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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 March 31, 2018

¨ 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

As of May 1, 2018, the issuer had 243,605,883 shares of Common Stock outstanding.

CHENIERE ENERGY, INC.

TABLE OF CONTENTS



	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Income	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	28

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45

Item 4.	Controls and Procedures	46

Part II. Other Information
Item 1.	Legal Proceedings	47

Item 1A.	Risk Factors	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47

Item 6.	Exhibits	48

	Signatures	49

DEFINITIONS

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

Common Industry and Other Terms



Bcf		billion cubic feet
Bcf/d		billion cubic feet per day
Bcf/yr		billion cubic feet per year
Bcfe		billion cubic feet equivalent
DOE		U.S. Department of Energy
EPC		engineering, procurement and construction
FERC		Federal Energy Regulatory Commission
FTA countries		countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP		generally accepted accounting principles in the United States
Henry Hub		the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR		London Interbank Offered Rate
LNG		liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu		million British thermal units, an energy unit
mtpa		million tonnes per annum
non-FTA countries		countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC		U.S. Securities and Exchange Commission
SPA		LNG sale and purchase agreement
TBtu		trillion British thermal units, an energy unit
Train		an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA		terminal use agreement

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of March 31, 2018, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to “Cheniere,” the “Company,” “we,” “us” and “our” refer to Cheniere Energy, Inc. and its consolidated subsidiaries, including our publicly traded subsidiaries, Cheniere Partners and Cheniere Holdings.

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 millions, except share data)



	March 31,			December 31,
	2018			2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	715		$	722
Restricted cash	1,696			1,880
Accounts and other receivables	606			369
Accounts receivable—related party	2			2
Inventory	123			243
Derivative assets	23			57
Other current assets	103			96
Total current assets	3,268			3,369

Non-current restricted cash	11			11
Property, plant and equipment, net	24,474			23,978
Debt issuance costs, net	138			149
Non-current derivative assets	81			34
Goodwill	77			77
Other non-current assets, net	292			288
Total assets	$	28,341		$	27,906

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	21		$	25
Accrued liabilities	729			1,078
Deferred revenue	120			111
Derivative liabilities	25			37
Total current liabilities	895			1,251

Long-term debt, net	25,656			25,336
Non-current deferred revenue	—			1
Non-current derivative liabilities	9			19
Other non-current liabilities	74			59

Commitments and contingencies (see Note 15)

Stockholders’ equity
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—			—
Common stock, $0.003 par value
Authorized: 480.0 million shares at March 31, 2018 and December 31, 2017
Issued: 250.5 million shares and 250.1 million shares at March 31, 2018 and December 31, 2017, respectively
Outstanding: 237.9 million shares and 237.6 million shares at March 31, 2018 and December 31, 2017, respectively	1			1
Treasury stock: 12.6 million shares and 12.5 million shares at March 31, 2018 and December 31, 2017, respectively, at cost	(392		)	(386		)
Additional paid-in-capital	3,264			3,248
Accumulated deficit	(4,270		)	(4,627		)
Total stockholders’ deficit	(1,397		)	(1,764		)
Non-controlling interest	3,104			3,004
Total equity	1,707			1,240
Total liabilities and equity	$	28,341		$	27,906

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share data)

(unaudited)



	Three Months Ended March 31,
	2018			2017
Revenues
LNG revenues	$	2,166		$	1,143
Regasification revenues	65			65
Other revenues	10			3
Other—related party	1			—
Total revenues	2,242			1,211

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	1,178			624
Operating and maintenance expense	140			78
Development expense	1			3
Selling, general and administrative expense	67			54
Depreciation and amortization expense	109			70
Restructuring expense	—			6
Total operating costs and expenses	1,495			835

Income from operations	747			376

Other income (expense)
Interest expense, net of capitalized interest	(216		)	(165		)
Loss on early extinguishment of debt	—			(42		)
Derivative gain, net	77			1
Other income	7			2
Total other expense	(132		)	(204		)

Income before income taxes and non-controlling interest	615			172
Income tax provision	(15		)	—
Net income	600			172
Less: net income attributable to non-controlling interest	243			118
Net income attributable to common stockholders	$	357		$	54

Net income per share attributable to common stockholders—basic	$	1.52		$	0.23
Net income per share attributable to common stockholders—diluted	$	1.50		$	0.23

Weighted average number of common shares outstanding—basic	235.5			232.4
Weighted average number of common shares outstanding—diluted	238.0			232.7

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(in millions)

(unaudited)



	Total Stockholders’ Equity
	Common Stock			Treasury Stock				Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Equity
	Shares	Par Value Amount		Shares	Amount			Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Equity
Balance at December 31, 2017	237.6	$	1	12.5	$	(386	)	$	3,248	$	(4,627	)	$	3,004		$	1,240
Issuances of restricted stock	0.3	—		—	—			—		—			—			—
Share-based compensation	—	—		—	—			16		—			—			16
Shares repurchased related to share-based compensation	—	—		0.1	(6		)	—		—			—			(6		)
Net income attributable to non-controlling interest	—	—		—	—			—		—			243			243
Distributions to non-controlling interest	—	—		—	—			—		—			(143		)	(143		)
Net income	—	—		—	—			—		357			—			357
Balance at March 31, 2018	237.9	$	1	12.6	$	(392	)	$	3,264	$	(4,270	)	$	3,104		$	1,707

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)



	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities
Net income	$	600		$	172
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	109			70
Share-based compensation expense	28			24
Non-cash interest expense	15			20
Amortization of debt issuance costs, deferred commitment fees, premium and discount	17			17
Loss on early extinguishment of debt	—			42
Total losses (gains) on derivatives, net	(31		)	44
Net cash used for settlement of derivative instruments	(4		)	(29		)
Other	(10		)	—
Changes in operating assets and liabilities:
Accounts and other receivables	(237		)	(6		)
Inventory	120			54
Accounts payable and accrued liabilities	(156		)	(76		)
Deferred revenue	8			(11		)
Other, net	10			(12		)
Net cash provided by operating activities	469			309

Cash flows from investing activities
Property, plant and equipment, net	(776		)	(1,319		)
Other	—			29
Net cash used in investing activities	(776		)	(1,290		)

Cash flows from financing activities
Proceeds from issuances of debt	266			2,862
Repayments of debt	—			(703		)
Debt issuance and deferred financing costs	(1		)	(43		)
Distributions and dividends to non-controlling interest	(143		)	(20		)
Payments related to tax withholdings for share-based compensation	(6		)	(1		)
Net cash provided by financing activities	116			2,095

Net increase (decrease) in cash, cash equivalents and restricted cash	(191		)	1,114
Cash, cash equivalents and restricted cash—beginning of period	2,613			1,827
Cash, cash equivalents and restricted cash—end of period	$	2,422		$	2,941

Balances per Consolidated Balance Sheet:



	March 31,
	2018
Cash and cash equivalents	$	715
Restricted cash	1,696
Non-current restricted cash	11
Total cash, cash equivalents and restricted cash	$	2,422

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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

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 in stages. The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the CCL Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). The CCL Project also includes a 23-mile natural gas supply pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”), which is being constructed concurrently with the first stage. Trains 1 and 2 are currently under construction, and Train 3 is being commercialized and has all necessary regulatory approvals in place. The construction of the Corpus Christi Pipeline is expected to be completed in second quarter of 2018.

Additionally, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project and recently amended our regulatory filings with FERC to incorporate a project design change, from two Trains with an expected aggregate nominal production capacity of approximately 9.0 mtpa to up to seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa. We remain focused on leveraging infrastructure through the expansion of our existing sites. We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision (“FID”).

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

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

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

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



	March 31,		December 31,
	2018		2017
Current restricted cash
SPL Project	$	561	$	544
Cheniere Partners and cash held by guarantor subsidiaries	916		1,045
CCL Project	83		227
Cash held by our subsidiaries restricted to Cheniere	136		64
Total current restricted cash	$	1,696	$	1,880

Non-current restricted cash
Other	$	11	$	11

Under Cheniere Partners’ $2.8 billion credit facilities (the “2016 CQP Credit Facilities”), Cheniere Partners, as well as Cheniere Investments, SPLNG 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, SPLNG 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 March 31, 2018 and December 31, 2017, accounts and other receivables consisted of the following (in millions):



	March 31,		December 31,
	2018		2017
Trade receivables
SPL	$	232	$	185
Cheniere Marketing	351		163
Other accounts receivable	23		21
Total accounts and other receivables	$	606	$	369

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.

NOTE 4—INVENTORY

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



	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	24		44
LNG in-transit	30		130
Materials and other	53		52
Total inventory	$	123	$	243

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

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



	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	12,675		$	12,687
LNG terminal construction-in-process	12,547			11,932
LNG site and related costs	86			86
Accumulated depreciation	(983		)	(882		)
Total LNG terminal costs, net	24,325			23,823
Fixed assets and other
Computer and office equipment	14			14
Furniture and fixtures	19			19
Computer software	93			92
Leasehold improvements	41			41
Land	59			59
Other	16			16
Accumulated depreciation	(93		)	(86		)
Total fixed assets and other, net	149			155
Property, plant and equipment, net	$	24,474		$	23,978

Depreciation expense was $108 million and $70 million during the three months ended March 31, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $131 million in the three months ended March 31, 2017 that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the SPL Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three months ended March 31, 2018.

NOTE 6—DERIVATIVE INSTRUMENTS

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


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


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


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


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

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Income to the extent not utilized for the commissioning process.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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



	Fair Value Measurements as of
	March 31, 2018											December 31, 2017
	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
CQP Interest Rate Derivatives asset	$	—		$	27		$	—	$	27		$	—		$	21		$	—	$	21
CCH Interest Rate Derivatives asset (liability)	—			43			—		43			—			(32		)	—		(32		)
Liquefaction Supply Derivatives asset	—			—			10		10			2			10			43		55
LNG Trading Derivatives asset (liability)	(9		)	3			—		(6		)	(13		)	5			—		(8		)
FX Derivatives liability	—			(4		)	—		(4		)	—			(1		)	—		(1		)

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

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

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

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2018:



	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$10	Market approach incorporating present value techniques	Basis Spread	$(0.725) - $0.095

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2018 and 2017 (in millions):



	Three Months Ended March 31,
	2018			2017
Balance, beginning of period	$	43		$	79
Realized and mark-to-market losses:
Included in cost of sales	(13		)	(41		)
Purchases and settlements:
Purchases	3			4
Settlements	(23		)	(1		)
Balance, end of period	$	10		$	41
Change in unrealized gains relating to instruments still held at end of period	$	(13	)	$	(41	)

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

During the three months ended March 31, 2018, there were no changes to the terms of the interest rate swaps (“CQP Interest Rate Derivatives”) entered into by CQP to hedge a portion of the variable interest payments on its 2016 CQP Credit Facilities or the interest rate swaps (“CCH Interest Rate Derivatives”) entered into by CCH 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”). See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information.

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

As of March 31, 2018, we had the following Interest Rate Derivatives outstanding:

Initial Notional Amount

Maximum Notional Amount

Effective Date

Maturity Date

Weighted Average Fixed Interest Rate Paid

Variable Interest Rate Received

CQP Interest Rate Derivatives

$225 million

$1.3 billion

March 22, 2016

February 29, 2020

1.19%

One-month LIBOR

CCH Interest Rate Derivatives

$29 million

$4.9 billion

May 20, 2015

May 31, 2022

2.29%

One-month LIBOR

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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



	March 31, 2018								December 31, 2017
	CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total			CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total
Balance Sheet Location
Derivative assets	$	12	$	—		$	12		$	7	$	—		$	7
Non-current derivative assets	15		49			64			14		3			17
Total derivative assets	27		49			76			21		3			24

Derivative liabilities	—		(6		)	(6		)	—		(20		)	(20		)
Non-current derivative liabilities	—		—			—			—		(15		)	(15		)
Total derivative liabilities	—		(6		)	(6		)	—		(35		)	(35		)

Derivative asset (liability), net	$	27	$	43		$	70		$	21	$	(32	)	$	(11	)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain, net on our Consolidated Statements of Income during the three months ended March 31, 2018 and 2017 (in millions):



	Three Months Ended March 31,
	2018		2017
CQP Interest Rate Derivatives gain	$	8	$	2
CCH Interest Rate Derivatives gain	69		1
SPL Interest Rate Derivatives loss	—		(2		)

Commodity Derivatives

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



	March 31, 2018									December 31, 2017
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total			Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total
Balance Sheet Location
Derivative assets	$	8		$	3		$	11		$	41		$	9		$	50
Non-current derivative assets	9			7			16			17			—			17
Total derivative assets	17			10			27			58			9			67

Derivative liabilities	(4		)	(14		)	(18		)	—			(17		)	(17		)
Non-current derivative liabilities	(3		)	(2		)	(5		)	(3		)	—			(3		)
Total derivative liabilities	(7		)	(16		)	(23		)	(3		)	(17		)	(20		)

Derivative asset (liability), net	$	10		$	(6	)	$	4		$	55		$	(8	)	$	47

Notional amount (in TBtu) (3)	2,573			27						2,539			25


(1)	Does not include a collateral call of $1 million for such contracts, which is included in other current assets in our Consolidated Balance Sheets as of both March 31, 2018 and December 31, 2017.


(2)	Does not include collateral of $25 million and $28 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017, respectively.


(3)	SPL had secured up to approximately 2,179 TBtu and 2,214 TBtu of natural gas feedstock through natural gas supply contracts as of March 31, 2018 and December 31, 2017, respectively. CCL has secured up to approximately 2,057 TBtu and 2,024 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which is subject to the

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

achievement of certain project milestones and other conditions precedent, as of March 31, 2018 and December 31, 2017, respectively.

The following table shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Income during the three months ended March 31, 2018 and 2017 (in millions):



	Statement of Income Location (1)	Three Months Ended March 31,
	Statement of Income Location (1)	2018		2017
LNG Trading Derivatives gain (loss)	LNG revenues	$	7	$	(6	)
Liquefaction Supply Derivatives loss (2)	Cost of sales	50		39


(1)	Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.


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

FX Derivatives

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



		Fair Value Measurements as of
	Balance Sheet Location	March 31, 2018			December 31, 2017
FX Derivatives	Non-current derivative assets	$	1		$	—
FX Derivatives	Derivative liabilities	(1		)	—
FX Derivatives	Non-current derivative liabilities	(4		)	(1		)

The total notional amount of our FX Derivatives was $79 million and $27 million as of March 31, 2018 and December 31, 2017, respectively.

The following table shows the changes in the fair value of our FX Derivatives recorded on our Consolidated Statements of Income during the three months ended March 31, 2018 and 2017 (in millions):



		Three Months Ended March 31,
	Statement of Income Location	2018			2017
FX Derivatives loss	LNG revenues	$	(3	)	$	—

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



	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
As of March 31, 2018
CQP Interest Rate Derivatives	$	27		$	—		$	27
CCH Interest Rate Derivatives	49			—			49
CCH Interest Rate Derivatives	(7		)	1			(6		)
Liquefaction Supply Derivatives	25			(8		)	17
Liquefaction Supply Derivatives	(10		)	3			(7		)
LNG Trading Derivatives	16			(6		)	10
LNG Trading Derivatives	(22		)	6			(16		)
FX Derivatives	1			—			1
FX Derivatives	(5		)	—			(5		)
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
CCH Interest Rate Derivatives	3			—			3
CCH Interest Rate Derivatives	(35		)	—			(35		)
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)
LNG Trading Derivatives	9			—			9
LNG Trading Derivatives	(37		)	20			(17		)
FX Derivatives	(1		)	—			(1		)

NOTE 7—OTHER NON-CURRENT ASSETS

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



	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		97
Advances and other asset conveyances to third parties to support LNG terminals	53		48
Tax-related payments and receivables	28		29
Equity method investments	64		64
Other	36		24
Total other non-current assets, net	$	292	$	288

Equity Method Investments

Our equity method investments consist of interests in privately-held companies. In 2017, we acquired an equity interest in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”). Midship Pipeline is pursuing the development, construction, operation and maintenance of an approximately 230-mile natural gas pipeline project (the “Midship Project”) that connects new production in the Anadarko Basin to Gulf Coast markets. Midship Holdings entered into agreements with investment funds managed by EIG Global Energy Partners (“EIG”) under which EIG-managed funds committed to make an investment of up to $500 million (the “EIG Investment”) in the Midship Project, subject to the terms and conditions contained in the applicable agreements. The EIG Investment, when combined with equity contributed by us, is intended to ensure the Midship Project has the equity funding expected to be required to develop and construct the project. Midship Holdings requires acceptable financing arrangements and regulatory and other approvals before construction of the proposed Midship Project commences.

We have determined that Midship Holdings is a variable interest entity (“VIE”) because it is thinly capitalized at formation such that the total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

financial support. We do not consolidate Midship Holdings because we do not have power to direct the activities that most significantly impact its economic performance. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause a change in our identification of a VIE or determination of the primary beneficiary to a VIE. We account for our investment in Midship Holdings under the equity method as we have the ability to exercise significant influence over the operating and financial policies of Midship Holdings through our non-controlling voting rights on its board of managers. Our investment in Midship Holdings was $55 million at both March 31, 2018 and December 31, 2017. Obligations to make additional investments in Midship Holdings are not significant and we have not provided financial support to Midship Holdings beyond amounts contractually required.

Cheniere LNG O&M Services, LLC (“O&M Services”), our wholly owned subsidiary, provides the development, construction, operation and maintenance services associated with the Midship Project pursuant to agreements in which O&M Services receives an agreed upon fee and reimbursement of costs incurred. O&M Services recorded $1 million and zero of income in other—related party during the three months ended March 31, 2018 and 2017, respectively, and $2 million of accounts receivable—related party as of both March 31, 2018 and December 31, 2017 for services provided to Midship Pipeline under these agreements. CCL has entered into transportation precedent agreements with Midship Pipeline to secure firm pipeline transportation capacity for a period of 10 years following commencement of the Midship Project.

NOTE 8—NON-CONTROLLING INTEREST

As of both March 31, 2018 and December 31, 2017, we owned 82.7% of Cheniere Holdings as well as the director voting share, with the remaining non-controlling interest held by the public. Cheniere Holdings owns a 48.6% limited partner interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco LP and the public. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners. Both Cheniere Holdings and Cheniere Partners are accounted for as variable interest entities. See Note 9—Variable Interest Entities of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for further information.

NOTE 9—ACCRUED LIABILITIES

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



	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	251	$	397
Compensation and benefits	47		141
LNG terminals and related pipeline costs	380		490
Other accrued liabilities	51		50
Total accrued liabilities	$	729	$	1,078

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—DEBT

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



	March 31,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $5	1,505			1,505
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
2016 CQP Credit Facilities	1,090			1,090
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250			1,250
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500			1,500
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500			1,500
2015 CCH Credit Facility	2,751			2,485
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,341			1,305
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”), net of unamortized discount of $114 and $121	1,047			1,040
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”), net of unamortized discount of $314 and $314	311			311
$750 million Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	—			—
Unamortized debt issuance costs	(293		)	(305		)
Total long-term debt, net	25,656			25,336

Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”)	—			—
Cheniere Marketing trade finance facilities	—			—
Total current debt	—			—

Total debt, net	$	25,656		$	25,336

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2018 (in millions):



	SPL Working Capital Facility		2016 CQP Credit Facilities		2015 CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Original facility size	$	1,200	$	2,800	$	8,404	$	350	$	750
Less:
Outstanding balance	—		1,090		2,751		—		—
Commitments prepaid or terminated	—		1,470		3,832		—		—
Letters of credit issued	706		20		—		289		—
Available commitment	$	494	$	220	$	1,821	$	61	$	750

Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)		LIBOR plus 2.25% or base rate plus 1.25% (2)		LIBOR plus 1.50% - 2.00% or base rate plus 0.50% - 1.00%		LIBOR plus 3.25% or base rate plus 2.25%
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020, with principal payments due quarterly commencing on March 31, 2019		Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date		December 14, 2021, with various terms for underlying loans		March 2, 2021


(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 the completion of Trains 1 and 2 of the CCL Project as defined in the common terms agreement.

Convertible Notes

Below is a summary of our convertible notes outstanding as of March 31, 2018 (in millions):



	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000		$	1,000		$	625
Debt component, net of discount	$	1,047		$	1,341		$	311
Equity component	$	206		$	—		$	194
Interest payment method	Paid-in-kind			Paid-in-kind (1)			Cash
Conversion by us (2)	—			(3)			(4)
Conversion by holders (2)	(5)			(6)			(7)
Conversion basis	Cash and/or stock			Stock			Cash and/or stock
Conversion value in excess of principal	$	—		$	—		$	—
Maturity date	May 28, 2021			March 1, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate (8)	8.3		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (9)	3.2 years			2.5 years			27.0 years


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


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


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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

for the 90 trading day period prior to the date notice is provided, and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date notice is provided.


(4)	Redeemable at any time after March 15, 2020 at a redemption price payable in cash equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date.


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


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

(7)

Prior to December 15, 2044, convertible only under certain circumstances as specified in the indenture; thereafter, holders may convert their notes regardless of these circumstances. The conversion rate will initially equal 7.2265 shares of our common stock per $1,000 principal amount of the 2045 Cheniere Convertible Senior Notes, which corresponds to an initial conversion price of approximately $138.38 per share of our common stock (subject to adjustment upon the occurrence of certain specified events).


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


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

Restrictive Debt Covenants

As of March 31, 2018, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Interest Expense

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



	Three Months Ended March 31,
	2018			2017
Interest cost on convertible notes:
Interest per contractual rate	$	58		$	53
Amortization of debt discount	8			7
Amortization of debt issuance costs	2			2
Total interest cost related to convertible notes	68			62
Interest cost on debt excluding convertible notes	336			292
Total interest cost	404			354
Capitalized interest	(188		)	(189		)
Total interest expense, net	$	216		$	165

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

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



	March 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	18,609	$	19,557	$	18,610	$	20,075
2037 SPL Senior Notes (2)	800		838		800		871
Credit facilities (3)	3,841		3,841		3,575		3,575
2021 Cheniere Convertible Unsecured Notes, net of discount (2)	1,047		1,152		1,040		1,136
2025 CCH HoldCo II Convertible Senior Notes (2)	1,341		1,521		1,305		1,535
2045 Cheniere Convertible Senior Notes, net of discount (4)	311		485		311		447

(1)

Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.


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

(3)

Includes SPL Working Capital Facility, 2016 CQP Credit Facilities, 2015 CCH Credit Facility, CCH Working Capital Facility, Cheniere Revolving Credit Facility and Cheniere Marketing trade finance facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.


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

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three months ended March 31, 2018 and 2017 (in millions):



	Three Months Ended March 31,
	2018		2017
LNG revenues	$	2,143	$	1,143
Regasification revenues	65		65
Other revenues	10		1
Other—related party	1		—
Total revenues from customers	2,219		1,209
Revenues from derivative instruments	23		2
Total revenues	$	2,242	$	1,211

LNG Revenues

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

We intend to primarily use LNG sourced from our Sabine Pass or Corpus Christi terminal to provide contracted volumes to our customers. However, we supplement this LNG with volumes procured from third parties. We recognized $110 million and $48 million in LNG revenues from LNG that was procured from third parties for the three months ended March 31, 2018 and 2017.

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

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

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

Regasification Revenues

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

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

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6.

Upon substantial completion of Train 3, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

During the three months ended March 31, 2018 and 2017, SPL recorded $8 million and zero as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” (in millions):



	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	111		$	73
Cash received but not yet recognized	120			61
Revenue recognized from prior period deferral	(111		)	(71		)
Deferred revenues, end of period	$	120		$	63

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the three months ended March 31, 2018 and 2017 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of March 31, 2018:


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

We have elected the following optional exemptions which omit certain potential future sources of revenue from the table above:


(1)	We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. The receipt of such variable consideration is considered constrained due to the uncertainty of ultimate pricing and receipt and we have not included such variable consideration in the transaction price. During the three months ended March 31, 2018, approximately 56% of our LNG Revenues from contracts with a duration of over one year and approximately 3% of our Regasification Revenues were related to variable consideration received from customers.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train or obtaining financing. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

NOTE 12—INCOME TAXES

During the three months ended March 31, 2018, we recorded a $15 million income tax provision, which was primarily related to increased profitability in the U.K. We have elected to account for the tax on global intangible low-taxed income (“GILTI”) as a tax expense in the period in which it is incurred.

Due to historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal and state net deferred tax assets at March 31, 2018 and December 31, 2017.

NOTE 13—SHARE-BASED COMPENSATION

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

For the three months ended March 31, 2018, we granted 1.5 million restricted stock units and 0.2 million performance stock units at target performance under the 2011 Plan to certain employees. Restricted stock units are stock awards that vest over a three-year service period and entitle the holder to receive shares of our common stock upon vesting, subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with us prior to the lapse of the restrictions. Performance stock units provide for three-year cliff vesting with payouts based on our cumulative distributable cash flow per share from January 1, 2018 through December 31, 2020 compared to a pre-established performance target. The number of shares that may be earned at the end of the vesting period ranges from 50 to 200 percent of the target award amount if the threshold performance is met. Both restricted stock units and performance stock units will be settled in Cheniere common stock (on a one-for-one basis) and are classified as equity awards.

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



	Three Months Ended March 31,
	2018			2017
Share-based compensation costs, pre-tax:
Equity awards	$	17		$	5
Liability awards	17			27
Total share-based compensation	34			32
Capitalized share-based compensation	(6		)	(8		)
Total share-based compensation expense	$	28		$	24
Tax benefit associated with share-based compensation expense	$	2		$	—

For further discussion of our equity incentive plans, see Note 15—Share-Based Compensation of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

NOTE 14—NET INCOME PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table reconciles basic and diluted weighted average common shares outstanding for the three months ended March 31, 2018 and 2017 (in millions, except per share data):



	Three Months Ended March 31,
	2018		2017
Weighted average common shares outstanding:
Basic	235.5		232.4
Dilutive unvested stock	2.5		0.3
Diluted	238.0		232.7

Basic net income per share attributable to common stockholders	$	1.52	$	0.23
Diluted net income per share attributable to common stockholders	$	1.50	$	0.23

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



	Three Months Ended March 31,
	2018	2017
Unvested stock (1)	2.0	1.2
Convertible notes (2)	17.1	16.5
Total potentially dilutive common shares	19.1	17.7


(1)	Does not include 0.4 million shares and 5.1 million shares for the three months ended March 31, 2018 and 2017, respectively, of unvested stock because the performance conditions had not yet been satisfied as of March 31, 2018 and 2017, respectively.

(2)

Includes number of shares in aggregate issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes. There were no shares included in the computation of diluted net income 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 March 31, 2018.

NOTE 15—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of March 31, 2018, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

Obligations under Certain Guarantee Contracts

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

Legal Proceedings

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

On July 27, 2017, the Parallax entities named as defendants in the Texas Federal Suit reurged their motion to dismiss and simultaneously filed counterclaims against CLNGT and third party claims against us for breach of contract, breach of fiduciary duty, promissory estoppel, quantum meruit and fraudulent inducement of the Secured Note and Pledge Agreement, based on substantially the same factual allegations Parallax Enterprises made in the Louisiana Suit. These Parallax entities also simultaneously filed an action styled Cause No. 2017-49685, Parallax Enterprises, LLC, et al. v. Cheniere Energy, Inc., et al., in the 61st District Court of Harris County, Texas (the “Texas State Suit”), which asserts substantially the same claims these entities asserted in the Texas Federal Suit. On July 31, 2017, CLNGT withdrew its opposition to the dismissal of the Texas Federal Suit without prejudice on jurisdictional grounds and the federal court subsequently dismissed the Texas Federal Suit without prejudice. We and CLNGT simultaneously filed an answer and counterclaims in the Texas State Suit, asserting the same claims CLNGT had previously asserted in the Texas Federal Suit. Additionally, CLNGT filed third party claims against Parallax principals Martin Houston, Christopher Bowen Daniels, Howard Candelet and Mark Evans, as well as Tellurian Investments, Inc., Driftwood LNG, LLC, Driftwood LNG Pipeline LLC and Tellurian Services LLC, formerly known as Parallax Services LLC, including claims for tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement, fraudulent transfer, conspiracy/aiding and abetting. Discovery in the Texas State Suit is ongoing. Trial is currently set for September 2018.

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 16—CUSTOMER CONCENTRATION

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



	Percentage of Total Third-Party Revenues			Percentage of Accounts Receivable from Third Parties
		Three Months Ended March 31,		March 31,	December 31,
		2018	2017	2018	2017
Customer A		17%	33%	13%	28%
Customer B		12%	13%	7%	16%
Customer C		24%	—%	18%	14%
Customer D		*	—%	10%	—%
Customer E		*	10%	21%	15%
Customer F		*	—%	11%	—%

* Less than 10%

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Three Months Ended March 31,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	282	$	163

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $310 million and $503 million as of March 31, 2018 and 2017, respectively.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 18—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of March 31, 2018:

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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



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


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

Information Regarding Forward-Looking Statements

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


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

•

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


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


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


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


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


•	statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;


•	statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;


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


•	statements regarding marketing of volumes expected to be made available to our integrated marketing function; and


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

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2017. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis includes the following subjects:


•	Overview of Business


•	Overview of Significant Events


•	Liquidity and Capital Resources


•	Results of Operations


•	Off-Balance Sheet Arrangements


•	Summary of Critical Accounting Estimates


•	Recent Accounting Standards

Overview of Business

Cheniere, a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. Our vision is to provide clean, secure and affordable energy to the world, while responsibly delivering a reliable, competitive and integrated source of LNG, in a safe and rewarding work environment. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. As of March 31, 2018, we owned 100% of the general partner interest in Cheniere Partners and 82.7% of Cheniere Holdings, which is a publicly traded limited liability company formed in 2013 that owned a 48.6% limited partner interest in Cheniere Partners. We are currently developing and constructing two natural gas liquefaction and export facilities. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG.

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “SPL Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, SPL. Cheniere Partners plans to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through a wholly owned subsidiary, CTPL.

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

intrastate natural gas pipelines (the “Corpus Christi Pipeline”). Stage 1 and the Corpus Christi Pipeline are currently under construction, and Train 3 is being commercialized and has all necessary regulatory approvals in place. The construction of the Corpus Christi Pipeline is expected to be completed in second quarter of 2018.

Additionally, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (the “Corpus Christi Expansion Project”) and recently began the process of amending our regulatory filings with FERC to incorporate a project design change, from two Trains with an expected aggregate nominal production capacity of approximately 9.0 mtpa to up to seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa. We remain focused on expansion of our existing sites by leveraging existing infrastructure. We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision (“FID”). We have made an equity investment of $55 million in Midship Pipeline Company, LLC (“Midship Pipeline”), which is developing a pipeline with expected capacity of up to 1.44 million Dekatherms per day that will connect new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project.

Overview of Significant Events

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

Strategic


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


•	In January 2018, we entered into a 15-year SPA with Trafigura Pte Ltd for the sale of approximately 1 mtpa of LNG beginning in 2019.

Operational


•	As of April 30, approximately 90 cargoes have been produced, loaded and exported from the SPL Project in 2018. To date, approximately 350 cumulative LNG cargoes have been exported from the SPL Project, with deliveries to 26 countries and regions worldwide.

Financial


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

•

In April 2018, we engaged financial institutions to assist in the structuring and arranging of up to $6.4 billion of credit facilities for CCH through an amendment and upsize of its existing credit facilities (the “2015 CCH Credit Facility”), the proceeds of which will be used to fund a portion of the costs of developing, constructing and placing into service three Trains and related facilities of the CCL Project, and the related pipeline being developed near Corpus Christi, Texas and for related business purposes.


•	In April and May 2018, we acquired a total of 21,453,482 common shares of Cheniere Holdings in a series of privately negotiated transactions pursuant to share purchase and exchange agreements, in exchange for a total of 10,278,739 unregistered shares of Cheniere. Subsequent to the completion of these transactions, our ownership of Cheniere Holdings is approximately 91.9%.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, Cheniere, Cheniere Holdings, Cheniere Partners, SPL and the CCH Group operate with independent capital structures. We expect the cash needs for at least the next twelve months will be met for each of these independent capital structures as follows:

•SPL through project debt and borrowings and operating cash flows;


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

•Cheniere Holdings through distributions from Cheniere Partners;

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


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

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



	March 31,		December 31,
	2018		2017
Cash and cash equivalents	$	715	$	722
Restricted cash designated for the following purposes:
SPL Project	561		544
Cheniere Partners and cash held by guarantor subsidiaries	916		1,045
CCL Project	83		227
Other	147		75
Available commitments under the following credit facilities:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	494		470
2016 CQP Credit Facilities	220		220
2015 CCH Credit Facility	1,821		2,087
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”)	61		186
$750 million Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	750		750

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

Cheniere

Convertible Notes

In November 2014, we issued an aggregate principal amount of $1.0 billion of Convertible Unsecured Notes due 2021 (the “2021 Cheniere Convertible Unsecured Notes”). The 2021 Cheniere Convertible Unsecured Notes are convertible at the option of the holder into our common stock at the then applicable conversion rate, provided that the closing price of our common stock is greater than or equal to the conversion price on the date of conversion. In March 2015, we issued $625 million aggregate principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”). We have the right, at our option, at any time after March 15, 2020, to redeem all or any part of the 2045 Cheniere Convertible Senior Notes at a redemption price equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date. We have the option to satisfy the conversion obligation for the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes with cash, common stock or a combination thereof.

Cheniere Revolving Credit Facility

In March 2017, we entered into the Cheniere Revolving Credit Facility that may be used to fund, through loans and letters of credit, equity capital contributions to CCH HoldCo II and its subsidiaries for the development of the CCL Project and, provided that certain conditions are met, for general corporate purposes. No advances or letters of credit under the Cheniere Revolving Credit Facility were available until either (1) Cheniere’s unrestricted cash and cash equivalents are less than $500 million or (2) Train 4 of the SPL Project has achieved substantial completion.

The Cheniere Revolving Credit Facility matures on March 2, 2021 and contains representations, warranties and affirmative and negative covenants customary for companies like Cheniere with lenders of the type participating in the Cheniere Revolving Credit Facility that limit our ability to make restricted payments, including distributions, unless certain conditions are satisfied, as well as limitations on indebtedness, guarantees, hedging, liens, investments and affiliate transactions. Under the Cheniere Revolving Credit Facility, we are required to ensure that the sum of our unrestricted cash and the amount of undrawn commitments under the Cheniere Revolving Credit Facility is at least equal to the lesser of (1) 20% of the commitments under the Cheniere Revolving Credit Facility and (2) $100 million.

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

Cash Receipts from Subsidiaries

As of March 31, 2018, we had an 82.7% direct ownership interest in Cheniere Holdings. We receive dividends on our Cheniere Holdings shares from the distributions that Cheniere Holdings receives from Cheniere Partners. We received $98 million and $4 million in dividends on our Cheniere Holdings common shares during the three months ended March 31, 2018 and 2017, respectively.

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of March 31, 2018, we owned 82.7% of Cheniere Holdings, which owned a 48.6% interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners. We receive quarterly equity distributions from Cheniere Partners related to our 2% general partner interest and quarterly distributions from our incentive distribution rights.

We also receive fees for providing management services to Cheniere Holdings, Cheniere Partners, SPLNG, SPL and CTPL. We received $20 million and $47 million in total service fees from these subsidiaries during the three months ended March 31, 2018 and 2017, respectively.

Cheniere Partners

2025 CQP Senior Notes

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (collectively, the “CQP Guarantors”). The 2025 CQP Senior Notes are governed by an indenture (the “CQP Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2020, Cheniere Partners may redeem all or a part of the 2025 CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the 2025 CQP Senior Notes redeemed, plus the “applicable premium” set forth in the CQP Indenture, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020, Cheniere Partners may redeem up to 35% of the aggregate principal amount of the 2025 CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. Cheniere Partners also may at any time on or after October 1, 2020 through the maturity date of October 1, 2025, redeem the 2025 CQP Senior Notes, in whole or in part, at the redemption prices set forth in the CQP Indenture.

The 2025 CQP Senior Notes are Cheniere Partners’ senior obligations, ranking equally in right of payment with Cheniere Partners’ other existing and future unsubordinated debt and senior to any of its future subordinated debt. The 2025 CQP Senior Notes will be secured alongside the 2016 CQP Credit Facilities on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2016 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 2016 CQP Credit Facilities). The liens securing the 2025 CQP Senior Notes would be released if (1) the aggregate principal amount of all indebtedness then outstanding under the term loans under the 2016 CQP Credit Facilities secured by such liens does not exceed $1.0 billion and (2) the aggregate amount of Cheniere Partners’ secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the 2025 CQP Senior Notes or any other series of notes issued under the CQP Indenture) outstanding at any one time, together with all Attributable Indebtedness (as defined in the CQP Indenture) from sale-leaseback transactions (subject to certain exceptions), does not exceed the greater of (1) $1.5 billion and (2) 10% of net tangible assets. Upon the release of the liens securing the 2025 CQP Senior Notes, the limitation on liens covenant under the CQP Indenture will continue to govern the incurrence of liens by Cheniere Partners and the CQP Guarantors.

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 million CTPL tranche term loan that was used to prepay the $400 million term loan facility (the “CTPL Term Loan”) in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that was used to repay and redeem in November 2016 the approximately $2.1 billion of the senior notes previously issued by SPLNG, (3) a $125 million facility that may be used to satisfy a six-month debt service reserve requirement and (4) a $115 million revolving credit facility that may be used for general business purposes. In September 2017, Cheniere Partners issued the 2025 CQP Senior Notes and the net proceeds were used to prepay $1.5 billion of the outstanding indebtedness under the 2016 CQP Credit Facilities. As of both March 31, 2018 and December 31, 2017, Cheniere Partners had $220 million of available commitments, $20 million aggregate amount of issued letters of credit and $1.1 billion of outstanding borrowings under the 2016 CQP Credit Facilities.

The 2016 CQP Credit Facilities mature on February 25, 2020, with principal payments due quarterly commencing on March 31, 2019. 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 2016 CQP Credit Facilities, Cheniere Partners is required to hedge not less than 50% of the variable interest rate exposure on its projected aggregate outstanding balance, maintain a minimum debt service coverage ratio of at least 1.15x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55x in order to incur additional indebtedness to refinance a portion of the existing obligations.

The 2016 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than (1) SPL and (2) certain subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Sabine Pass LNG Terminal

Liquefaction Facilities

We are developing, constructing and operating the SPL Project at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completion of Trains 1, 2, 3 and 4 of the SPL Project and commenced operating activities in May 2016, September 2016, March 2017 and October 2017, respectively. The following table summarizes the status of Train 5 of the SPL Project as of March 31, 2018:



		SPL Train 5
Overall project completion percentage		89.3%
Completion percentage of:
Engineering		100%
Procurement		100%
Subcontract work		70.2%
Construction		78.0%
Date of expected substantial completion		1H 2019

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


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


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


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

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

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

Customers

SPL has entered into six fixed price SPAs with terms of at least 20 years (plus extension rights) with third parties to make available an aggregate amount of LNG that is between approximately 80% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 through 5. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Under SPL’s SPA with BG Gulf Coast LNG, LLC (“BG”), BG has contracted for volumes related to Trains 3 and 4 for which the obligation to make LNG available to BG is expected to commence approximately one year after the date of first commercial delivery for the respective Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $1.6 billion for Trains 1 through 3, increasing to $2.3 billion upon the date of first commercial delivery of Train 4 and to $2.9 billion upon the date of first commercial delivery of Train 5, with the applicable fixed fees starting from the date of first commercial delivery from the applicable Train, as specified in each SPA.

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

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing 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 March 31, 2018, SPL has secured up to approximately 2,179 TBtu of natural gas feedstock through long-term and short-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 of the SPL Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 5 of the SPL Project is approximately $3.1 billion reflecting amounts incurred under change orders through March 31, 2018. Total expected capital costs for Trains 1 through 5 are estimated to be

between $12.5 billion and $13.5 billion before financing costs and between $17.5 billion and $18.5 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Train 6

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

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Each of Total Gas & Power North America, Inc. (“Total”) and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after May 2016. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 3, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the three months ended March 31, 2018 and 2017, SPL recorded $8 million and zero, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

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

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 5 of the SPL Project will be financed through project debt and borrowings and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the SPL Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Train 5 of the SPL Project and to meet our currently anticipated capital, operating and debt service requirements. SPL began generating cash flows from operations from the SPL Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2, 3 and 4 subsequently achieved substantial completion in September 2016, March 2017 and October 2017, respectively. We realized offsets to LNG terminal costs of $131 million in the three months ended March 31, 2017 that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations, during the testing phase for the construction of those Trains of the SPL Project. We did not realize any offsets to LNG terminal costs in the three months ended March 31, 2018. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at March 31, 2018 and December 31, 2017 (in millions):



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

(1)

Includes SPL’s 5.625% Senior Secured Notes due 2021, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”) and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”) and Cheniere Partners’ 2025 CQP Senior Notes.


(2)	Includes SPL Working Capital Facility and CTPL and SPLNG tranche term loans outstanding under the 2016 CQP Credit Facilities.


(3)	Consists of SPL Working Capital Facility. Does not include the letters of credit issued or available commitments under the 2016 CQP Credit Facilities, which are not specifically for the Sabine Pass LNG Terminal.


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

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

SPL Senior Notes

The SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets.

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

Both the indenture governing the 2037 SPL Senior Notes (the “2037 SPL Senior Notes Indenture”) and the common indenture governing the remainder of the SPL Senior Notes (the “SPL Indenture”) include restrictive covenants. SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes and the SPL Working Capital Facility. Under the 2037 SPL Senior Notes Indenture and the SPL Indenture, SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025.

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“SPL Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“SPL Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the SPL Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the SPL Project, request an incremental increase in commitments of up to an additional $390 million. As of March 31, 2018 and 2017, SPL had $494 million and $653 million of available commitments, $706 million and $324 million aggregate amount of issued letters of credit and zero and $224 million of loans outstanding under the SPL Working Capital Facility, respectively.

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

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

Corpus Christi LNG Terminal

Liquefaction Facilities

The CCL Project is being developed and constructed at the Corpus Christi LNG terminal. In December 2014, we received authorization from the FERC to site, construct and operate Stages 1 and 2 of the CCL Project. The following table summarizes the overall project status of Stage 1 of the CCL Project as of March 31, 2018:



	CCL Stage 1
Overall project completion percentage	85.7%
Completion percentage of:
Engineering	100%
Procurement	100%
Subcontract work	68.9%
Construction	68.1%
Expected date of substantial completion	Train 1	1H 2019
	Train 2	2H 2019

Train 3 is being commercialized and has all necessary regulatory approvals in place. Separate from the CCH Group, we are also developing the Corpus Christi Expansion Project, adjacent to the CCL Project. We commenced the regulatory approval process in June 2015 and recently began the process of amending our regulatory filings with FERC to incorporate a project design change, from two Trains with an expected aggregate nominal production capacity of approximately 9.0 mtpa to up to seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa.

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


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

•

Corpus Christi Expansion Project—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 before the DOE. We intend to amend our DOE applications consistent with the design change in our amended FERC filings.

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.

Customers

CCL entered into eight fixed-price SPAs with terms of at least 20 years (plus extension rights) with seven third parties to make available an aggregate amount of LNG that is between approximately 85% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 and 2. Under these eight SPAs, the customers will purchase LNG from CCL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of Stage 1 of the CCL Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for Train 1 or Train 2, as specified in each SPA.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to $1.4 billion upon the date of first commercial delivery of Train 2 of the CCL Project, with the applicable fixed fees generally starting from the date of first commercial delivery from the applicable Train, as specified in each SPA.

In addition, Cheniere Marketing has entered into an SPA with CCL to purchase, at Cheniere Marketing’s option, any LNG produced by CCL in excess of that 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 and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. As of March 31, 2018, CCL has secured up to approximately 2,057 TBtu of natural gas feedstock through long-term natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.

Construction

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

The total contract price of the EPC contract for Stage 1, which does not include the Corpus Christi Pipeline, is approximately $7.8 billion, reflecting amounts incurred under change orders through March 31, 2018. Total expected capital costs for Stage 1 and the Corpus Christi Pipeline 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 and total expected capital costs for the Corpus Christi Pipeline of between $350 million and $400 million. The total contract price of the EPC contract for Stage 2, which was amended and restated in December 2017, is approximately $2.4 billion.

Pipeline Facilities

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

pipeline grid. The construction of the Corpus Christi Pipeline commenced in January 2017 and is expected to be completed in the second quarter of 2018.

Final Investment Decision on Stage 2

CCL has issued limited notice to proceed to Bechtel for the commencement of certain engineering, procurement and construction activities for Stage 2 of the CCL Project. FID and full notice to proceed for Stage 2 of the CCL Project will be contingent on 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 flows from CCL and CCP and equity contributions to our subsidiaries. The following table provides a summary of our capital resources from borrowings and available commitments for the CCL Project, excluding equity contributions to our subsidiaries, at March 31, 2018 and December 31, 2017 (in millions):



	March 31,		December 31,
	2018		2017
Senior notes (1)	$	4,250	$	4,250
11% Convertible Senior Secured Notes due 2025	1,341		1,305
Credit facilities outstanding balance (2)	2,751		2,485
Letters of credit issued (2)	289		164
Available commitments under credit facilities (2)	1,882		2,273
Total capital resources from borrowings and available commitments (3)	$	10,513	$	10,477


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


(2)	Includes 2015 CCH Credit Facility and CCH Working Capital Facility.


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

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

2025 CCH HoldCo II Convertible Senior Notes

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

CCH Senior Notes

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

The indenture governing the CCH Senior Notes (the “CCH Indenture”) contains customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell

or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any CCH Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.

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

2015 CCH Credit Facility

In May 2015, CCH entered into the 2015 CCH Credit Facility. 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. As of March 31, 2018 and December 31, 2017, CCH had $1.8 billion and $2.1 billion of available commitments and $2.8 billion and $2.5 billion of outstanding borrowings under the 2015 CCH Credit Facility, respectively.

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 1.55:1.00.

Under 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.

CCH Working Capital Facility

In December 2016, CCH entered into the $350 million CCH Working Capital Facility, which is intended to be used for loans to CCH (“CCH Working Capital Loans”), the issuance of letters of credit on behalf of CCH, as well as for swing line loans to CCH (“CCH Swing Line Loans”) for certain working capital requirements related to developing and placing into operation the CCL Project. Loans under the CCH Working Capital Facility are guaranteed by the CCH Guarantors. CCH may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed under the Common Terms Agreement that was entered into concurrently with the 2015 CCH Credit Facility. CCH did not have any amounts outstanding under the CCH Working Capital Facility as of both March 31, 2018 and December 31, 2017. CCH had $289 million and $164 million aggregate amount of issued letters of credit as of March 31, 2018 and December 31, 2017, respectively.

The CCH Working Capital Facility matures on December 14, 2021, and CCH may prepay the CCH Working Capital Loans, CCH Swing Line Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans”) at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. CCH Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the CCH Working Capital Facility, (2) the date that is 15 days after such CCH Swing Line Loan is made and (3) the first borrowing date for a CCH Working Capital Loan or CCH Swing Line Loan occurring at least four business days following the date the CCH Swing Line Loan is made. CCH is required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of CCH under the CCH Working Capital Facility are secured by substantially all of the assets of CCH and the CCH Guarantors as well as all of the membership interests in CCH and each of the CCH Guarantors on a pari passu basis with the CCH Senior Notes and the 2015 CCH Credit Facility.

Restrictive Debt Covenants

As of March 31, 2018, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Marketing

We market and sell LNG produced by the SPL Project and the CCL Project that is not required for other customers through our integrated marketing function. We are developing a portfolio of long-, medium- and short-term SPAs to transport and unload commercial LNG cargoes to locations worldwide, which is primarily sourced by LNG produced by the SPL Project and the CCL Project but supplemented by volume procured from other locations worldwide, as needed. As of March 31, 2018, we have sold or have options to sell approximately 1,572 TBtu of LNG to be delivered to customers between 2018 and 2043. The cargoes have been sold either on a Free on Board basis (delivered to the customer at the Sabine Pass LNG terminal) or a Delivered at Terminal (“DAT”) basis (delivered to the customer at their LNG receiving terminal). We have chartered LNG vessels to be utilized in DAT transactions. In addition, we have entered into a long-term agreement to sell LNG cargoes on a DAT basis that is conditioned upon the buyer achieving certain milestones.

Cheniere Marketing entered into uncommitted trade finance facilities with available commitments of $300 million as of March 31, 2018, primarily to be used for the purchase and sale of LNG for ultimate resale in the course of its operations. The finance facilities are intended to be used for advances, guarantees or the issuance of letters of credit or standby letters of credit on behalf of Cheniere Marketing. As of March 31, 2018 and December 31, 2017, Cheniere Marketing had $14 million and $2 million, respectively, in standby letters of credit and guarantees outstanding under the finance facilities. Cheniere Marketing had no loans outstanding under the finance facilities as of both March 31, 2018 and December 31, 2017. Cheniere Marketing pays interest or fees on utilized commitments.

Corporate and Other Activities

We are required to maintain corporate and general and administrative functions to serve our business activities described above. We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require acceptable commercial and financing arrangements before we make an FID. We have made an equity investment of $55 million in Midship Pipeline, which is developing a pipeline with expected capacity of up to 1.44 million Dekatherms per day that will connect new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the three months ended March 31, 2018 and 2017 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Three Months Ended March 31,
	2018			2017
Operating cash flows	$	469		$	309
Investing cash flows	(776		)	(1,290		)
Financing cash flows	116			2,095

Net increase (decrease) in cash, cash equivalents and restricted cash	(191		)	1,114
Cash, cash equivalents and restricted cash—beginning of period	2,613			1,827
Cash, cash equivalents and restricted cash—end of period	$	2,422		$	2,941

Operating Cash Flows

Our operating cash inflows during the three months ended March 31, 2018 and 2017 were $469 million and $309 million, respectively. The $160 million increase in operating cash inflows in 2018 compared to 2017 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the of additional Trains that were operating at the SPL Project in 2018. There were four Trains operating during the three months ended March 31, 2018, whereas two Trains were operating during the three months ended March 31, 2017.

Investing Cash Flows

Investing cash outflows during the three months ended March 31, 2018 and 2017 were $0.8 billion and $1.3 billion, respectively, and were primarily used to fund the construction costs for the SPL Project and the CCL Project. These costs are capitalized as construction-in-process until achievement of substantial completion. In addition to cash outflows for construction costs for the SPL Project and the CCL Project, we received $36 million during the during the three months ended March 31, 2017 from the return of collateral payments previously paid for the CCL Project, which was offset by $7 million for investments in unconsolidated entities and other projects.

Financing Cash Flows

Financing cash inflows during the three months ended March 31, 2018 were $0.1 billion, primarily as a result of:


•	$266 million of borrowings under the 2015 CCH Credit Facility; and


•	$143 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings.

Financing cash inflows during the three months ended March 31, 2017 were $2.1 billion, primarily as a result of:


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


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


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


•	$548 million of borrowings under the 2015 CCH Credit Facility;


•	$43 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and


•	$20 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings.

Results of Operations

The following table summarizes the volumes of operational and commissioning LNG cargoes that were loaded from the SPL Project and recognized on our Consolidated Financial Statements during the three months ended March 31, 2018:



	Three Months Ended March 31, 2018
(in TBtu)	Operational		Commissioning
Volumes loaded during the current period	241		—
Volumes loaded during the prior period but recognized during the current period	43		—
Less: volumes loaded during the current period and in transit at the end of the period	(11	)	—
Total volumes recognized in the current period	273		—

Our consolidated net income attributable to common stockholders was $357 million, or $1.52 per share—basic and $1.50 per share—diluted, in the three months ended March 31, 2018, compared to net income attributable to common stockholders of $54 million, or $0.23 per share (basic and diluted), in the three months ended March 31, 2017. This $303 million increase in net income in 2018 was primarily a result of increased income from operations due to additional Trains operating between the periods and increased derivative gain, net, which were partially offset by increased allocation of net income to non-controlling interest and increased interest expense, net of amounts capitalized.

Revenues



	Three Months Ended March 31,
(in millions)	2018		2017		Change
LNG revenues	$	2,166	$	1,143	$	1,023
Regasification revenues	65		65		—
Other revenues	10		3		7
Other—related party	1		—		1
Total revenues	$	2,242	$	1,211	$	1,031

We begin recognizing LNG revenues from the SPL Project following the substantial completion and the commencement of operating activities of the respective Trains. During the three months ended March 31, 2018, Trains 1 through 4 were operational, whereas during the three months ended March 31, 2017, only Trains 1 and 2 were operational. Trains 3 and 4 achieved substantial completion in March 2017 and October 2017, respectively. The increase in revenues for the three months ended March 31, 2018 from the comparable period in 2017 was primarily attributable to the increased volume of LNG sold following the achievement of substantial completion of these Trains. We expect our LNG revenues to increase in the future upon Train 5 of the SPL Project and Trains 1 and 2 of the CCL Project becoming operational.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process because these amounts are earned or loaded during the testing phase for the construction of that Train. We realized offset to LNG terminal costs of $131 million corresponding to 18 TBtu of LNG in the three months ended March 31, 2017 that was related to the sale of commissioning cargoes. There were no commissioning cargoes sold that were realized as offsets to LNG terminal costs in the three months ended March 31, 2018.

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



	Three Months Ended March 31,
	2018		2017
LNG revenues (in millions):
LNG from the SPL Project sold under SPL’s third party long-term SPAs	$	993	$	462
LNG from the SPL Project sold by our integrated marketing function	1,021		629
LNG procured from third parties	110		48
Other revenues and derivative gains (losses)	42		4
Total LNG revenues	$	2,166	$	1,143

Volumes sold as LNG revenues (in TBtu):
LNG from the SPL Project sold under SPL’s third party long-term SPAs	165		76
LNG from the SPL Project sold by our integrated marketing function	108		64
LNG procured from third parties	11		4
Total volumes sold as LNG revenues	284		144

Operating costs and expenses



	Three Months Ended March 31,
(in millions)	2018		2017		Change
Cost of sales	$	1,178	$	624	$	554
Operating and maintenance expense	140		78		62
Development expense	1		3		(2		)
Selling, general and administrative expense	67		54		13
Depreciation and amortization expense	109		70		39
Restructuring expense	—		6		(6		)
Total operating costs and expenses	$	1,495	$	835	$	660

Our total operating costs and expenses increased during the three months ended March 31, 2018 from the three months ended March 31, 2017, primarily as a result of additional Trains that were operating between the periods. There were four Trains

operating during the three months ended March 31, 2018, compared to two Trains operating during the three months ended March 31, 2017.

Cost of sales increased during the three months ended March 31, 2018 from the three months ended March 31, 2017, primarily as a result of the increase in operating Trains during 2018. Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project, to the extent those costs are not utilized for the commissioning process. The increase during the three months ended March 31, 2018 from the three months ended March 31, 2017 was primarily related to the increase in the volume of natural gas feedstock, partially offset by lower prices of natural gas feedstock between the periods. Cost of sales also includes vessel charter costs, gains and losses from derivatives associated with economic hedges to secure natural gas feedstock for the SPL Project, port and canal fees, variable transportation and storage costs and other costs to convert natural gas into LNG.

Operating and maintenance expense increased during the three months ended March 31, 2018 from the three months ended March 31, 2017, as a result of the increase in operating Trains during 2018. Operating and maintenance expense includes costs associated with operating and maintaining the SPL Project and CCL Project. The increase during the three months ended March 31, 2018 from the three months ended March 31, 2017 was primarily related to natural gas transportation and storage capacity demand charges, third-party service and maintenance contract costs and payroll and benefit costs of operations personnel. Operating and maintenance expense also includes TUA reservation charges as a result of payments under the partial TUA assignment agreement with Total, insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the three months ended March 31, 2018 from the three months ended March 31, 2017 as a result of an increased number of operational Trains, as the assets related to the Trains of the SPL Project began depreciating upon reaching substantial completion.

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

Other expense (income)



	Three Months Ended March 31,
(in millions)	2018			2017			Change
Interest expense, net of capitalized interest	$	216		$	165		$	51
Loss on early extinguishment of debt	—			42			(42		)
Derivative gain, net	(77		)	(1		)	(76		)
Other income	(7		)	(2		)	(5		)
Total other expense	$	132		$	204		$	(72	)

Interest expense, net of capitalized interest, increased during the three months ended March 31, 2018 compared to the three months ended March 31, 2017, primarily as a result of a decrease in the portion of total interest costs that could be capitalized as additional Trains of the SPL Project completed construction between the periods. For the three months ended March 31, 2018, we incurred $404 million of total interest cost, of which we capitalized $188 million which was directly related to the construction of the SPL Project and the CCL Project. For the three months ended March 31, 2017, we incurred $354 million of total interest cost, of which we capitalized $189 million which was directly related to the construction of the SPL Project and the CCL Project.

Loss on early extinguishment of debt decreased during the three months ended March 31, 2018, as compared to the three months ended March 31, 2017. Loss on early extinguishment of debt recognized in 2017 was attributable to the write-off of debt issuance costs upon termination of the remaining available balance of $1.6 billion under SPL’s previous credit facilities in connection with the issuance of the 2028 SPL Senior Notes and the 2037 SPL Senior Notes.

Derivative gain, net increased during the three months ended March 31, 2018 compared to the three months ended March 31, 2017, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods. During the three months ended March 31, 2017, the gain attributable to a relative increase in the long-term forward LIBOR curve during the period was partially offset by the $7 million loss recognized upon the termination of interest rate swaps associated with approximately $1.6 billion of commitments that were terminated under SPL’s previous credit facilities.

Other



	Three Months Ended March 31,
(in millions)	2018			2017			Change
Income tax provision	$	(15	)	$	—		$	(15	)
Net income attributable to non-controlling interest	243			118			125

Effective tax rate	2.4		%	—		%

Income tax provision increased $15 million during the three months ended March 31, 2018 from the three months ended March 31, 2017 primarily due to the increased profitability in the U.K. The effective tax rates for both the three months ended March 31, 2018 and 2017 were lower than the statutory federal rate of 21% and 35%, respectively, primarily due to the federal and state valuation allowance recorded.

Net income attributable to non-controlling interest increased during the three months ended March 31, 2018 from the three months ended March 31, 2017 due to the increase in the share of Cheniere Partners’ net income that is attributed to non-controlling interest holders as a result of changes in ownership percentages between years and an increase in consolidated net income recognized by Cheniere Partners and Cheniere Holdings in which the non-controlling interests are held, partially offset by the nonrecurrence of non-cash amortization of the beneficial conversion feature on Cheniere Partners’ Class B units that occurred in the three months ended March 31, 2017. The ownership percentage by non-controlling interest holders increased between the periods as a result of the conversion of Cheniere Partners’ Class B units into common units on August 2, 2017. The consolidated net income recognized by Cheniere Partners increased from $47 million in the three months ended March 31, 2017 to $335 million in the three months ended March 31, 2018, primarily as a result of the additional Trains that were operating at the SPL Project between the periods and decreased loss on early extinguishment of debt, which were partially offset by increased interest expense, net of amounts capitalized. The consolidated net income recognized by Cheniere Holdings increased from $4 million in the three months ended March 31, 2017 to $123 million in the three months ended March 31, 2018, primarily as a result of an increase in equity income from investment in Cheniere Partners. Additionally, net income attributable to non-controlling interest during the three months ended March 31, 2017 increased by approximately $84 million due to amortization of the beneficial conversion feature on Cheniere Partners’ Class B units, which ceased upon the conversion of Cheniere Partners’ Class B units into common units.

Off-Balance Sheet Arrangements

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

Summary of Critical Accounting Estimates

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

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 18—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 and the CCL Project (“Liquefaction Supply Derivatives”). We have also entered into financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“LNG Trading Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):



	March 31, 2018					December 31, 2017
	Fair Value			Change in Fair Value		Fair Value			Change in Fair Value
Liquefaction Supply Derivatives	$	10		$	—	$	55		$	5
LNG Trading Derivatives	(6		)	3		(8		)	2

Interest Rate Risk

Cheniere Partners and CCH have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2016 CQP Credit Facilities (“CQP Interest Rate Derivatives”) and the 2015 CCH Credit Facility (“CCH Interest Rate Derivatives” and collectively with the CQP Interest Rate Derivatives, “Interest Rate Derivatives”), respectively. In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining terms of the Interest Rate Derivatives as follows (in millions):



	March 31, 2018				December 31, 2017
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
CQP Interest Rate Derivatives	$	27	$	5	$	21		$	5
CCH Interest Rate Derivatives	43		46		(32		)	44

Foreign Currency Exchange Risk

We have entered into foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with operations in countries outside of the United States (“FX Derivatives”). In order to test the sensitivity of the fair value of the FX Derivatives to changes in FX rates, management modeled a 10% change in FX rate between the U.S. dollar and the applicable foreign currencies. This 10% change in FX rates would have resulted in an immaterial change in the fair value of the FX Derivatives as of both March 31, 2018 and December 31, 2017.

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


ITEM 4.	CONTROLS AND PROCEDURES

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

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. Other than as discussed below, there have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the year ended December 31, 2017.

In February 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal. These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. We continue to work with PHMSA and other appropriate regulatory authorities to address the matters identified in the Consent Order. We do not expect that the Consent Order and related analysis, repair and remediation will have a material adverse impact on our financial results or operations.


ITEM 1A.	RISK FACTORS

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2017.


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

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended March 31, 2018:



Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share (2)	Total Number of Shares Purchased as a Part of Publicly Announced Plans	Maximum Number of Units That May Yet Be Purchased Under the Plans
January 1 - 31, 2018	5,206	$54.37	—	—
February 1 - 28, 2018	98,525	$57.49	—	—
March 1 - 31, 2018	1,150	$52.63	—	—


(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 6.	EXHIBITS



Exhibit No.		Description
10.1*		Consent for Amendment to the Common Security and Account Agreement, dated February 14, 2018, among the Company, as Company, CCL, CCP, and CCP GP, as Guarantors, the Senior Creditor Group Representatives party thereto from time to time, Société Générale, as Intercreditor Agent and Security Trustee, and Mizuho Bank, Ltd., as Account Bank
10.2*		Second Amendment to the Common Security and Account Agreement, dated February 14, 2018, among the Company, as Company, CCL, CCP, and CCP GP, as Guarantors, Société Générale as Security Trustee, and Mizuho Bank, Ltd., as Account Bank
10.3*		Consent for Execution of Precedent Agreement with the Natural Gas Pipeline Company of America LLC, dated February 14, 2018, among the Company, as Borrower, CCL, CCP, and CCP GP, as Guarantors, Société Générale, as Term Loan Facility Agent and Intercreditor Agent
10.4*		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between SPL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00025 BOG and LNG Rundown, dated January 19, 2018, (ii) the Change Order CO-00026 Design Analysis of Existing East & West Jetty Piping and Structure for Simultaneous Loading, dated February 1, 2018, (iii) the Change Order CO-00027 Performance and Attendance Bonus (PAB) Transfer from Stage 2, dated February 1, 2018, and (iv) the Change Order CO-00028 Existing Jetty Structural Steel Supply, dated February 27, 2018
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 CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00038 Settlement of Various Scopes, dated November 10, 2017, (ii) the Change Order CO-00039 OSHA Handrails, East Jetty Scaffold, Attachment Y, and Insurance Provisional Sum, dated February 26, 2018, and (iii) the Change Order CO-00041 GE Service Bulletins and JT Valve Modifications, dated March 6, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
10.6*		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 27, 2018, between CCL (Seller) and Gas Natural Fenosa LNG GOM, Limited (Buyer)
31.1*		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document



*	Filed herewith.
**	Furnished herewith.

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:	May 3, 2018	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)

Date:	May 3, 2018	By:	/s/ Leonard Travis
			Leonard Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)