
	2016			2015
LNG terminal costs
LNG terminal	$	7,976,737		$	2,487,759
LNG terminal construction-in-process	12,176,899			13,875,204
LNG site and related costs, net	38,752			33,512
Accumulated depreciation	(498,934		)	(413,545		)
Total LNG terminal costs, net	19,693,454			15,982,930
Fixed assets and other
Computer and office equipment	13,241			12,153
Furniture and fixtures	17,393			17,101
Computer software	78,942			69,340
Leasehold improvements	46,351			40,136
Land	60,582			60,612
Other	36,369			49,376
Accumulated depreciation	(54,666		)	(37,741		)
Total fixed assets and other, net	198,212			210,977
Property, plant and equipment, net	$	19,891,666		$	16,193,907

During the three and nine months ended September 30, 2016, we realized offsets to LNG terminal costs of $68.3 million and $214.3 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 Trains 1 and 2 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 supply contracts 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”).

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 September 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
	September 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	$	—		$	(15,948	)	$	—	$	(15,948	)	$	—	$	(8,740	)	$	—	$	(8,740	)
CQP Interest Rate Derivatives liability	—			(12,166		)	—		(12,166		)	—		—			—		—
CCH Interest Rate Derivatives liability	—			(297,539		)	—		(297,539		)	—		(104,999		)	—		(104,999		)
Liquefaction Supply Derivatives asset (liability)	(105		)	(275		)	12,480		12,100			—		(25		)	32,492		32,467
LNG Trading Derivatives asset (liability)	284			(632		)	—		(348		)	—		1,053			—		1,053
Natural Gas Derivatives liability	—			—			—		—			—		(66		)	—		(66		)
FX Derivatives liability	—			(1,193		)	—		(1,193		)	—		—			—		—

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 quarter of 2016, which we transferred into Level 1 during the second quarter of 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. There were no transfers in and out of Level 2 during the three months ended September 30, 2016.

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 supply contracts. As of September 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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

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 supply contracts 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 September 30, 2016:



	Net Fair Value Asset (in thousands)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$12,480	Income Approach	Basis Spread	$(0.35) - $(0.03)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Balance, beginning of period	$	22,434		$	440		$	32,492		$	342
Realized and mark-to-market losses:
Included in cost of sales (1)	(10,567		)	32,177			(20,482		)	32,204
Purchases and settlements:
Purchases	968			—			968			—
Settlements (1)	(308		)	(71		)	(741		)	—
Transfers out of Level 3 (2)	(47		)	—			243			—
Balance, end of period	$	12,480		$	32,546		$	12,480		$	32,546
Change in unrealized gains relating to instruments still held at end of period	$	(10,567	)	$	—		$	(19,763	)	$	—


(1)	Does not include the decrease in fair value of $0.7 million related to the realized gains capitalized during the nine months ended September 30, 2016.


(2)	Transferred to Level 2 as a result of observable market for the underlying natural gas supply contracts.

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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(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 September 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:



	September 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	$	(6,376	)	$	(5,248	)	$	(45,481	)	$	(57,105	)	$	(5,940	)	$	—	$	(28,559	)	$	(34,499	)
Non-current derivative liabilities	(9,572		)	(6,918		)	(252,058		)	(268,548		)	(2,800		)	—		(76,440		)	(79,240		)
Total derivative liabilities	$	(15,948	)	$	(12,166	)	$	(297,539	)	$	(325,653	)	$	(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 nine months ended September 30, 2016 and 2015:



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2016		2015			2016			2015
SPL Interest Rate Derivatives gain (loss)	$	2,557	$	(10,872	)	$	(13,473	)	$	(46,541	)
CQP Interest Rate Derivatives gain (loss)	6,626		—			(12,944		)	—
CCH Interest Rate Derivatives gain (loss)	20,113		(150,610		)	(215,940		)	(195,582		)

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 September 30, 2016, SPL has secured up to approximately

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

1,982.0 million MMBtu of natural gas feedstock through natural gas supply contracts. The notional natural gas position of our Physical Liquefaction Supply Derivatives was approximately 1,069.0 million MMBtu as of September 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 September 30, 2016, we have entered into certain LNG Trading Derivatives representing a short position of 12.6 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 September 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:



	September 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	$	1,947		$	2,142		$	—	$	4,089		$	2,737		$	640		$	—		$	3,377
Non-current derivative assets	11,247			—			—		11,247			30,304			583			—			30,887
Total derivative assets	13,194			2,142			—		15,336			33,041			1,223			—			34,264

Derivative liabilities	(1,083		)	(2,490		)	—		(3,573		)	(490		)	(107		)	(66		)	(663		)
Non-current derivative liabilities	(11		)	—			—		(11		)	(84		)	(63		)	—			(147		)
Total derivative liabilities	(1,094		)	(2,490		)	—		(3,584		)	(574		)	(170		)	(66		)	(810		)

Derivative asset (liabilities), net	$	12,100		$	(348	)	$	—	$	11,752		$	32,467		$	1,053		$	(66	)	$	33,454


(1)	Does not include collateral of $1.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of September 30, 2016.


(2)	Does not include collateral of $13.4 million and $11.0 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

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 nine months ended September 30, 2016 and 2015:



		Three Months Ended						Nine Months Ended
		September 30,						September 30,
	Statement of Operations Location	2016			2015			2016			2015
Liquefaction Supply Derivatives gain	LNG revenues (losses)	$	374		$	—		$	368		$	—
Liquefaction Supply Derivatives gain (loss) (1)	Cost (cost recovery) of sales	(10,416		)	32,103			(22,680		)	32,184
LNG Trading Derivatives gain (loss)	LNG revenues (losses)	8,617			113			(3,597		)	113
Natural Gas Derivatives loss	LNG revenues (losses)	—			(152		)	(5		)	(260		)
Natural Gas Derivatives gain	Operating and maintenance expense	—			857			174			1,317

(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 $14.6 million as of September 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	September 30, 2016			December 31, 2015
FX Derivatives	Derivative liabilities	$	(1,151	)	$	—
FX Derivatives	Non-current derivative liabilities	(42		)	—

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 nine months ended September 30, 2016 and 2015:



		Three Months Ended					Nine Months Ended
		September 30,					September 30,
	Statement of Operations Location	2016			2015		2016			2015
FX Derivatives loss	LNG revenues (losses)	$	(1,385	)	$	—	$	(1,345	)	$	—
FX Derivatives gain	Derivative gain (loss), net	31			—		129			—
FX Derivatives gain (loss)	Other income (expense)	2			—		(86		)	—

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(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)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
As of September 30, 2016
SPL Interest Rate Derivatives	$	(15,948	)	$	—		$	(15,948	)
CQP Interest Rate Derivatives	(12,166		)	—			(12,166		)
CCH Interest Rate Derivatives	(297,539		)	—			(297,539		)
Liquefaction Supply Derivatives	13,740			(546		)	13,194
Liquefaction Supply Derivatives	(2,803		)	1,709			(1,094		)
LNG Trading Derivatives	6,829			(4,687		)	2,142
LNG Trading Derivatives	(5,712		)	3,222			(2,490		)
FX Derivatives	(2,036		)	843			(1,193		)
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 September 30, 2016 and December 31, 2015, other non-current assets consisted of the following (in thousands):



	September 30,		December 31,
	2016		2015
Advances made under EPC and non-EPC contracts	$	13,678	$	83,579
Advances made to municipalities for water system enhancements	98,958		89,953
Collateral payments for the CCL Project	36,341		4,994
Tax-related payments and receivables	31,218		31,712
Equity method investments	11,058		20,295
Other	88,181		83,922
Total other non-current assets	$	279,434	$	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 September 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 ENERGY, INC. AND SUBSIDIARIES

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



	September 30,		December 31,
	2016		2015
Interest costs and related debt fees	$	228,434	$	159,968
Compensation and benefits	104,318		99,511
SPL Project and CCL Project costs	343,782		145,759
LNG terminal costs	4,430		3,918
Other accrued liabilities	19,032		18,043
Total accrued liabilities	$	699,996	$	427,199

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—DEBT

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



	September 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 $7,573 and $8,718	2,007,573			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 $5,844 and $6,392	1,505,844			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			—
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500,000			—
2015 SPL Credit Facilities	—			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	3,283,340			2,713,000
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,139,667			1,050,588
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”), net of unamortized discount of $151,996 and $174,095	927,729			879,938
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”), net of unamortized discount of $317,441 and $319,062	307,559			305,938
Unamortized debt issuance costs (2)	(258,199		)	(207,718		)
Total long-term debt, net	19,033,513			14,920,427

Current debt:
7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of $782 and $4,303 (3)	1,664,718			1,661,197
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	98,500			15,000
Cheniere Marketing trade finance facilities	18,807			—
Unamortized debt issuance costs (2)	(514		)	(2,818		)
Total current debt, net	1,781,511			1,673,379

Total debt, net	$	20,815,024		$	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. See Note 20—Subsequent Events for additional details about the redemption of the 2020 SPLNG Senior Notes.


(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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

for each reporting period presented. As a result, we reclassified $207.7 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. See Note 20—Subsequent Events for additional details about the intended repayment of the 2016 SPLNG Senior Notes.

2016 Debt Issuances and Redemptions

SPL Senior Notes

In June and September 2016, SPL issued the 2026 SPL Senior Notes and the 2027 SPL Senior Notes, respectively, for aggregate principal amounts of $1.5 billion each. Net proceeds of the offerings of the 2026 SPL Senior Notes and 2027 SPL Senior Notes were approximately $1.3 billion and $1.4 billion, respectively, after deducting commissions, fees and expenses and incremental interest required under the respective senior notes during construction. The net proceeds were used to prepay a portion (for the 2026 SPL Senior Notes) or all (for the 2027 SPL Senior Notes) of the outstanding borrowings and terminate commitments under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $25.8 million and $51.8 million during the three and nine months ended September 30, 2016, respectively. The remaining proceeds from the 2027 SPL Senior Notes are being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities. The 2026 SPL Senior Notes and 2027 SPL Senior Notes accrue interest at fixed rates of 5.875% and 5.00%, respectively, and interest is payable semi-annually in arrears. The terms of the 2026 SPL Senior Notes and 2027 SPL Senior Notes are governed by the same common indenture as the other senior notes of SPL, which contains customary terms and events of default, covenants and redemption terms.

In connection with the issuance of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes, SPL entered into registration rights agreements (the “SPL Registration Rights Agreements”). Under the terms of the SPL Registration Rights Agreements, SPL has agreed, and any future guarantors will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective registration statements relating to offers to exchange any and all of the 2026 SPL Senior Notes and 2027 SPL Senior Notes for like aggregate principal amounts of debt securities of SPL with terms identical in all material respects to the respective senior notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after June 14, 2016 and September 23, 2016, respectively. Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective shelf registration statements relating to resales of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes. SPL will be obligated to pay additional interest on these senior notes if it fails to comply with its obligation to register them 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 the nine months ended September 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 billion 2016 CQP Credit Facilities, which consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 million 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 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 as of September 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 nine months ended September 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 September 30, 2016 (in thousands):



	2015 SPL Credit Facilities		SPL Working Capital Facility		2016 CQP Credit Facilities		2015 CCH Credit Facility
Original facility size	$	4,600,000	$	1,200,000	$	2,800,000	$	8,403,714
Outstanding balance	—		98,500		450,000		3,283,340
Commitments prepaid or terminated	2,643,867		—		—		1,050,660
Letters of credit issued	—		337,044		7,500		—
Available commitment	$	1,956,133	$	764,456	$	2,342,500	$	4,069,714

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 September 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	$	927,729		$	1,139,667		$	307,559
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	8.3		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (8)	4.7 years			4.0 years			28.5 years


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


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


(3)	Convertible on or after the later of March 1, 2020 and the substantial completion of Train 2 of the CCL Project, provided that our market capitalization is not less than $10.0 billion (“Eligible Conversion Date”). The conversion price is the

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 by holders 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Interest cost on convertible notes:
Interest per contractual rate	$	51,000		$	46,782		$	149,893		$	97,991
Amortization of debt discount	6,593			7,233			24,578			20,948
Amortization of debt issuance costs	1,362			1,133			3,766			1,748
Total interest cost related to convertible notes	58,955			55,148			178,237			120,687
Interest cost on debt excluding convertible notes	281,814			230,807			773,032			587,137
Total interest cost	340,769			285,955			951,269			707,824
Capitalized interest	(192,716		)	(192,389		)	(620,912		)	(469,160		)
Total interest expense, net	$	148,053		$	93,566		$	330,357		$	238,664

Fair Value Disclosures

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



	September 30, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior Notes, net of premium or discount (1)	$	14,848,135	$	15,747,108	$	10,596,307	$	9,525,809
CTPL Term Loan, net of discount (2)	—		—		398,571		400,000
Credit facilities (2) (3)	3,850,647		3,850,647		3,573,000		3,573,000
2021 Cheniere Convertible Unsecured Notes, net of discount (4)	927,729		981,520		879,938		825,413
2025 CCH HoldCo II Convertible Senior Notes (4)	1,139,667		1,296,440		1,050,588		914,363
2045 Cheniere Convertible Senior Notes, net of discount (5)	307,559		414,063		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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPL Senior Notes; 2027 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.

NOTE 12—RESTRUCTURING EXPENSE

During the fourth quarter of 2015, we initiated certain organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment. As a result of these efforts, we recorded $26.2 million and $49.2 million of restructuring charges and other costs associated with restructuring and operational efficiency initiatives during the three and nine months ended September 30, 2016, respectively, for which the majority of these charges required, or will require, cash expenditure. Included in these amounts are $20.9 million and $42.9 million for share-based compensation during the three and nine months ended September 30, 2016, respectively. All charges were recorded within the line item entitled “restructuring expense” on our Consolidated Statements of Operations and substantially all related to severance and other employee-related costs. As of September 30, 2016 and December 31, 2015, we had $14.6 million and $33.0 million, respectively, of accrued restructuring charges and other costs that were recorded as part of accrued liabilities on our Consolidated Balance Sheets. Operational efficiency initiatives remain ongoing and are expected to be substantially complete by the end of 2016.

NOTE 13—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. We have recorded a net benefit (provision) of $(1.6) million and $0.1 million for the three months ended September 30, 2016 and 2015, respectively, and $(1.9) million and $(0.1) million for the nine months ended September 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 NOL carryforwards.

NOTE 14—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 September 30, 2016, all of the shares under the 2003 Plan have been granted and

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

26.6 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 September 30, 2016, 6.3 million phantom units have been granted under the 2015 Plan. See Note 20—Subsequent Events regarding the termination of 2014-2018 Long-Term Cash Incentive Program (“2014-2018 LTIP”) 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 September 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Total share-based compensation	$	39,557		$	27,451		$	97,617		$	114,107
Capitalized share-based compensation	(6,153		)	(1,202		)	(12,489		)	(21,480		)
Total share-based compensation expense	$	33,404		$	26,249		$	85,128		$	92,627

The total unrecognized compensation cost at September 30, 2016 relating to non-vested share-based compensation arrangements was $138.0 million, which is expected to be recognized over a weighted average period of 1.4 years.

During the three and nine months ended September 30, 2016, we recognized $4.3 million and $5.6 million, respectively, of share-based compensation expense related to the modification of share-based compensation awards resulting from employee terminations.

We received $0.1 million in each of the three and nine months ended September 30, 2016 and $0.4 million and $2.3 million in the three and nine months ended September 30, 2015, respectively, of proceeds from the exercise of stock options.

NOTE 15—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 nine months ended September 30, 2016 and 2015:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Weighted average common shares outstanding:
Basic	228,924			227,126			228,463			226,648
Dilutive common stock options and unvested stock (1)	—			—			—			—
Diluted	228,924			227,126			228,463			226,648

Basic and diluted net loss per share attributable to common stockholders	$	(0.44	)	$	(1.31	)	$	(3.15	)	$	(3.02	)

(1)

Stock options and unvested stock of 5.8 million shares and 5.7 million shares for the three and nine months ended September 30, 2016, respectively, and 8.6 million shares for each of the three and nine months ended September 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. Included in these numbers of shares are 5.1 million shares for each of the three and nine months ended September 30, 2016 and 5.4 million shares for each of the three and nine months ended September 30, 2015 of unvested stock that have performance conditions not yet satisfied as of September 30, 2016 and 2015, respectively. In addition, 16.2 million shares in aggregate for the three and nine months

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

ended September 30, 2016 and 15.6 million shares in aggregate for the three and nine months ended September 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 substantive non-market-based contingencies underlying the eligible conversion date have not been met as of September 30, 2016.

NOTE 16—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 September 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. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery, which is ongoing.

On March 11, 2016, Parallax Enterprises filed a suit against us and CLNGT styled Civil Action No. 62-810, Parallax Enterprises LLP v. Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC, in the 25th Judicial District Court of Plaquemines Parish, Louisiana (the “Louisiana Suit”), wherein Parallax Enterprises asserted claims for breach of contract, fraudulent inducement, negligent misrepresentation, detrimental reliance, unjust enrichment and violation of the Louisiana Unfair Trade Practices Act. Parallax Enterprises predicated its claims in the Louisiana Suit on an allegation that we and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises sought $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, we and CLNGT removed the Louisiana Suit to the United States District Court for the Eastern District of Louisiana, which subsequently transferred the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was assigned Civil Action No. 4:16-cv-01628 and transferred to the same judge presiding over the Texas Suit for coordinated handling. On August 22, 2016, Parallax Enterprises voluntarily dismissed all claims asserted against CLNGT and us in the Louisiana Suit without prejudice to refiling. 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 September 30, 2016 and December 31, 2015, there were no liabilities recognized under these guarantee arrangements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 17—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 $224.3 million and $255.7 million for the three and nine months ended September 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 portfolio of long-term, short-term and spot LNG SPAs with professional staff based in the United States, United Kingdom, Singapore and Chile.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(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 September 30, 2016
Revenues (losses) from external customers	$	314,917		$	179,188		$	(28,432	)	$	465,673
Intersegment revenues (losses) (2)	16,244			8,692			(24,936		)	—
Depreciation and amortization expense	43,014			344			5,854			49,212
Income (loss) from operations (3)	44,346			26,614			(55,684		)	15,276
Interest expense, net of capitalized interest	(121,636		)	—			(26,417		)	(148,053		)
Income (loss) before income taxes and non-controlling interest (4)	(68,345		)	26,736			(87,169		)	(128,778		)
Share-based compensation	9,183			5,434			24,940			39,557
Expenditures for additions to long-lived assets	1,213,662			1,103			170			1,214,935

Three Months Ended September 30, 2015
Revenues (losses) from external customers	$	67,212		$	(1,557	)	$	404		$	66,059
Intersegment revenues (losses) (2)	233			11,354			(11,587		)	—
Depreciation and amortization expense	16,775			320			4,543			21,638
Income (loss) from operations	27,072			(27,117		)	(52,029		)	(52,074		)
Interest expense, net of capitalized interest	(67,589		)	(14		)	(25,963		)	(93,566		)
Loss before income taxes and non-controlling interest (4)	(196,693		)	(27,665		)	(82,803		)	(307,161		)
Share-based compensation	1,316			2,051			24,084			27,451
Expenditures for additions to long-lived assets	1,429,808			403			21,258			1,451,469

Nine Months Ended September 30, 2016
Revenues (losses) from external customers	$	530,526		$	222,418		$	(41,363	)	$	711,581
Intersegment revenues (losses) (2)	17,168			29,259			(46,427		)	—
Depreciation and amortization expense	87,698			965			17,419			106,082
Income (loss) from operations (3)	41,912			(35,850		)	(157,799		)	(151,737		)
Interest expense, net of capitalized interest	(253,129		)	—			(77,228		)	(330,357		)
Loss before income taxes and non-controlling interest (4)	(519,877		)	(35,814		)	(256,732		)	(812,423		)
Share-based compensation	19,005			20,580			58,032			97,617
Expenditures for additions to long-lived assets	3,800,814			2,634			13,238			3,816,686

Nine Months Ended September 30, 2015
Revenues (losses) from external customers	$	203,324		$	(1,601	)	$	730		$	202,453
Intersegment revenues (losses) (2)	827			24,725			(25,552		)	—
Depreciation and amortization expense	47,787			764			11,010			59,561
Loss from operations	(15,324		)	(58,667		)	(134,201		)	(208,192		)
Interest expense, net of capitalized interest	(169,899		)	(14		)	(68,751		)	(238,664		)
Loss before income taxes and non-controlling interest (4)	(507,751		)	(59,871		)	(217,014		)	(784,636		)
Share-based compensation	30,233			12,138			71,736			114,107
Expenditures for additions to long-lived assets	5,964,244			2,517			70,913			6,037,674


(1)	Includes corporate activities, business development, strategic activities and certain intercompany eliminations. These activities have been included in the corporate and other column. Also includes $45.1 million and $60.5 million for the three and nine months ended September 30, 2016, respectively, of Cheniere Marketing’s LNG revenues, which is eliminated in consolidation.


(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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

intersegment revenues (losses) are eliminated with intersegment revenues (losses) in our Consolidated Statements of Operations.


(3)	Includes restructuring expense of $23.1 million and $35.3 million for the three and nine months ended September 30, 2016, respectively, in the corporate and other column and $3.1 million and $13.9 million for the three and nine months ended September 30, 2016, respectively, in the LNG and natural gas marketing segment.


(4)	Items to reconcile income (loss) from operations and income (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:



	September 30,		December 31,
	2016		2015
LNG Terminal	$	21,365,364	$	17,363,750
LNG & Natural Gas Marketing	631,378		550,896
Corporate and Other	692,338		894,407
Total Consolidation	$	22,689,080	$	18,809,053

NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Nine Months Ended September 30,
	2016		2015
Cash paid during the period for interest, net of amounts capitalized	$	29,879	$	48,271
Non-cash conveyance of assets	—		13,169

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $491.4 million and $356.3 million as of September 30, 2016 and 2015, respectively.

NOTE 19—RECENT ACCOUNTING STANDARDS

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

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 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.
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.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Additionally, the following table provides a brief description of recent accounting standards that were adopted by 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.
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.

NOTE 20—SUBSEQUENT EVENTS

SPLNG Senior Notes Redemption

On October 14, 2016, SPLNG issued a notice of redemption to redeem all of its outstanding 2020 SPLNG Senior Notes. The redemption date will be November 30, 2016 (the “Redemption Date”) and the price will be equal to 103.250% of the principal amount of the 2020 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2020 SPLNG Senior Notes to, but not including, the Redemption Date. Concurrently with the redemption of the 2020 SPLNG Senior Notes, SPLNG intends to repay all of its outstanding 2016 SPLNG Senior Notes, which mature on the Redemption Date, at a price equal to 100% of the principal amount of the 2016 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2016 SPLNG Senior Notes to, but not including, the Redemption Date.

Termination of 2014-2018 LTIP

On October 27, 2016, the Compensation Committee recommended and our Board of Directors approved the termination, effective as of October 31, 2016, of the 2014-2018 LTIP under the 2015 Plan.


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 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, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;


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


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


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

All of these types of statements, other than statements of historical 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,

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. Our vision is to be recognized as the premier global LNG company and provide a reliable, competitive and integrated source of LNG to our customers while creating a safe, productive and rewarding work environment for our employees. 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. Trains 1 and 2 have commenced operating activities, Train 3 is undergoing commissioning, Trains 4 and 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”).

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”). We have proposed the development of a pipeline with expected capacity of up to 1.4 Bcf/d connecting new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project. We expect the regulatory pre-filing process to commence imminently and to file formal applications for the required regulatory permits in 2017. We are also exploring the development of a midscale liquefaction project using electric drive modular Trains, with an expected aggregate nominal production capacity of approximately 9.5 mtpa of LNG.

Overview of Significant Events

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


•	SPL commenced production and shipment of LNG commissioning cargoes from Trains 1 and 2 of the SPL Project in February and August 2016, respectively, and achieved substantial completion and commenced operating activities in May and September 2016, respectively.


•	In September 2016, SPL initiated the commissioning process for Train 3 of the SPL Project.


•	In October 2016, the previously announced planned outage to improve performance of the flare systems at the SPL Project, as well as to perform scheduled maintenance to Train 1 and other facilities, was completed on schedule and budget.


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

•

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 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 June and September 2016, SPL issued 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”) and 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), respectively, for aggregate principal amounts of $1.5 billion each. Net proceeds of the offerings of the 2026 SPL Senior Notes and 2027 SPL Senior Notes were approximately $1.3 billion and $1.4 billion, respectively, after deducting commissions, fees and expenses and incremental interest required under the respective senior notes during construction. The net proceeds were used to prepay a portion (for the 2026 SPL Senior Notes) or all (for the 2027 SPL Senior Notes) of the outstanding borrowings under the credit facilities we entered into in June 2015 (the “2015 SPL Credit Facilities”). The remaining proceeds from the 2027 SPL Senior Notes are being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.


•	On September 30, 2016, we submitted a proposal to Cheniere Holdings’ board of directors to acquire the publicly held shares of Cheniere Holdings not already owned by us in a stock for stock exchange. There can be no assurance that any discussions that may occur between us and Cheniere Holdings in connection with our proposal will result in the entry

into a definitive agreement concerning a transaction or, if such a definitive agreement is reached, will result in the consummation of a transaction provided for in such definitive agreement.

•

In October 2016, SPLNG issued a notice of redemption to redeem all of its outstanding 2020 SPLNG Senior Notes. The redemption date will be November 30, 2016 (the “Redemption Date”) and the price will be equal to 103.250% of the principal amount of the 2020 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2020 SPLNG Senior Notes to, but not including, the Redemption Date. Concurrently with the redemption of the 2020 SPLNG Senior Notes, SPLNG intends to repay all of its outstanding 2016 SPLNG Senior Notes, which mature on the Redemption Date, at a price equal to 100% of the principal amount of the 2016 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2016 SPLNG Senior Notes to, but not including, the Redemption Date.

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


•	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 September 30, 2016, we had cash and cash equivalents of $990.1 million available to Cheniere. In addition, we had current and non-current restricted cash of $858.7 million (which included current and non-current restricted cash available to us and our subsidiaries) designated for the following purposes: $192.8 million for the CCL Project; $325.6 million for the SPL Project; $127.5 million due to restrictions under the 2016 CQP Credit Facilities; $129.1 million for interest payments related to the SPLNG Senior Notes; and $83.7 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 September 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 $11.1 million and $11.0 million in dividends on our Cheniere Holdings common shares during the nine months ended September 30, 2016 and 2015, respectively, and $0.8 million of management fees from Cheniere Holdings during each of the nine months ended September 30, 2016 and 2015.

Cheniere Partners

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of September 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 $1.5 million in distributions on our general partner interest during each of the nine months ended September 30, 2016 and 2015, and we received $100.1 million and $66.4 million in total service fees from Cheniere Partners, SPLNG, SPL and CTPL, during the nine months ended September 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.

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 (“Blackstone CQP Holdco”) was 1.80 and 1.77, respectively, as of September 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. The holders of Class B units have a preference over the holders of the subordinated units in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets.

The Class B units were issued at a discount to the market price of the Cheniere Partners common units into which they are convertible. This discount, totaling $2,130.0 million, represents a beneficial conversion feature. The beneficial conversion feature is similar to a dividend that will be distributed with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity, including our equity interest in Cheniere Partners. Cheniere Partners amortizes the beneficial conversion feature assuming a conversion date of August 2017, although actual conversion may occur prior to or after this assumed date. Deemed dividends represented by the amortization of the beneficial conversion feature allocated to the Class B units held by Blackstone CQP Holdco are included in net loss attributable to non-controlling interest and result in a reduction of income available to common stockholders. The impact to net loss attributable to non-controlling interest due to the amortization of the beneficial conversion feature was $6.8 million and $9.3 million during the three and nine months ended September 30, 2016, respectively. The anticipated impact to net loss attributable to non-controlling interest due to the amortization of the beneficial conversion feature based on the assumed

conversion date and ownership interest as of September 30, 2016, is approximately $33 million and $725 million, respectively, for the years ended December 31, 2016 and 2017.

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. In May 2016 and September 2016, Trains 1 and 2 achieved substantial completion, respectively. 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. In October 2016, the previously announced planned outage to improve performance of the flare systems at the SPL Project, as well as to perform scheduled maintenance to Train 1 and other facilities, was completed on schedule and budget.

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, which commenced on May 15, 2016, and to non-FTA countries for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas). 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 of natural gas (approximately 10 mtpa). 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 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 July 2016, the same party petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the DOE order related to the export of 503.3 Bcf/yr to non-FTA countries and the order denying the request for rehearing of the same. The appeal is pending. 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 three-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 September 30, 2016, Trains 1 and 2 of the SPL Project had achieved substantial completion. As of September 30, 2016, the overall project completion percentage for Trains 3 and 4 of the SPL Project was approximately 91.8%. As of September 30, 2016, the overall project completion percentage for Train 5 of the SPL Project was approximately 42.8% with engineering, procurement, subcontract work and construction approximately 90.8%, 62.0%, 41.9% and 4.6% complete, respectively. As of September 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 August 2016 and achieved substantial completion in September 2016. Based on our current construction schedule, 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 date of first commercial delivery from 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 supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of September 30, 2016, SPL has secured up to approximately 1,982.0 million MMBtu of natural gas feedstock through long-term natural gas supply contracts.

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.

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, $3.9 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through September 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 nine months ended September 30, 2016, we realized offsets to LNG terminal costs of $68.3 million and $214.3 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 Trains 1 and 2 of the SPL Project.

Senior Secured Notes

As of September 30, 2016, Cheniere Partners’ subsidiaries had nine 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, the 2026 SPL Senior Notes and the 2027 SPL Senior Notes, the “SPL Senior Notes”);


•	$1.5 billion of 2026 SPL Senior Notes; and


•	$1.5 billion of 2027 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.

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.

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, 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 nine months ended September 30, 2016 and 2015, SPLNG made distributions of $230.4 million and $267.9 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. During 2016, in conjunction with the issuance of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes, SPL prepaid outstanding borrowings and terminated commitments under the 2015 SPL Credit Facilities for approximately $2.6 billion. These prepayments and termination of commitments resulted in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $25.8 million and $51.8 million during the three and nine months ended September 30, 2016, respectively. As of September 30, 2016, SPL had $2.0 billion of available commitments and no 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.

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 certain conditions have been met, including that 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 $96.3 million for the nine months ended September 30, 2015.

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 nine months ended September 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 million 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 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 million 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. As of September 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.

Cheniere Partners incurred $48.7 million of debt issuance costs during the nine months ended September 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.

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 September 30, 2016, SPL had $764.5 million of available commitments, $337.0 million aggregate amount of issued letters of credit and $98.5 million of 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 September 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.

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 September 30, 2016, the overall project completion percentage for Stage 1 of the CCL Project was approximately 43.0% with engineering, procurement and construction approximately 99.3%, 59.0% and 14.4% complete, respectively. The construction of the Corpus Christi Pipeline is planned to commence in early 2017. 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 date of first commercial delivery from 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 supply contracts under these enabling agreements as and when required for the CCL Project.

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 September 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.

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.

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 the nine months ended September 30, 2016. As of September 30, 2016, CCH had $4.1 billion of available commitments and $3.3 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 of Trains 1 and 2 of the CCL Project and 2.50% on completion and thereafter. The applicable margins for base rate loans are 1.25% prior to completion Trains 1 and 2 of the CCL Project 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.

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 September 30, 2016, Cheniere Marketing has sold approximately 500 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 September 30, 2016, Cheniere Marketing had $18.8 million in loans and $5.8 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. We have proposed the development of a pipeline with expected capacity of up to 1.4 Bcf/d connecting new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project. We expect the regulatory pre-filing process to commence imminently and to file formal applications for the required regulatory permits in 2017. We are also exploring the development of a midscale liquefaction project using electric drive modular Trains, with an expected aggregate nominal production capacity of approximately 9.5 mtpa of LNG.

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 nine months ended September 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.



	Nine Months Ended September 30,
	2016			2015
Operating cash flows
Net cash used in operating activities	$	(199,027	)	$	(274,577	)
Changes in restricted cash for certain operating activities	(119,831		)	(92,589		)
Cash, cash equivalents and restricted cash used in operating activities	(318,858		)	(367,166		)

Investing cash flows
Net cash used in investing activities	(12,206		)	(528,588		)
Use of restricted cash for the acquisition of property, plant and equipment	(3,488,263		)	(5,330,526		)
Cash, cash equivalents and restricted cash used in investing activities	(3,500,469		)	(5,859,114		)

Financing cash flows
Net cash provided by financing activities	253			395,844
Investment in restricted cash	3,931,648			5,161,701
Cash, cash equivalents and restricted cash provided by financing activities	3,931,901			5,557,545

Net increase (decrease) in cash, cash equivalents and restricted cash	112,574			(668,735		)
Cash, cash equivalents and restricted cash—beginning of period	1,736,231			2,780,131
Cash, cash equivalents and restricted cash—end of period	$	1,848,805		$	2,111,396

Operating Cash Flows

Operating cash flows during the nine months ended September 30, 2016 and 2015 were $318.9 million and $367.2 million, respectively. The decrease in operating cash outflows in 2016 compared to 2015 primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the commencement of operations of Trains 1 and 2 of the SPL Project in May and September 2016, respectively, and increased cash payout for phantom unit awards.

Investing Cash Flows

Investing cash flows during the nine months ended September 30, 2016 and 2015 were $3.5 billion and $5.9 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 nine months ended September 30, 2016 and 2015, we used $51.3 million and $111.5 million, respectively, primarily to pay municipal water districts for water system enhancements that will increase potable water supply to our export terminals, payments made for capital assets purchased pursuant to information technology services agreements, collateral payments for the CCL Project and for investments made in unconsolidated entities.

Financing Cash Flows

Financing cash flows during the nine months ended September 30, 2016 were $3.9 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;


•	$1.6 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;


•	$1.7 billion of borrowings under the 2015 SPL Credit Facilities;


•	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;


•	issuance of an aggregate principal amount of $1.5 billion of the 2027 SPL Senior Notes in September 2016, which was used to prepay $1.2 billion of the outstanding borrowings under the 2015 SPL Credit Facilities and pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project;


•	$18.8 million of borrowings under the Cheniere Marketing trade finance facilities;


•	$313.5 million of borrowings and a $230.0 million repayment made under the SPL Working Capital Facility;


•	$116.7 million of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions;


•	$60.2 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; and


•	$18.6 million paid for tax withholdings for share-based compensation.

Financing cash flows during the nine months ended September 30, 2015 were $5.6 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 borrowing $2.4 billion under this facility during the nine months ended September 30, 2015;


•	entering into the 2015 SPL Credit Facilities in June 2015 and borrowing $250.0 million under this facility during the nine months ended September 30, 2015;


•	$519.7 million of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions;


•	$60.2 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; and


•	$44.3 million paid for tax withholdings for share-based compensation.

Results of Operations

Our consolidated net loss attributable to common stockholders was $100.4 million, or $0.44 per share (basic and diluted), in the three months ended September 30, 2016, compared to a net loss attributable to common stockholders of $297.8 million, or $1.31 per share (basic and diluted), in the three months ended September 30, 2015. This $197.4 million decrease in net loss in 2016 was primarily a result of decreased derivative loss, net, and increased income from operations, which was partially offset by increased interest expense, net of amounts capitalized, and restructuring expense.

Our consolidated net loss attributable to common stockholders was $719.7 million, or $3.15 per share (basic and diluted), in the nine months ended September 30, 2016, compared to a net loss attributable to common stockholders of $684.0 million, or $3.02 per share (basic and diluted), in the nine months ended September 30, 2015. This $35.7 million increase in net loss in 2016 was primarily a result of increased interest expense, net of amounts capitalized, and restructuring expense, which was partially offset by decreased loss from operations.

Revenues



	Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)	2016		2015			Change			2016		2015			Change
Regasification revenues	$	66,970	$	66,597		$	373		$	198,143	$	199,888		$	(1,745	)
LNG revenues (losses)	398,554		(1,557		)	400,111			511,993		(1,601		)	513,594
Other revenues	149		1,019			(870		)	1,445		4,166			(2,721		)
Total revenues	$	465,673	$	66,059		$	399,614		$	711,581	$	202,453		$	509,128

We began recognizing LNG revenues from the SPL Project following the substantial completion of Trains 1 and 2 in May and September 2016, respectively. Prior to these dates, 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 those Trains of the SPL Project. During the three and nine months ended September 30, 2016, we loaded a total of 60.3 million MMBtu and 113.8 million MMBtu of LNG, respectively, of which 50.8 million MMBtu and 69.0 million MMBtu, respectively, resulted in the recognition of revenues related to this volume. The remaining 9.5 million MMBtu and 44.8 million MMBtu of LNG loaded during the three and nine months ended September 30, 2016, respectively, were recognized as offsets to LNG terminal costs as they related to the sale of commissioning cargoes. Additionally, LNG revenues included revenues from Cheniere Marketing of $123.5 million and $163.3 million for the three and nine months ended September 30, 2016, respectively, as well as derivative gains and losses related to commodity and foreign currency exchange derivatives.

Operating costs and expenses



	Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)	2016		2015			Change			2016		2015			Change
Cost (cost recovery) of sales	$	252,343	$	(24,214	)	$	276,557		$	352,559	$	(22,077	)	$	374,636
Operating and maintenance expense	61,610		17,963			43,647			143,489		71,396			72,093
Development expense	1,546		4,935			(3,389		)	4,709		37,640			(32,931		)
Selling, general and administrative expense	59,418		97,332			(37,914		)	196,999		263,205			(66,206		)
Depreciation and amortization expense	49,212		21,638			27,574			106,082		59,561			46,521
Restructuring expense	26,241		—			26,241			49,196		—			49,196
Impairment expense	—		396			(396		)	10,095		572			9,523
Other	27		83			(56		)	189		348			(159		)
Total operating costs and expenses	$	450,397	$	118,133		$	332,264		$	863,318	$	410,645		$	452,673

Our total operating costs and expenses increased $332.3 million and $452.7 million during the three and nine months ended September 30, 2016 compared to the three and nine months ended September 30, 2015, respectively, primarily as a result of the commencement of operations of Trains 1 and 2 of the SPL Project in May and September 2016, respectively, compared to a significant cost recovery recorded during the three and nine months ended September 30, 2015. This cost recovery was due to a $32.2 million increase in fair value for our natural gas supply contracts recorded for the period, which we recognized following the completion and placement into service of certain modifications to the underlying pipeline infrastructure and the resulting development of a market for physical gas delivery at locations specified in a portion of our natural gas supply contracts. 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 nine months ended September 30, 2016 was vessel charter costs of $20.8 million and $36.9 million, respectively, which were incurred throughout the period, including the period prior to substantial completion of Trains 1 and 2 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 nine months ended September 30, 2016 as we began depreciation of our assets related to Trains 1 and 2 of the SPL Project upon reaching substantial completion. Additionally, in 2015, we initiated certain organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment. As a result of these efforts, we recorded $26.2 million and $49.2 million of restructuring charges and other costs associated with restructuring and operational efficiency initiatives during the three and nine months ended September 30, 2016, respectively.

Offsetting the increases above was a decrease in selling, general and administrative expense, which was primarily due to the timing of share-based compensation recognition and the recognition of certain employee-related costs within restructuring expense during the three and nine months ended September 30, 2016 historically reported in selling, general and administrative expense, a reduction in certain professional services fees and reallocation of costs from selling, 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 nine months ended September 30, 2016 compared to the three and nine months ended September 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 September 30,								Nine Months Ended September 30,
(in thousands)	2016			2015		Change			2016		2015			Change
Interest expense, net of capitalized interest	$	148,053		$	93,566	$	54,487		$	330,357	$	238,664		$	91,693
Loss on early extinguishment of debt	25,765			—		25,765			82,537		96,273			(13,736		)
Derivative loss (gain), net	(29,327		)	161,482		(190,809		)	242,228		242,123			105
Other expense (income)	(437		)	39		(476		)	5,564		(616		)	6,180
Total other expense	$	144,054		$	255,087	$	(111,033	)	$	660,686	$	576,444		$	84,242

Interest expense, net of capitalized interest, increased $54.5 million and $91.7 million in the three and nine months ended September 30, 2016, as compared to the three and nine months ended September 30, 2015, primarily as a result of an increase in our indebtedness outstanding (before premium, discount and unamortized debt issuance costs), from $16.3 billion as of September 30, 2015 to $21.5 billion as of September 30, 2016, and the decrease in the portion of total interest costs that could be capitalized as Trains 1 and 2 of the SPL Project were no longer in construction. For the three and nine months ended September 30, 2016, we incurred $340.8 million and $951.3 million of total interest cost, respectively, of which we capitalized $192.7 million and $620.9 million, respectively, which were directly related to the construction of the SPL Project and the CCL Project. For the three and nine months ended September 30, 2015, we incurred $286.0 million and $707.8 million of total interest cost, respectively, of which we capitalized $192.4 million and $469.2 million, respectively, which were directly related to the construction of the SPL Project and the CCL Project.

Loss on early extinguishment of debt increased $25.8 million in the three months ended September 30, 2016, as compared to the three months ended September 30, 2015 whereas it decreased $13.7 million in the nine months ended September 30, 2016, as compared to the nine months ended September 30, 2015. Loss on early extinguishment of debt during the three months ended September 30, 2016 was attributable to the $25.8 million write-off of debt issuance costs related to the prepayment of outstanding borrowings and termination of commitments under the 2015 SPL Credit Facilities of approximately $1.4 billion in September 2016 in connection with the issuance of the 2027 SPL Senior Notes. Loss on early extinguishment of debt during the nine months ended September 30, 2016 further included a $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, a $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 a $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 nine months ended September 30, 2015 was attributable to a $7.3 million write-off of debt issuance costs and deferred commitment fees related to the termination and replacement of the 2013 SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015 and a $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 (gain), net decreased $190.8 million from a loss of $161.5 million in the three months ended September 30, 2015 to a gain of $29.3 million in the three months ended September 30, 2016, primarily due to a relative increase in the forward LIBOR curve in the three months ended September 30, 2016 as compared to the three months ended September 30, 2015. Derivative loss, net did not significantly change between the nine months ended September 30, 2016 and 2015. Derivative loss, net during the nine months ended September 30, 2016 was primarily due to a decrease in the forward LIBOR curve during the period and an increase in the notional amounts of our interest rate derivatives. Derivative loss, net recognized during the nine months ended September 30, 2015 was primarily due to a decrease in the forward LIBOR curve during the period, the loss incurred upon meeting the contingency related to the CCH Interest Rate Derivatives and the loss recognized 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 September 30,									Nine Months Ended September 30,
(in thousands)	2016			2015			Change			2016			2015			Change
Income tax provision (benefit)	$	1,638		$	(69	)	$	1,707		$	1,911		$	102		$	1,809
Net loss attributable to non-controlling interest	(29,974		)	(9,284		)	(20,690		)	(94,636		)	(100,726		)	6,090

Net loss attributable to non-controlling interest increased $20.7 million in the three months ended September 30, 2016 as compared to the three months ended September 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 $24.1 million in the three months ended September 30, 2015 to $81.5 million in the three months ended September

30, 2016 primarily due to increased interest expense, net of amounts capitalized, and increased loss on early extinguishment of debt, partially offset by decreased derivative loss and increased income from operations primarily as a result of the commencement of operations of Trains 1 and 2 of the SPL Project. Net loss attributable to non-controlling interest decreased $6.1 million in the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, primarily due to increased income from operations, decreased loss on early extinguishment of debt and decreased derivative loss, net, which were partially offset by increased interest expense, net of amounts capitalized.

Off-Balance Sheet Arrangements

As of September 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 19—Recent Accounting Standards of our Notes to Consolidated Financial Statements.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Cash Investments

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

Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts 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 September 30, 2016, we estimated the fair value of the Liquefaction Supply Derivatives to be $12.1 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 $0.2 million as of September 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 September 30, 2016, we estimated the fair value of the LNG Trading Derivatives to be a liability of $0.3 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 $4.4 million as of September 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 September 30, 2016, we estimated the fair value of the SPL Interest Rate Derivatives to be a liability of $15.9 million. This 10% change in interest rates would have resulted in a change in the fair value of the SPL Interest Rate Derivatives of $1.6 million as of September 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 nine months ended September 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 September 30, 2016, we estimated the fair value of the CQP Interest Rate Derivatives to be a liability of $12.2 million. This 10% change in interest rates would have resulted in a change in the fair value of the CQP Interest Rate Derivatives of $3.9 million as of September 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 September 30, 2016, we estimated the fair value of the CCH Interest Rate Derivatives to be a liability of $297.5 million. This 10% change in interest rates would have resulted in a change in the fair value of the CCH Interest Rate Derivatives of $38.8 million as of September 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 nine months ended September 30, 2016.

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 September 30, 2016, we estimated the fair value of the FX Derivatives to be a liability of $1.2 million. This 10% change in FX rates would have resulted in a change in the fair value of the FX Derivatives of $0.1 million as of September 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.

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.

Louisiana Department of Environmental Quality (“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. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery, which is ongoing.

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 sought $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, which subsequently transferred the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was assigned Civil Action No. 4:16-cv-01628 and transferred to the same judge presiding over the Texas Suit for coordinated handling. On August 22, 2016, Parallax Enterprises voluntarily dismissed all claims asserted against CLNGT and CEI in the Louisiana Suit without prejudice to refiling. CEI does not expect that the resolution of this litigation will have a material adverse impact on its 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.


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

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended September 30, 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
July 1 - 31, 2016	13,307	$38.71	—	—
August 1 - 31, 2016	345,200	$42.13	—	—
September 1 - 30, 2016	—	$—	—	—
Total	358,507		—	—


(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 September 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. During the quarter ended September 30, 2016, we did not engage in any transactions with Iran or with persons or entities related to Iran.


ITEM 6.	EXHIBITS



Exhibit No.		Description
3.1		Amendment No. 1 to the Amended and Restated Bylaws of Cheniere Energy, Inc., dated September 15, 2016 (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on September 19, 2016)
4.1		Eighth Supplemental Indenture, dated as of September 19, 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 September 23, 2016)
4.2		Ninth Supplemental Indenture, dated as of September 23 2016, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 23, 2016)
10.1†		Release Agreement between Cheniere Energy, Inc. and Meg A. Gentle, dated August 26, 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 August 26, 2016)
10.2		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-00048 N2 Supply for High Pressure Tightness Test During Commissioning and Startup, dated July 12, 2016, (ii) the Change Order CO-00050 Train 2 N2 Dryout, dated July 29, 2016, (iii) the Change Order CO-00051 Six-Day Work Week for Insulation Scope — Subproject 2, dated August 9, 2016, and (iv) the Change Order CO-00052 Process Flares Modification Provisional Sum, dated September 1, 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 10.1 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 2, 2016)
10.3		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-00024 Additional Support for FERC Document Requests, dated June 20, 2016, (ii) the Change Order CO-00025 N2 Supply for High Pressure Tightness Test During Commissioning and Startup, dated July 12, 2016, (iii) the Change Order CO-00027 Addition of Check Valves to Condensate Lines, dated July 29, 2016, (iv) the Change Order CO-00028 Additional Professional Services Support Hours for the Flare System Evaluation, dated August 3, 2016, and (v) the Change Order CO-00029 Lump Sum Process Flares Modification, dated September 1, 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 10.2 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 2, 2016)
10.4		Change order 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.: the Change Order CO-00011 Site Drainage Design Change: Professional Service Hours, dated July 26, 2016 (Incorporated by reference to Exhibit 10.3 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 2, 2016)
10.5*		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-00022 Permanent Plant Building Modifications, dated June 20, 2016 and (ii) the Change Order CO-00024 N2 Dewar Interface, Temporary Power to Air Cooler, Condensate Pipeline Maximum Allowable Operating Pressure, dated June 28, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
10.6		Registration Rights Agreement, dated as of September 23, 2016, between Sabine Pass Liquefaction, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 23, 2016)
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



Exhibit No.		Description
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.

SIGNATURES

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



		CHENIERE ENERGY, INC.

Date:	November 2, 2016	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)

Date:	November 2, 2016	By:	/s/ Leonard Travis
			Leonard Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)



	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations	4
	Consolidated Statement of Stockholders’ Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49

Item 4.	Controls and Procedures	50

Part II. Other Information
Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

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

Item 5.	Other Information	52

Item 6.	Exhibits	53

	Signatures	55

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