Cheniere Energy, Inc. - Quarter Report: 2017 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2017

¨ 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. ¨

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

As of November 3, 2017, the issuer had 237,664,678 shares of Common Stock outstanding.

CHENIERE ENERGY, INC.

TABLE OF CONTENTS



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

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	48

Item 4.	Controls and Procedures	49

Part II. Other Information
Item 1.	Legal Proceedings	50

Item 1A.	Risk Factors	50

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50

Item 6.	Exhibits	51

	Signatures	53

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 Organizational Structure

The following diagram depicts our abbreviated organizational structure as of September 30, 2017, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to “Cheniere,” the “Company,” “we,” “us” and “our” refer to Cheniere Energy, Inc. (NYSE American: LNG) and its consolidated subsidiaries, including our publicly traded subsidiaries, Cheniere Partners (NYSE American: CQP) and Cheniere Holdings (NYSE American: CQH).

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


PART I.	FINANCIAL INFORMATION


ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)



	September 30,			December 31,
	2017			2016
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	919		$	876
Restricted cash	1,590			860
Accounts and other receivables	264			218
Accounts receivable—related party	1			—
Inventory	133			160
Derivative assets	12			24
Other current assets	112			100
Total current assets	3,031			2,238

Non-current restricted cash	66			91
Property, plant and equipment, net	23,466			20,635
Debt issuance costs, net	159			277
Non-current derivative assets	37			83
Goodwill	77			77
Other non-current assets, net	298			302
Total assets	$	27,134		$	23,703

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	59		$	49
Accrued liabilities	722			637
Current debt	41			247
Deferred revenue	134			73
Derivative liabilities	55			71
Total current liabilities	1,011			1,077

Long-term debt, net	24,923			21,688
Non-current deferred revenue	2			5
Non-current derivative liabilities	52			45
Other non-current liabilities	63			49

Commitments and contingencies (see Note 15)

Stockholders’ equity
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—			—
Common stock, $0.003 par value
Authorized: 480.0 million shares at September 30, 2017 and December 31, 2016
Issued: 250.1 million shares at September 30, 2017 and December 31, 2016
Outstanding: 237.8 million shares and 238.0 million shares at September 30, 2017 and December 31, 2016, respectively	1			1
Treasury stock: 12.3 million shares and 12.2 million shares at September 30, 2017 and December 31, 2016, respectively, at cost	(378		)	(374		)
Additional paid-in-capital	3,238			3,211
Accumulated deficit	(4,754		)	(4,234		)
Total stockholders’ deficit	(1,893		)	(1,396		)
Non-controlling interest	2,976			2,235
Total equity	1,083			839
Total liabilities and equity	$	27,134		$	23,703

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Revenues
LNG revenues	$	1,332		$	399		$	3,646		$	512
Regasification revenues	65			64			195			194
Other revenues	5			2			12			5
Other—related party	1			—			2			—
Total revenues	1,403			465			3,855			711

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	824			253			2,140			353
Operating and maintenance expense	114			61			309			143
Development expense	3			2			7			5
Selling, general and administrative expense	64			59			179			197
Depreciation and amortization expense	92			49			252			106
Restructuring expense	—			26			6			49
Impairment expense and loss on disposal of assets	9			—			15			10
Total operating costs and expenses	1,106			450			2,908			863

Income (loss) from operations	297			15			947			(152		)

Other income (expense)
Interest expense, net of capitalized interest	(186		)	(148		)	(539		)	(330		)
Loss on early extinguishment of debt	(25		)	(26		)	(100		)	(83		)
Derivative gain (loss), net	(2		)	30			(37		)	(242		)
Other income (expense)	4			—			11			(6		)
Total other expense	(209		)	(144		)	(665		)	(661		)

Income (loss) before income taxes and non-controlling interest	88			(129		)	282			(813		)
Income tax benefit (provision)	2			(2		)	1			(2		)
Net income (loss)	90			(131		)	283			(815		)
Less: net income (loss) attributable to non-controlling interest	379			(30		)	803			(95		)
Net loss attributable to common stockholders	$	(289	)	$	(101	)	$	(520	)	$	(720	)

Net loss per share attributable to common stockholders—basic and diluted	$	(1.24	)	$	(0.44	)	$	(2.24	)	$	(3.15	)

Weighted average number of common shares outstanding—basic and diluted	232.6			228.9			232.5			228.5

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, 2016	238.0		$	1	12.2	$	(374	)	$	3,211	$	(4,234	)	$	2,235		$	839
Issuance of stock to acquire additional interest in Cheniere Holdings	—		—		—	—			2		—			(2		)	—
Issuances of restricted stock	0.1		—		—	—			—		—			—			—
Forfeitures of restricted stock	(0.2	)	—		—	—			—		—			—			—
Share-based compensation	—		—		—	—			25		—			—			25
Shares repurchased related to share-based compensation	(0.1	)	—		0.1	(4		)	—		—			—			(4		)
Net income attributable to non-controlling interest	—		—		—	—			—		—			803			803
Distributions to non-controlling interest	—		—		—	—			—		—			(60		)	(60		)
Net loss	—		—		—	—			—		(520		)	—			(520		)
Balance at September 30, 2017	237.8		$	1	12.3	$	(378	)	$	3,238	$	(4,754	)	$	2,976		$	1,083

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)



	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	283		$	(815	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense	252			106
Share-based compensation expense	64			85
Non-cash interest expense	54			60
Amortization of debt issuance costs, deferred commitment fees, premium and discount	53			45
Loss on early extinguishment of debt	100			83
Total losses on derivatives, net	108			269
Net cash used for settlement of derivative instruments	(59		)	(34		)
Impairment expense and loss on disposal of assets	15			10
Other	(2		)	10
Changes in operating assets and liabilities:
Accounts and other receivables	(33		)	(128		)
Accounts receivable—related party	(1		)	—
Inventory	35			(28		)
Accounts payable and accrued liabilities	20			34
Deferred revenue	58			(3		)
Other, net	(52		)	(13		)
Net cash provided by (used in) operating activities	895			(319		)

Cash flows from investing activities
Property, plant and equipment, net	(2,903		)	(3,449		)
Investment in equity method investment	(41		)	—
Other	18			(50		)
Net cash used in investing activities	(2,926		)	(3,499		)

Cash flows from financing activities
Proceeds from issuances of debt	6,537			8,308
Repayments of debt	(3,609		)	(4,181		)
Debt issuance and deferred financing costs	(85		)	(117		)
Distributions and dividends to non-controlling interest	(60		)	(60		)
Payments related to tax withholdings for share-based compensation	(4		)	(19		)
Net cash provided by financing activities	2,779			3,931

Net increase in cash, cash equivalents and restricted cash	748			113
Cash, cash equivalents and restricted cash—beginning of period	1,827			1,736
Cash, cash equivalents and restricted cash—end of period	$	2,575		$	1,849

Balances per Consolidated Balance Sheet:



	September 30, 2017
Cash and cash equivalents	$	919
Restricted cash	1,590
Non-current restricted cash	66
Total cash, cash equivalents and restricted cash	$	2,575

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 3 are operational, Train 4 became operational in October 2017, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. In the second quarter of 2016, we started production at the SPL Project and began recognizing LNG revenues, which include fees that are received pursuant to our long-term SPAs and our integrated LNG marketing activities and other related revenues.

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, which were historically included in regasification revenues but are now included within other revenues on our Consolidated Statements of Operations, that are received by Sabine Pass Tug Services, LLC, a wholly owned subsidiary of SPLNG.

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, 2016. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

Results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2017.

During the first quarter of 2017, we finalized organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment. As a result of these efforts, we revised the way we manage our business, which resulted in a change to our reportable segments. We previously had two reportable segments: LNG terminal segment and LNG and natural gas marketing segment. We have now determined that we operate as a single operating and reportable segment. Our chief operating decision maker makes resource allocation decisions and assesses performance based on financial information presented on a consolidated basis in the delivery of an integrated source of LNG to our customers.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 2—RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2017 and December 31, 2016, restricted cash consisted of the following (in millions):



	September 30,		December 31,
	2017		2016
Current restricted cash
SPL Project	$	579	$	358
CQP and cash held by guarantor subsidiaries	816		247
CCL Project	117		197
Cash held by our subsidiaries restricted to Cheniere	78		58
Total current restricted cash	$	1,590	$	860

Non-current restricted cash
SPL Project	$	48	$	—
CCL Project	—		73
Other	18		18
Total non-current restricted cash	$	66	$	91

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2017 and December 31, 2016, accounts and other receivables consisted of the following (in millions):



	September 30,		December 31,
	2017		2016
Trade receivables
SPL	$	154	$	88
Cheniere Marketing	87		121
Other accounts receivable	23		9
Total accounts and other receivables	$	264	$	218

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 September 30, 2017 and December 31, 2016, inventory consisted of the following (in millions):



	September 30,		December 31,
	2017		2016
Natural gas	$	16	$	15
LNG	24		50
LNG in-transit	45		58
Materials and other	48		37
Total inventory	$	133	$	160

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):



	September 30,			December 31,
	2017			2016
LNG terminal costs
LNG terminal	$	10,548		$	7,978
LNG terminal construction-in-process	13,461			12,995
LNG site and related costs	86			41
Accumulated depreciation	(784		)	(555		)
Total LNG terminal costs, net	23,311			20,459
Fixed assets and other
Computer and office equipment	14			13
Furniture and fixtures	18			17
Computer software	89			85
Leasehold improvements	41			43
Land	59			61
Other	17			22
Accumulated depreciation	(83		)	(65		)
Total fixed assets and other, net	155			176
Property, plant and equipment, net	$	23,466		$	20,635

Depreciation expense was $91 million and $49 million in the three months ended September 30, 2017 and 2016, respectively, and $250 million and $105 million in the nine months ended September 30, 2017 and 2016, respectively.

We realized offsets to LNG terminal costs of $82 million and $68 million in the three months ended September 30, 2017 and 2016, respectively, and $252 million and $214 million in the nine months ended September 30, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the SPL Project, during the testing phase for its construction.

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 operations in countries outside of the United States (“FX Derivatives”).

None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table (in millions) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets.



	Fair Value Measurements as of
	September 30, 2017											December 31, 2016
	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
SPL Interest Rate Derivatives liability	$	—		$	—		$	—	$	—		$	—		$	(6	)	$	—	$	(6	)
CQP Interest Rate Derivatives asset	—			14			—		14			—			13			—		13
CCH Interest Rate Derivatives liability	—			(79		)	—		(79		)	—			(86		)	—		(86		)
Liquefaction Supply Derivatives asset (liability)	—			(1		)	29		28			(4		)	(2		)	79		73
LNG Trading Derivatives asset (liability)	(21		)	—			—		(21		)	2			(5		)	—		(3		)
FX Derivatives asset (liability)	—			—			—		—			—			—			—		—

There have been no changes to our evaluation of and accounting for our derivative positions during the nine months ended September 30, 2017. 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, 2016 for additional information.

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

The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair value models include conditions precedent to the respective long-term natural gas supply contracts. As of September 30, 2017 and December 31, 2016, 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 following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2017:



	Net Fair Value Asset (in millions)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$29	Income Approach	Basis Spread	$(0.370) - $0.081

The following table (in millions) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Balance, beginning of period	$	40		$	22		$	79		$	32
Realized and mark-to-market losses:
Included in cost of sales (1)	(8		)	(11		)	(43		)	(20		)
Purchases and settlements:
Purchases	(1		)	1			1			1
Settlements (1)	(2		)	—			(8		)	(1		)
Balance, end of period	$	29		$	12		$	29		$	12
Change in unrealized gains relating to instruments still held at end of period	$	(8	)	$	(11	)	$	(43	)	$	(20	)


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

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. 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

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 discussed in Note 10—Debt.

CCH has entered into interest rate swaps (“CCH Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on its credit facility (the “2015 CCH Credit Facility”). In May 2017, CCH settled a portion of the CCH Interest Rate Derivatives and recognized a derivative loss of $13 million in conjunction with the termination of approximately $1.4 billion of commitments under the 2015 CCH Credit Facility, as discussed in Note 10—Debt.

During the nine months ended September 30, 2017, 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 the credit facilities it entered into in February 2016 (the “2016 CQP Credit Facilities”). 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, 2016 for additional information.

As of September 30, 2017, 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 (in millions) shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets:



	September 30, 2017										December 31, 2016
	SPL Interest Rate Derivatives		CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total			SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			CCH Interest Rate Derivatives			Total
Balance Sheet Location
Derivative assets	$	—	$	3	$	—		$	3		$	—		$	—		$	—		$	—
Non-current derivative assets	—		11		—			11			—			16			—			16
Total derivative assets	—		14		—			14			—			16			—			16

Derivative liabilities	—		—		(30		)	(30		)	(4		)	(3		)	(43		)	(50		)
Non-current derivative liabilities	—		—		(49		)	(49		)	(2		)	—			(43		)	(45		)
Total derivative liabilities	—		—		(79		)	(79		)	(6		)	(3		)	(86		)	(95		)

Derivative asset (liability), net	$	—	$	14	$	(79	)	$	(65	)	$	(6	)	$	13		$	(86	)	$	(79	)

The following table (in millions) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017			2016
SPL Interest Rate Derivatives gain (loss)	$	—		$	3	$	(2	)	$	(13	)
CQP Interest Rate Derivatives gain (loss)	1			7		—			(13		)
CCH Interest Rate Derivatives gain (loss)	(3		)	20		(35		)	(216		)

Commodity Derivatives

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



	September 30, 2017									December 31, 2016
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total			Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total
Balance Sheet Location
Derivative assets	$	8		$	1		$	9		$	13		$	7		$	20
Non-current derivative assets	26			—			26			67			—			67
Total derivative assets	34			1			35			80			7			87

Derivative liabilities	(4		)	(21		)	(25		)	(7		)	(10		)	(17		)
Non-current derivative liabilities	(2		)	(1		)	(3		)	—			—			—
Total derivative liabilities	(6		)	(22		)	(28		)	(7		)	(10		)	(17		)

Derivative asset (liability), net	$	28		$	(21	)	$	7		$	73		$	(3	)	$	70

Notional amount (in TBtu) (3)	1,911			20						1,117			—


(1)	Does not include collateral of $2 million and $6 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016, respectively.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)


(2)	Does not include collateral of $42 million and $10 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016, respectively.


(3)	SPL had secured up to approximately 2,462 TBtu and 1,994 TBtu and CCL has secured up to approximately 362 TBtu and zero TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2017 and December 31, 2016, respectively.

The following table (in millions) shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2017 and 2016:



		Three Months Ended					Nine Months Ended
	Statement of Operations Location (1)	September 30,					September 30,
	Statement of Operations Location (1)	2017			2016		2017			2016
LNG Trading Derivatives gain (loss)	LNG revenues	$	(16	)	$	9	$	(20	)	$	(3	)
Liquefaction Supply Derivatives loss (2)	Cost of sales	11			11		51			23


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



		Fair Value Measurements as of
	Balance Sheet Location	September 30, 2017		December 31, 2016
FX Derivatives	Derivative assets	$	—	$	4
FX Derivatives	Derivative liabilities	—		(4		)

The total notional amount of our FX Derivatives was $7 million and $11 million as of September 30, 2017 and December 31, 2016, respectively.

The following table (in millions) shows the changes in the fair value of our FX Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2017 and 2016:



		Three Months Ended					Nine Months Ended
		September 30,					September 30,
	Statement of Operations Location	2017		2016			2017		2016
FX Derivatives loss	LNG revenues	$	—	$	(1	)	$	—	$	(1	)

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Balance Sheet Presentation

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



	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
As of September 30, 2017
CQP Interest Rate Derivatives	$	14		$	—		$	14
CCH Interest Rate Derivatives	(80		)	1			(79		)
Liquefaction Supply Derivatives	35			(1		)	34
Liquefaction Supply Derivatives	(8		)	2			(6		)
LNG Trading Derivatives	2			(1		)	1
LNG Trading Derivatives	(24		)	2			(22		)
As of December 31, 2016
SPL Interest Rate Derivatives	$	(6	)	$	—		$	(6	)
CQP Interest Rate Derivatives	16			—			16
CQP Interest Rate Derivatives	(3		)	—			(3		)
CCH Interest Rate Derivatives	(95		)	9			(86		)
Liquefaction Supply Derivatives	82			(2		)	80
Liquefaction Supply Derivatives	(11		)	4			(7		)
LNG Trading Derivatives	21			(15		)	6
LNG Trading Derivatives	(17		)	8			(9		)
FX Derivatives	5			(1		)	4
FX Derivatives	(4		)	—			(4		)

NOTE 7—OTHER NON-CURRENT ASSETS

As of September 30, 2017 and December 31, 2016, other non-current assets, net consisted of the following (in millions):



	September 30,		December 31,
	2017		2016
Advances made under EPC and non-EPC contracts	$	21	$	69
Advances made to municipalities for water system enhancements	97		99
Advances and other asset conveyances to third parties to support LNG terminals	49		53
Tax-related payments and receivables	40		31
Equity method investments	64		10
Cost method investments	5		5
Other	22		35
Total other non-current assets, net	$	298	$	302

Equity Method Investments

As of December 31, 2016, our equity method investments consisted of interests in privately-held companies. During the second quarter of 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 at September 30, 2017 was $55 million. 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 $2 million of income in other—related party during the three and nine months ended September 30, 2017, respectively, and $1 million of accounts receivable—related party as of September 30, 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.

Cost Method Investments

Our cost method investments consist of interests in privately-held companies without a readily determinable fair value. The Company’s cost method investments are assessed for impairment quarterly. We determined that it is not practicable to estimate the fair value of these investments on a regular basis and do not reassess the fair value of cost method investments if there are no identified events or changes in circumstances that may have a significant adverse effect on the fair value of the investment. We did not identify events or changes in circumstances that may have a significant adverse effect on the fair value of these investments during the three and nine months ended September 30, 2017.

NOTE 8—NON-CONTROLLING INTEREST

As of September 30, 2017 and December 31, 2016, we owned 82.7% and 82.6%, respectively, of Cheniere Holdings as well as the director voting share, with the remaining non-controlling interest held by the public. As a result of the mandatory conversion of Cheniere Partners’ Class B units on August 2, 2017, as of September 30, 2017, Cheniere Holdings owned a 48.6% limited partner interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco LP (“Blackstone CQP Holdco”) and the public. Prior to the conversion, as of December 31, 2016, Cheniere Holdings owned a 55.9% limited partner interest in Cheniere Partners in the form of 12.0 million common units, 45.3 million Class B units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco 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. For further information regarding variable interest entities, refer to our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016.

NOTE 9—ACCRUED LIABILITIES

As of September 30, 2017 and December 31, 2016, accrued liabilities consisted of the following (in millions):



	September 30,		December 31,
	2017		2016
Interest costs and related debt fees	$	220	$	273
Compensation and benefits	110		56
LNG terminals and related pipeline costs	359		284
Other accrued liabilities	33		24
Total accrued liabilities	$	722	$	637

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—DEBT

As of September 30, 2017 and December 31, 2016, our debt consisted of the following (in millions):



	September 30,			December 31,
	2017			2016
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7	$	2,006		$	2,007
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 $6	1,505			1,506
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 zero	1,349			—
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			—
2015 SPL Credit Facilities	—			314
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			—
2016 CQP Credit Facilities	1,090			2,560
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			—
2015 CCH Credit Facility	2,151			2,381
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,270			1,171
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”), net of unamortized discount of $127 and $146	1,006			960
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”), net of unamortized discount of $315 and $317	310			308
$750 million Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	—			—
Unamortized debt issuance costs	(314		)	(269		)
Total long-term debt, net	24,923			21,688

Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			224
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”)	—			—
Cheniere Marketing trade finance facilities	41			23
Total current debt	41			247

Total debt, net	$	24,964		$	21,935

2017 Debt Issuances and Redemptions

SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to repay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.

In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the nine months ended September 30, 2017.

The 2037 SPL Senior Notes and the 2028 SPL Senior Notes accrue interest at fixed rates of 5.00% and 4.200%, respectively, and interest is payable semi-annually in arrears. The 2037 SPL Senior Notes are governed by an indenture which contains customary terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. The 2028 SPL Senior Notes are governed by the same common indenture as the senior notes of SPL other than the 2037 SPL Senior Notes, which also contains customary terms and events of default, covenants and redemption terms.

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

2025 CQP Senior Notes

In September 2017, CQP issued an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which are jointly and severally guaranteed by each of CQP’s subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (the “CQP Guarantors”). Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2016 CQP Credit Facilities of $25 million during the nine months ended September 30, 2017.

Borrowings under the 2025 CQP Senior Notes accrue interest at a fixed rate of 5.250%, and interest on the 2025 CQP Senior Notes is payable semi-annually in arrears. 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 CQP 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, CQP 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, CQP 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. CQP 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The 2025 CQP Senior Notes are CQP’s senior obligations, ranking equally in right of payment with CQP’s 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 CQP 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). 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 CQP and the CQP Guarantors.

In connection with the closing of the sale of the 2025 CQP Senior Notes, CQP and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, CQP and the CQP Guarantors have agreed to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2025 CQP Senior Notes for a like aggregate principal amount of debt securities of CQP with terms identical in all material respects to the 2025 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after September 18, 2017. Under specified circumstances, CQP and the CQP Guarantors have also agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2025 CQP Senior Notes. CQP will be obligated to pay additional interest on the 2025 CQP Senior Notes if it fails to comply with its obligation to register the 2025 CQP Senior Notes within the specified time period.

2027 CCH Senior Notes

In May 2017, CCH issued an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, which are jointly and severally guaranteed by its subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (“CCP GP”, and collectively with CCL and CCP, the “CCH Guarantors”). Net proceeds of the offering of approximately $1.4 billion, after deducting commissions, fees and expenses and provisioning for incremental interest required under the 2027 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 CCH Credit Facility, resulting in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $33 million during the nine months ended September 30, 2017. Borrowings under the 2027 CCH Senior Notes accrue interest at a fixed rate of 5.125%, and interest on the 2027 CCH Senior Notes is payable semi-annually in arrears. The 2027 CCH Senior Notes are governed by the same common indenture as the other senior notes of CCH (the “CCH Indenture”), which contains customary terms and events of default, covenants and redemption terms.

At any time prior to January 1, 2027, CCH may redeem all or a part of the 2027 CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. CCH also may at any time on or after January 1, 2027 through the maturity date of June 30, 2027, redeem the 2027 CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2027 CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

In connection with the closing of the sale of the 2027 CCH Senior Notes, CCH and the CCH Guarantors entered into a registration rights agreement (the “CCH Registration Rights Agreement”). Under the CCH Registration Rights Agreement, CCH and the CCH Guarantors have agreed, and any future guarantors of the 2027 CCH Senior Notes will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2027 CCH Senior Notes for a like aggregate principal amount of debt securities of CCH with terms identical in all material respects to the 2027 CCH Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after May 19, 2017. Under specified circumstances, CCH and the CCH Guarantors have also agreed, and any future guarantors of the 2027 CCH Senior Notes will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2027 CCH Senior Notes. CCH will be obligated to pay additional interest on the 2027 CCH Senior Notes if it fails to comply with its obligation to register the 2027 CCH Senior Notes within the specified time period.

Cheniere Revolving Credit Facility

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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. We incurred $16 million of debt issuance costs related to the Cheniere Revolving Credit Facility during the nine months ended September 30, 2017.

Loans under the Cheniere Revolving Credit Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of (1) the prime rate, (2) the federal funds rate plus 0.50% and (3) one month LIBOR plus 1.00%), plus the applicable margin. The applicable margin for LIBOR loans is 3.25% per annum, and the applicable margin for base rate loans is 2.25% per annum. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and interest on base rate loans is due and payable at the end of each calendar quarter. We will also pay (1) a commitment fee on the average daily amount of undrawn commitments at an annual rate of 0.75%, payable quarterly in arrears, and (2) a letter of credit fee at an annual rate equal to the applicable margin for LIBOR loans on the undrawn portion of all letters of credit issued under the Cheniere Revolving Credit Facility. Draws on any letters of credit will accrue interest at an annual rate equal to the base rate plus 2.0%.

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).

Credit Facilities

Below is a summary (in millions) of our credit facilities outstanding as of September 30, 2017:



	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
Outstanding balance	—		1,090		2,151		—		—
Commitments prepaid or terminated	—		1,470		3,832		—		—
Letters of credit issued	721		50		—		163		—
Available commitment	$	479	$	190	$	2,421	$	187	$	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 principals due quarterly commencing on February 19, 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Convertible Notes

Below is a summary (in millions) of our convertible notes outstanding as of September 30, 2017:



	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	$	1,006		$	1,270		$	310
Equity component	$	205		$	—		$	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)	8.2		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (9)	3.7 years			3.0 years			27.5 years


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


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

(3)

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


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


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


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

(7)

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


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


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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Interest Expense

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Interest cost on convertible notes:
Interest per contractual rate	$	55		$	51		$	162		$	150
Amortization of debt discount	8			7			22			24
Amortization of debt issuance costs	2			1			5			4
Total interest cost related to convertible notes	65			59			189			178
Interest cost on debt excluding convertible notes	324			282			931			773
Total interest cost	389			341			1,120			951
Capitalized interest	(203		)	(193		)	(581		)	(621		)
Total interest expense, net	$	186		$	148		$	539		$	330

Fair Value Disclosures

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



	September 30, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	18,610	$	20,140	$	14,263	$	15,210
2037 SPL Senior Notes (2)	800		844		—		—
Credit facilities (3)	3,282		3,282		5,502		5,502
2021 Cheniere Convertible Unsecured Notes, net of discount (2)	1,006		1,096		960		983
2025 CCH HoldCo II Convertible Senior Notes (2)	1,270		1,502		1,171		1,328
2045 Cheniere Convertible Senior Notes, net of discount (4)	310		437		308		375

(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 2015 SPL Credit Facilities, 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—RESTRUCTURING EXPENSE

During 2015 and 2016, we initiated and implemented certain organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment. These organizational initiatives were completed as of the first quarter of 2017. As a result of these efforts, we recorded $6 million during the nine months ended September 30, 2017 and $26 million and $49 million during the three and nine months ended September 30, 2016, respectively, of restructuring charges and other costs associated with restructuring and operational efficiency initiatives for which the majority of these charges required cash expenditure. Included in these amounts were $3 million for share-based compensation during the nine months ended September 30, 2017 and $21 million and $43 million for share-based compensation during the three and nine months ended September 30,

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

2016, respectively. All charges were recorded within the line item entitled “restructuring expense” on our Consolidated Statements of Operations and substantially all related to severance and other employee-related costs. As of December 31, 2016, we had $6 million of accrued restructuring charges and other costs that were recorded as part of accrued liabilities on our Consolidated Balance Sheets.

NOTE 12—INCOME TAXES

Due to our cumulative loss position and historical net operating losses (“NOLs”), we have recorded a full valuation allowance against our U.S. deferred tax assets at September 30, 2017 and December 31, 2016. Accordingly, the Company has not recorded a provision for federal or state income taxes during the three and nine months ended September 30, 2017 and 2016. Any provision recorded in the accompanying Consolidated Financial Statements is for foreign income taxes.

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

NOTE 13—SHARE-BASED COMPENSATION

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

In January 2017, the issuance of awards with respect to 7.8 million shares of common stock available for issuance under the 2011 Plan was approved at a special meeting of our shareholders. In February 2017, our Board of Directors approved the award of 0.9 million restricted stock units and 0.2 million target performance stock units under the 2011 Plan to certain employees as part of the Long-Term Incentive program implemented in 2017. Restricted stock unit awards vest ratably over a three-year service period on each of the first, second and third anniversaries of the grant date, subject to forfeiture upon termination except in certain events and acceleration upon certain events including death or disability. Performance stock units provide for three-year cliff vesting with payouts based on the Company’s cumulative distributable cash flow per share from January 1, 2018 through December 31, 2019 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 shares of Cheniere common stock and are classified as equity awards.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Share-based compensation:
Equity awards	$	10		$	7		$	25		$	37
Liability awards	12			33			56			61
Total share-based compensation	22			40			81			98
Capitalized share-based compensation	(4		)	(7		)	(17		)	(13		)
Total share-based compensation expense	$	18		$	33		$	64		$	85

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, 2016.

NOTE 14—NET LOSS PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

Basic net loss per share attributable to common stockholders (“EPS”) excludes dilution and is computed by dividing net loss attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net loss attributable to common stockholders by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

been outstanding if the potential common shares had been issued. The dilutive effect of stock options and unvested stock is calculated using the treasury-stock method and the dilutive effect of convertible securities is calculated using the if-converted method.

The following table (in millions, except per share data) reconciles basic and diluted weighted average common shares outstanding for the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Weighted average common shares outstanding:
Basic	232.6			228.9			232.5			228.5
Dilutive unvested stock	—			—			—			—
Diluted	232.6			228.9			232.5			228.5

Basic and diluted net loss per share attributable to common stockholders	$	(1.24	)	$	(0.44	)	$	(2.24	)	$	(3.15	)

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



	Three And Nine Months Ended September 30,
	2017	2016
Stock options and unvested stock (1)	1.5	0.8
Convertible notes (2)	16.8	16.2
Total potentially dilutive common shares	18.3	17.0


(1)	Does not include 5.1 million shares for each of the three and nine months ended September 30, 2017 and 2016 of unvested stock because the performance conditions had not yet been satisfied as of September 30, 2017 and 2016, 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 loss per share for the 2025 CCH HoldCo II Convertible Senior Notes because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of September 30, 2017.

NOTE 15—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of September 30, 2017, are not recognized as liabilities.

Obligations under Certain Guarantee Contracts

Cheniere and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate transactions with third parties. These arrangements include financial guarantees, letters of credit and debt guarantees. As of September 30, 2017 and December 31, 2016, there were no liabilities recognized under these guarantee arrangements.

Legal Proceedings

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Parallax Litigation

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

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

On July 27, 2017, the Parallax entities named as defendants in the Texas Federal Suit reurged their motion to dismiss and simultaneously filed counterclaims against CLNGT and third party claims against us for breach of contract, breach of fiduciary duty, promissory estoppel, quantum meruit, and fraudulent inducement of the Secured Note and Pledge Agreement, based on substantially the same factual allegations Parallax Enterprises made in the Louisiana Suit. These Parallax entities also simultaneously filed an action styled Cause No. 2017-49685, Parallax Enterprises, LLC, et al. v. Cheniere Energy, Inc., et al., in the 61st District Court of Harris County, Texas (the “Texas State Suit”), which asserts substantially the same claims these entities asserted in the Texas Federal Suit. On July 31, 2017, CLNGT withdrew its opposition to the dismissal of the Texas Federal Suit without prejudice on jurisdictional grounds and the federal court subsequently dismissed the Texas Federal Suit without prejudice. We and CLNGT simultaneously filed an answer and counterclaims in the Texas State Suit, asserting the same claims CLNGT had previously asserted in the Texas Federal Suit. Additionally, CLNGT filed third party claims against Parallax principals Martin Houston, Christopher Bowen Daniels, Howard Candelet, and Mark Evans, as well as Tellurian Investments, Inc., Driftwood LNG, LLC, Driftwood Pipeline, LLC and Tellurian Services, LLC f/k/a Parallax Services LLC, including claims for tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement. The Parallax entities have filed an application for a preliminary injunction prohibiting CLNGT from foreclosing on any of the Parallax entities’ assets pending resolution of the Texas State Suit. The Parallax Entities’ temporary injunction application is presently set for a hearing on November 17, 2017. Discovery in the Texas State Suit is ongoing.

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 September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2017	2016	2017	2016	2017	2016
Customer A	19%	37%	25%	36%	22%	34%
Customer B	14%	*	13%	*	18%	21%
Customer C	20%	—%	10%	—%	19%	—%
Customer D	20%	—%	19%	—%	18%	—%
Customer E	*	16%	*	16%	—%	—%
Customer F	*	10%	*	*	*	*
Customer G	*	—%	*	—%	—%	28%
Customer H	—%	—%	—%	—%	—%	12%

* Less than 10%

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Nine Months Ended September 30,
	2017		2016
Cash paid during the period for interest, net of amounts capitalized	$	360	$	30
Contribution of assets to equity method investment	14		—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $426 million and $491 million as of September 30, 2017 and 2016, 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 recent accounting standards that had not been adopted by the Company as of September 30, 2017:



Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard 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 continue to evaluate the effect of this standard on our Consolidated Financial Statements. We plan to adopt this standard using the full retrospective approach. Preliminarily, we do not anticipate that the adoption will have a material impact upon our revenues. Furthermore, we routinely enter into new contracts and we cannot predict with certainty whether the accounting for any future contract under the new standard would result in a significant change from existing guidance. Because this assessment is preliminary and the accounting for revenue recognition is subject to significant judgment, this conclusion could change as we finalize our assessment.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, whether we will elect to early adopt this standard or which, if any, practical expedients we will elect upon transition.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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



Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.
ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	This standard primarily requires the recognition of excess tax benefits for share-based awards in the statement of operations and the classification of excess tax benefits as an operating activity within the statement of cash flows. The guidance also allows an entity to elect to account for forfeitures when they occur. This guidance may be early adopted, but all of the guidance must be adopted in the same period.	January 1, 2017	Upon adoption of this guidance, we made a cumulative effect adjustment to accumulated deficit for all excess tax benefits not previously recognized, offset by the change in valuation allowance, and for our election to account for forfeitures as they occur. The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.
ASU 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment	This standard simplifies the measurement of goodwill impairment by eliminating the requirement for an entity to perform a hypothetical purchase price allocation. An entity will instead measure the impairment as the difference between the carrying amount and the fair value of the reporting unit. This guidance may be early adopted beginning January 1, 2017, and must be adopted prospectively.	January 1, 2017	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.
ASU 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting	This standard clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. An entity will not apply modification accounting to a share-based payment award if the award’s fair value, vesting conditions and classification as an equity or liability award are the same prior to and after the change. This guidance may be early adopted and must be adopted prospectively.	June 30, 2017	The adoption of this guidance did not have a material 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 counterparties to our commercial contracts, construction contracts and other contracts;


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


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


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


•	statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; 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, 2016. 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 be recognized as the premier global LNG company and provide a reliable, competitive and integrated source of LNG to our customers while creating a safe, productive and rewarding work environment for our employees. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 82.7% of Cheniere Holdings, which is a publicly traded limited liability company formed in 2013 that owns 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 3 are operational, Train 4 became operational in October 2017, 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. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines 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.

Additionally, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (the “Corpus Christi Expansion 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”).

Overview of Significant Events

Our significant accomplishments since January 1, 2017 and through the filing date of this Form 10-Q include the following:

Strategic


•	As of October 2017, more than 200 cumulative LNG cargoes had been produced, loaded and exported from the SPL Project, with deliveries completed to 25 countries worldwide.


•	We completed a land acquisition and acquired rights to obtain additional upland and waterfront land adjacent to the CCL Project aggregating more than 500 acres.

•

We made an equity investment in Midship Pipeline Company, LLC (“Midship Pipeline”) through Midship Holdings, LLC, which is constructing an approximately 230-mile interstate natural gas pipeline with expected capacity of up to 1.44 million Dekatherms per day, to connect new production in the Anadarko Basin to Gulf Coast markets (the “Midship Project”). Additionally, Midship Holdings entered into agreements with investment funds managed by EIG Global Energy Partners (“EIG”) under which EIG-managed funds have committed to make an investment of up to $500 million in the Midship Project, subject to the terms and conditions in the applicable agreements.


•	In October 2017, we began the process of amending our regulatory filings with FERC related to the Corpus Christi Expansion Project 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.

Operational


•	SPL commenced production and shipment of LNG commissioning cargoes from Train 3 of the SPL Project in January 2017 and achieved substantial completion and commenced operating activities in March 2017.


•	Commissioning activities for Train 4 of the SPL Project began in March 2017, and substantial completion was achieved in October 2017.

Financial


•	In June 2017, the date of first commercial delivery was reached under the 20-year SPA with Korea Gas Corporation relating to Train 3 of the SPL Project.


•	In August 2017, the date of first commercial delivery relating to Train 2 of the SPL Project was reached under the respective 20-year SPAs with Gas Natural Fenosa LNG GOM, Limited and BG Gulf Coast LNG, LLC (“BG”).

•

In February and March 2017, SPL issued aggregate principal amounts of $800 million of 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) and $1.35 billion, before discount, of 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”), respectively. Net proceeds of the offerings of the 2037 SPL Senior Notes and 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to repay the outstanding borrowings under the credit facilities SPL entered into in June 2015 (the “2015 SPL Credit Facilities”) and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.


•	In March 2017, we entered into a $750 million revolving credit agreement (“Cheniere Revolving Credit Facility”) that may be used to fund the development of the CCL Project and, provided that certain conditions are met, for general corporate purposes.

•

In May 2017, CCH issued an aggregate principal amount of $1.5 billion of 5.125% Senior Secured Notes due 2027 (the “2027 CCH Senior Notes”). Net proceeds of the offering of approximately $1.4 billion, after deducting commissions, fees and expenses and after provisioning for incremental interest required under the 2027 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under its credit facility (the “2015 CCH Credit Facility”).


•	In September 2017, CQP issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). Net proceeds of the offering of approximately $1.5 billion, after deducting commissions, fees and expenses, were used to prepay a portion of the outstanding indebtedness under CQP’s credit facilities (the “2016 CQP Credit Facilities”).


•	Fitch Ratings (“Fitch”) assigned SPL’s senior secured debt an investment grade rating of BBB- in January 2017 and an investment-grade issuer default rating of BBB- in June 2017.


•	In May 2017, Moody’s Investors Service (“Moody’s”) upgraded SPL’s senior secured debt rating from Ba1 to Baa3, an investment-grade rating.


•	In September 2017, Moody’s, S&P Global Ratings and Fitch assigned ratings of Ba2 / BB / BB, respectively to the 2025 CQP Senior Notes.

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 (in millions) provides a summary of our liquidity position at September 30, 2017 and December 31, 2016:



	September 30,		December 31,
	2017		2016
Cash and cash equivalents	$	919	$	876
Restricted cash designated for the following purposes:
SPL Project	627		358
CQP and cash held by guarantor subsidiaries	816		247
CCL Project	117		270
Other	96		76
Available commitments under the following credit facilities:
2015 SPL Credit Facilities	—		1,642
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	479		653
2016 CQP Credit Facilities	190		195
2015 CCH Credit Facility	2,421		3,603
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”)	187		350
Cheniere Revolving Credit Facility	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, 2016.

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 $625.0 million aggregate principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”). We have the right, at our option, at any time after March 15, 2020, to redeem all or any part of the 2045 Cheniere Convertible Senior Notes at a redemption price equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date. 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.

Cash Receipts from Subsidiaries

As of September 30, 2017, 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 $11 million in dividends on our Cheniere Holdings common shares during each of the nine months ended September 30, 2017 and 2016.

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of September 30, 2017, 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. Cheniere Partners’ distributions are being funded from accumulated operating surplus.

We also receive fees for providing management services to Cheniere Holdings, Cheniere Partners, SPLNG, SPL and CTPL. We received $87 million and $101 million in total service fees from Cheniere Holdings, Cheniere Partners, SPLNG, SPL and CTPL during the nine months ended September 30, 2017 and 2016, respectively.

Cheniere Partners’ Class B Units

On August 2, 2017, Cheniere Partners’ Class B units mandatorily converted into common units in accordance with the terms of Cheniere Partners’ partnership agreement. Upon conversion of the Class B units, Cheniere Holdings, Blackstone CQP Holdco LP (“Blackstone CQP Holdco”) and the public owned a 48.6%, 40.3% and 9.1% interest in Cheniere Partners, respectively. Cheniere

Holdings’ ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by The Blackstone Group, L.P., an affiliate of Blackstone CQP Holdco.

Cheniere Partners’ Class B units were subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Cheniere Partners Class B units were not entitled to cash distributions except in the event of a liquidation of Cheniere Partners, a merger, consolidation or other combination of Cheniere Partners with another person or the sale of all or substantially all of the assets of Cheniere Partners. On a quarterly basis beginning on the initial purchase date of the Class B units, the conversion value of the Class B units increased at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings.

The Class B units were issued at a discount to the market price of Cheniere Partners’ common units into which they were convertible. This discount, totaling $2,130 million, represented a beneficial conversion feature. The beneficial conversion feature was similar to a dividend that was distributed with respect to any Class B unit from its issuance date through its conversion date, which resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity, including our equity interest in Cheniere Partners. Cheniere Partners amortized the beneficial conversion feature through the mandatory conversion date as a non-cash adjustment. Deemed dividends represented by the amortization of the beneficial conversion feature allocated to the Class B units held by Blackstone CQP Holdco were included in net income (loss) attributable to non-controlling interest and resulted in a reduction of income available to common stockholders. The impact to net income (loss) attributable to non-controlling interest due to the amortization of the beneficial conversion feature was $370 million and $7 million during the three months ended September 30, 2017 and 2016, respectively, and $748 million and $10 million during the nine months ended September 30, 2017 and 2016, respectively. There will be no further impact to net income (loss) attributable to non-controlling interest due to the amortization of the beneficial conversion feature during the year ending December 31, 2017.

Cheniere Partners

2025 CQP Senior Notes

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 CQP 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.

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 the approximately $2.1 billion of the senior notes previously issued by SPLNG in November 2016, (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, CQP issued the 2025 CQP Senior Notes and the net proceeds of the issuance were used to prepay $1.5 billion of the outstanding indebtedness under the 2016 CQP Credit Facilities. As of September 30, 2017 and December 31, 2016, Cheniere Partners had $190 million and $195 million of available commitments, $50 million and $45 million aggregate amount of issued letters of credit and $1.1 billion and $2.6 billion of outstanding borrowings under the 2016 CQP Credit Facilities, respectively.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit Cheniere Partners’ ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the 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. The following table summarizes the overall project status of the SPL Project as of September 30, 2017:



	SPL Trains 1 & 2		SPL Trains 3 & 4		SPL Train 5
Overall project completion percentage	100%		100%		76.1%
Completion percentage of:
Engineering	100%		100%		100%
Procurement	100%		100%		98.9%
Subcontract work	100%		100%		58.6%
Construction	100%		99.9%		45.1%
Date of expected substantial completion	Train 1	Operational	Train 3	Operational	Train 5	2H 2019
	Train 2	Operational	Train 4	October 2017

We achieved substantial completion of Trains 1, 2 and 3 of the SPL Project and commenced operating activities in May 2016, September 2016 and March 2017, respectively, and subsequently achieved substantial completion of Train 4 of the SPL Project in October 2017.

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 2016, the DOE issued an order 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 on January 15, 2016, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports to non-FTA countries under this order, when combined with exports to non-FTA countries under the orders related to Trains 1 through 4 above, may not exceed 1,006 Bcf/yr).

A party to the proceedings requested rehearings of the orders above related to the export of 803 Bcf/yr, 203 Bcf/yr and 503.3 Bcf/yr to non-FTA countries. The DOE issued orders denying rehearing of the orders. The same party petitioned the U.S. Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review (1) the 203 Bcf/yr order to non-FTA countries and the order denying the request for rehearing of the same and (2) the 503.3 Bcf/yr order to non-FTA countries and the order denying the request for rehearing of the same. The Court of Appeals denied the petition relating to the 503.3 Bcf/yr order to non-FTA countries in November 2017, and the time for review of the court’s denial has not yet expired.

Customers

SPL has entered into six fixed price, 20-year SPAs with extension rights with third parties to make available an aggregate amount of LNG that equates to approximately 19.75 mtpa of LNG, which is approximately 88% of the expected aggregate nominal production capacity of Trains 1 through 5. The obligation to make LNG available under the SPAs commences from the date of first commercial delivery for Trains 1 through 5, as specified in each SPA. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of a specified Train. Under SPL’s SPA with 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 fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion annually for Trains 1 through 5, with the applicable fixed fees starting from the date of first commercial delivery under the respective SPA from the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.

Any LNG produced by SPL in excess of that required for other customers is sold by our integrated marketing function, in fulfilment of various sales commitments.

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing volatility in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of September 30, 2017, SPL has secured up to approximately 2,462 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 prices of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC contract for Train 5 of the SPL Project are approximately $4.1 billion, $3.9 billion and $3.1 billion, respectively, reflecting amounts incurred under change orders through September 30, 2017. 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 SPL delivers its first commercial cargo at the SPL Project. 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 and nine months ended September 30, 2017, SPL recorded $7 million and $15 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

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

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 5 of the SPL Project will be financed through project debt and borrowings and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the SPL Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 5 of the SPL Project and to meet our currently anticipated capital, operating and debt service requirements. SPL began generating cash flows from operations from the SPL Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2 and 3 subsequently achieved substantial completion in September 2016 and March 2017, respectively. We realized offsets to LNG terminal costs of $82 million and $68 million in the three months ended September 30, 2017 and 2016, respectively, and $252 million and $214 million in the nine months ended September 30, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations, during the testing phase for the construction of those Trains of the SPL Project. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table (in millions) provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at September 30, 2017 and December 31, 2016:



	September 30,		December 31,
	2017		2016
Senior notes (1)	$	15,150	$	11,500
Credit facilities outstanding balance (2)	1,090		3,097
Letters of credit issued (3)	721		324
Available commitments under credit facilities (3)	479		2,295
Total capital resources from borrowings and available commitments (4)	$	17,440	$	17,216

(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”), 2028 SPL Senior Notes and 2037 SPL Senior Notes (collectively, the “SPL Senior Notes”) and CQP’s 2025 CQP Senior Notes.


(2)	Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and CTPL and SPLNG tranche term loans outstanding under the 2016 CQP Credit Facilities.


(3)	Includes 2015 SPL Credit Facilities and 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, 2016.

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.

2015 SPL Credit Facilities

In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the SPL Project. In February 2017, SPL issued the 2037 SPL Senior Notes and a portion of the net proceeds of the issuance was used to repay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities. In March 2017, SPL issued the 2028 SPL Senior Notes and SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities.

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“SPL Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“SPL Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the SPL Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the SPL Project, request an incremental increase in commitments of up to an additional $390 million. As of September 30, 2017 and December 31, 2016, SPL had $479 million and $653 million of available commitments, $721 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, on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas. In December 2014, we received authorization from the FERC to site, construct and operate Stages 1 and 2 of the CCL Project. The following table summarizes the overall project status of Stage 1 of the CCL Project as of September 30, 2017:



	CCL Stage 1
Overall project completion percentage	72.4%
Project completion percentage of:
Engineering	100%
Procurement	89.4%
Subcontract work	49.4%
Construction	49.2%
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. A party to the proceeding requested a rehearing of the authorization to non-FTA countries, which was denied by the DOE in May 2016. In July 2016, the same party petitioned the Court of Appeals to review the authorization to non-FTA countries and the DOE order denying the request for rehearing of the same. The Court of Appeals denied the petition in November 2017, and the time for review of the court’s denial has not yet expired.

•

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 has entered into seven fixed price, 20-year SPAs with extension rights with six third parties to make available an aggregate amount of LNG that equates to approximately 7.7 mtpa of LNG, which is approximately 86% of the expected aggregate nominal production capacity of Trains 1 and 2. The obligation to make LNG available under these SPAs commences from the date of first commercial delivery for Trains 1 and 2, as specified in each SPA. In addition, CCL has entered into one fixed price, 20-year SPA with a third party for another 0.8 mtpa of LNG that commences with the date of first commercial delivery for Train 3. Under these eight SPAs, the customers will purchase LNG from CCL for a price consisting of a fixed fee of $3.50 per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of a specified Train.

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

Any LNG produced by CCL that is not required for other customers is sold by our integrated marketing function, in fulfilment of various sales commitments.

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 September 30, 2017, CCL has secured up to approximately 362 TBtu of natural gas feedstock through long-term natural gas supply contracts.

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 September 30, 2017. 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.

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 nearing completion.

Final Investment Decision on Stage 2

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

Capital Resources

We expect to finance the construction costs of the CCL Project from one or more of the following: project financing, operating cash flows from CCL and CCP and equity contributions to our subsidiaries. The following table (in millions) provides a summary of our capital resources from borrowings and available commitments for the CCL Project, excluding equity contributions to our subsidiaries, at September 30, 2017 and December 31, 2016:



	September 30,		December 31,
	2017		2016
Senior notes (1)	$	4,250	$	2,750
11% Convertible Senior Secured Notes due 2025	1,270		1,171
Credit facilities outstanding balance (2)	2,151		2,381
Letters of credit issued (2)	163		—
Available commitments under credit facilities (2)	2,608		3,953
Total capital resources from borrowings and available commitments (3)	$	10,442	$	10,255


(1)	Includes CCH’s 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”), 5.875% Senior Secured Notes due 2025 (the “2025 CCH Senior Notes”) and 2027 CCH Senior Notes (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, 2016.

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

In May 2017, CCH issued an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, in addition to the existing 2024 CCH Senior Notes and 2025 CCH Senior Notes. The CCH Senior Notes are jointly and severally guaranteed by its subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (“CCP GP”, and collectively with CCL and CCP, the “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 September 30, 2017 and December 31, 2016, CCH had $2.4 billion and $3.6 billion of available commitments and $2.2 billion and $2.4 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.

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 September 30, 2017 and December 31, 2016, and CCH had $163 million and zero aggregate amount of issued letters of credit as of September 30, 2017 and December 31, 2016, 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.

Marketing

We market and sell LNG produced by the SPL Project and the CCL Project that is not required for other customers through our integrated marketing function. We are developing a portfolio of long-, medium- and short-term SPAs to transport and unload commercial LNG cargoes to locations worldwide, which is primarily sourced by LNG produced by the SPL Project and the CCL Project but supplemented by volume procured from other locations worldwide, as needed. As of September 30, 2017, we have sold approximately 480 TBtu of LNG to be delivered to counterparties between 2017 and 2023, with delivery obligations conditional in certain circumstances. The cargoes have been sold either on a Free on Board basis (delivered to the counterparty at the Sabine Pass LNG terminal) or a Delivered at Terminal (“DAT”) basis (delivered to the counterparty at their LNG receiving terminal). 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, including reaching an FID related to certain projects and obtaining related financing.

Cheniere Marketing entered into uncommitted trade finance facilities for up to $450 million primarily to be used for the purchase and sale of LNG for ultimate resale in the course of its operations. The finance facilities are intended to be used for advances, guarantees or the issuance of letters of credit or standby letters of credit on behalf of Cheniere Marketing. As of September 30, 2017 and December 31, 2016, Cheniere Marketing had $41 million and $23 million in loans outstanding and $72 million and $12 million, respectively, in standby letters of credit and guarantees outstanding under the finance facilities. Cheniere Marketing pays interest or fees on utilized commitments.

Corporate and Other Activities

We are required to maintain corporate and general and administrative functions to serve our business activities described above. We are also in various stages of developing other projects, 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 (in millions) summarizes the sources and uses of our cash, cash equivalents and restricted cash for the nine months ended September 30, 2017 and 2016. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Nine Months Ended September 30,
	2017			2016
Operating cash flows	$	895		$	(319	)
Investing cash flows	(2,926		)	(3,499		)
Financing cash flows	2,779			3,931

Net increase in cash, cash equivalents and restricted cash	748			113
Cash, cash equivalents and restricted cash—beginning of period	1,827			1,736
Cash, cash equivalents and restricted cash—end of period	$	2,575		$	1,849

Operating Cash Flows

Our operating cash flows increased from outflows of $319 million during the nine months ended September 30, 2016 to inflows of $895 million during the nine months ended September 30, 2017. The $1.2 billion increase in operating cash inflows in 2017 compared to 2016 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 between the periods. During the nine months ended September 30, 2017, Trains 1 and 2 were operating for nine months and Train 3 was operating for six months, whereas Train 1 was operating for four months and Train 2 was operating for less than a month during the comparable period in 2016.

Investing Cash Flows

Investing cash outflows during the nine months ended September 30, 2017 and 2016 were $2.9 billion and $3.5 billion, respectively, and were primarily used to fund the construction costs for Trains 1 through 5 of the SPL Project and Trains 1 and 2 of the CCL Project. These costs are capitalized as construction-in-process until achievement of substantial completion. In addition to cash outflows for construction costs for the SPL Project and the CCL Project, during the nine months ended September 30, 2017, we invested $41 million in our equity method investment Midship Holdings and made payments of $18 million primarily for infrastructure to support the CCL Project. Partially offsetting these cash outflows was a $36 million receipt during the nine months ended September 30, 2017 from the return of collateral payments previously paid for the CCL Project. During the nine months ended September 30, 2016, we used $50 million primarily for collateral payments for the CCL Project, payments to municipal water districts for water system enhancements that will increase potable water supply to our export terminals and payments made for capital assets purchased pursuant to information technology services agreements.

Financing Cash Flows

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


•	issuances of aggregate principal amounts of $800 million of the 2037 SPL Senior Notes and $1.35 billion of the 2028 SPL Senior Notes;


•	$55 million of borrowings and $369 million of repayments made under the 2015 SPL Credit Facilities;


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


•	$1.2 billion of borrowings under the 2015 CCH Credit Facility;


•	issuance of aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, which was used to prepay $1.4 billion of outstanding borrowings under the 2015 CCH Credit Facility;


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


•	issuance of an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which was used to prepay $1.5 billion of the outstanding borrowings under the 2016 CQP Credit Facilities;


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


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


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


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

Financing cash inflows during the nine months ended September 30, 2016 were $3.9 billion, primarily as a result of:


•	$450 million of borrowings under the 2016 CQP Credit Facilities, which was entered into in February to prepay the $400 million CTPL Term Loan;


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


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


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


•	$314 million of borrowings and $230 million of repayments made under the SPL Working Capital Facility;


•	$1.6 billion of borrowings under the 2015 CCH Credit Facility;


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


•	$19 million in net borrowings under the Cheniere Marketing trade finance facilities;


•	$117 million of debt issuance costs related to up-front fees paid upon the closing of these transactions;


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


•	$19 million paid for tax withholdings for share-based compensation.

Results of Operations

The following table summarizes the volumes of operational and commissioning LNG cargoes that were loaded from the SPL Project and recognized on our Consolidated Financial Statements during the three and nine months ended September 30, 2017:



	Three Months Ended September 30, 2017				Nine Months Ended September 30, 2017
(in TBtu)	Operational		Commissioning		Operational		Commissioning
Volumes loaded during the current period	144		18		439		44
Volumes loaded during the prior period but recognized during the current period	14		—		19		—
Less: volumes loaded during the current period and in transit at the end of the period	(7	)	(4	)	(7	)	(4	)
Total volumes recognized in the current period	151		14		451		40

Our consolidated net loss attributable to common stockholders was $289 million, or $1.24 per share (basic and diluted), in the three months ended September 30, 2017, compared to a net loss attributable to common stockholders of $101 million, or $0.44 per share (basic and diluted), in the three months ended September 30, 2016. This $188 million increase in net loss in 2017 was primarily a result of increased allocation of net income to non-controlling interest, increased interest expense, net of amounts capitalized, and increased derivative loss, net associated with interest rate derivative activity, which were partially offset by increased income from operations.

Our consolidated net loss attributable to common stockholders was $520 million, or $2.24 per share (basic and diluted), in the nine months ended September 30, 2017, compared to a net loss attributable to common stockholders of $720 million, or $3.15 per share (basic and diluted), in the nine months ended September 30, 2016. This $200 million decrease in net loss in 2017 was

primarily a result of increased income from operations and decreased derivative loss, net associated with interest rate derivative activity, which were partially offset by increased allocation of net income to non-controlling interest and increased interest expense, net of amounts capitalized.

In August 2017, Hurricane Harvey struck the Texas and Louisiana coasts, and the Sabine Pass LNG terminal experienced a temporary suspension in construction and LNG loading operations. Construction on the Corpus Christi LNG terminal was also suspended. Neither terminal sustained significant damage, and the effects of Hurricane Harvey did not have a material impact on our Consolidated Financial Statements.

Revenues



	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2017		2016		Change		2017		2016		Change
LNG revenues	$	1,332	$	399	$	933	$	3,646	$	512	$	3,134
Regasification revenues	65		64		1		195		194		1
Other revenues	5		2		3		12		5		7
Other—related party	1		—		1		2		—		2
Total revenues	$	1,403	$	465	$	938	$	3,855	$	711	$	3,144

We began recognizing LNG revenues from the SPL Project following the substantial completion and the commencement of operating activities of Train 1 in May 2016. Trains 2 and 3 subsequently achieved substantial completion in September 2016 and March 2017, respectively. The increase in revenues for the three and nine months ended September 30, 2017 from the comparable periods in 2016 was attributable to both the increased volume of LNG sold that was recognized as revenues following the achievement of substantial completion of these Trains, as well as increased revenues per MMBtu. As additional Trains become operational, we expect our LNG revenues to increase in the future.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process because these amounts are earned or loaded during the testing phase for the construction of that Train. We realized offsets to LNG terminal costs of $82 million corresponding to 14 TBtu of LNG and $68 million corresponding to 10 TBtu of LNG in the three months ended September 30, 2017 and 2016, respectively, and $252 million corresponding to 40 TBtu of LNG and $214 million corresponding to 45 TBtu of LNG in the nine months ended September 30, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes.

The following table presents the components of LNG revenues (in millions) and the corresponding LNG volumes sold (in TBtu).



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017		2016
LNG revenues (in millions):
LNG from the SPL Project sold under SPL’s third party long-term SPAs	$	715		$	174	$	1,669	$	256
LNG from the SPL Project sold by our integrated marketing function	200			92		1,337		95
LNG procured from third parties	427			123		631		163
Other revenues and derivative gains (losses)	(10		)	10		9		(2		)
Total LNG revenues	$	1,332		$	399	$	3,646	$	512

Volumes sold as LNG revenues (in TBtu):
LNG from the SPL Project sold under SPL’s third party long-term SPAs	118			32		275		50
LNG from the SPL Project sold by our integrated marketing function	33			18		176		19
LNG procured from third parties	45			14		64		18
Total volumes sold as LNG revenues	196			64		515		87

Operating costs and expenses



	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions)	2017		2016		Change			2017		2016		Change
Cost of sales	$	824	$	253	$	571		$	2,140	$	353	$	1,787
Operating and maintenance expense	114		61		53			309		143		166
Development expense	3		2		1			7		5		2
Selling, general and administrative expense	64		59		5			179		197		(18		)
Depreciation and amortization expense	92		49		43			252		106		146
Restructuring expense	—		26		(26		)	6		49		(43		)
Impairment expense and loss on disposal of assets	9		—		9			15		10		5
Total operating costs and expenses	$	1,106	$	450	$	656		$	2,908	$	863	$	2,045

Our total operating costs and expenses increased during the three and nine months ended September 30, 2017 from the comparable periods in 2016, primarily as a result of additional Trains that were operating between the periods. During the nine months ended September 30, 2017, Trains 1 and 2 were operating for nine months and Train 3 was operating for six months, whereas Train 1 was operating for four months and Train 2 was operating for less than a month during the comparable period in 2016.

Cost of sales increased during the three and nine months ended September 30, 2017 from the comparable periods in 2016, primarily as a result of the increase in operating Trains during 2017. Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project, to the extent those costs are not utilized for the commissioning process. The increase during the three and nine months ended September 30, 2017 from the comparable periods in 2016 was primarily related to the increase in both the volume and pricing of natural gas feedstock. 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 and nine months ended September 30, 2017 from the comparable periods in 2016, as a result of the increase in operating Trains during 2017. Operating and maintenance expense includes costs associated with operating and maintaining the SPL Project and CCL Project. The increase during the three and nine months ended September 30, 2017 from the comparable periods in 2016 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 the commencement of payments under the partial TUA assignment agreement with Total, insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the three and nine months ended September 30, 2017 from the comparable periods in 2016 as a result of increased number of operational Trains, as the assets related to the Trains of the SPL Project began depreciating upon reaching substantial completion.

As additional Trains become operational, we expect our operating costs and expenses to generally increase in the future, although certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.

Partially offsetting the increases above was a decrease in restructuring expense, which was primarily due to the completion of organizational initiatives as of March 31, 2017.

Impairment expense and loss on disposal of assets increased during the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016. The impairment expense and loss on disposal of assets recognized during the three and nine months ended September 30, 2017 and nine months ended September 30, 2016 each related to write down of assets used in non-core operations outside of our liquefaction activities.

Other expense (income)



	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions)	2017			2016			Change			2017			2016		Change
Interest expense, net of capitalized interest	$	186		$	148		$	38		$	539		$	330	$	209
Loss on early extinguishment of debt	25			26			(1		)	100			83		17
Derivative loss (gain), net	2			(30		)	32			37			242		(205		)
Other expense (income)	(4		)	—			(4		)	(11		)	6		(17		)
Total other expense	$	209		$	144		$	65		$	665		$	661	$	4

Interest expense, net of capitalized interest, increased during the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016, primarily as a result of an increase in our indebtedness outstanding (before premium, discount and unamortized debt issuance costs), from $21.5 billion as of September 30, 2016 to $25.7 billion as of September 30, 2017, and a decrease in the portion of total interest costs that could be capitalized as Trains 1 through 3 of the SPL Project completed construction. For the three and nine months ended September 30, 2017, we incurred $389 million and $1.1 billion of total interest cost, respectively, of which we capitalized $203 million and $581 million, respectively, which was directly related to the construction of the SPL Project and the CCL Project. For the three and nine months ended September 30, 2016, we incurred $341 million and $951 million of total interest cost, respectively, of which we capitalized $193 million and $621 million, respectively, which was directly related to the construction of the SPL Project and the CCL Project.

Loss on early extinguishment of debt decreased during the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. Loss on early extinguishment of debt recognized during the nine months ended September 30, 2017 was attributable to the write-offs of debt issuance costs of (1) $42 million in March 2017 upon termination of the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities in connection with the issuance of the 2028 SPL Senior Notes; (2) $33 million in May 2017 upon the prepayment of approximately $1.4 billion of outstanding borrowings under the 2015 CCH Credit Facility in connection with the issuance of the 2027 CCH Senior Notes; and (3) $25 million in September 2017 related to the prepayment of $1.5 billion of the outstanding indebtedness under the 2016 CQP Credit Facilities in connection with the issuance of the 2025 CQP Senior Notes. Loss on early extinguishment of debt during the nine months ended September 30, 2016 was primarily attributable to the write-offs of debt issuance costs of (1) $29 million in May 2016 upon the prepayment of approximately $1.1 billion of outstanding borrowings under the 2015 CCH Credit Facility in connection with the issuance of the 2024 CCH Senior Notes; (2) $26 million in June 2016 upon the prepayment of approximately $1.3 billion of outstanding borrowings under the 2015 SPL Credit Facilities in connection with the issuance of the 2026 SPL Senior Notes; and (3) $26 million in September 2016 related to the prepayment of outstanding borrowings and termination of commitments under the 2015 SPL Credit Facilities of approximately $1.4 billion in connection with the issuance of the 2027 SPL Senior Notes.

Derivative loss, net increased during the three months ended September 30, 2017 from a gain during the three months ended September 30, 2016, primarily due to an unfavorable shift in the long-term forward LIBOR curve between the periods. Derivative loss, net decreased during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods, partially offset by a $7 million loss in March 2017 upon the settlement of interest rate swaps associated with approximately $1.6 billion of commitments that were terminated under the 2015 SPL Credit Facilities and a $13 million loss in May 2017 in conjunction with the termination of approximately $1.4 billion of commitments under the 2015 CCH Credit Facility.

Other



	Three Months Ended September 30,									Nine Months Ended September 30,
(in millions)	2017			2016			Change			2017			2016			Change
Income tax benefit (provision)	$	(2	)	$	2		$	(4	)	$	(1	)	$	2		$	(3	)
Net income (loss) attributable to non-controlling interest	379			(30		)	409			803			(95		)	898

Net income attributable to non-controlling interest increased during the three and nine months ended September 30, 2017 from the comparable periods in 2016 primarily due to the amortization of the beneficial conversion feature on Cheniere Partners’ Class B units and increase in consolidated net income recognized by Cheniere Partners in which the non-controlling interest is held. Net income attributable to non-controlling interest was increased by $363 million and $738 million for non-cash amortization of the beneficial conversion feature on Cheniere Partners’ Class B units during the three and nine months ended September 30, 2017, respectively. Although the amortization of the beneficial conversion feature on Cheniere Partners’ Class B units ceased

upon the conversion of these units into common units on August 2, 2017, the share of Cheniere Partners’ net income (loss) that is attributed to non-controlling interest holders has increased from that date as a result of the increased ownership percentage by non-controlling interest holders. The consolidated net income recognized by Cheniere Partners increased from a net loss of $82 million and $257 million in the three and nine months ended September 30, 2016, respectively, to a net income of $23 million and $116 million in the three and nine months ended September 30, 2017, respectively, primarily as a result of the additional Trains that were operating at the SPL Project between the periods, which was partially offset by increased interest expense, net of amounts capitalized.

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, 2016.

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):



	September 30, 2017					December 31, 2016
	Fair Value			Change in Fair Value		Fair Value			Change in Fair Value
Liquefaction Supply Derivatives	$	28		$	1	$	73		$	6
LNG Trading Derivatives	(21		)	1		(3		)	—

Interest Rate Risk

SPL, CQP 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 2015 SPL Credit Facilities (“SPL Interest Rate Derivatives”), the 2016 CQP Credit Facilities (“CQP Interest Rate Derivatives”) and the 2015 CCH Credit Facility (“CCH Interest Rate Derivatives” and collectively, with the SPL Interest Rate Derivatives and the CQP Interest Rate Derivatives, the “Interest Rate Derivatives”), respectively. In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining terms of the Interest Rate Derivatives as follows (in millions):



	September 30, 2017					December 31, 2016
	Fair Value			Change in Fair Value		Fair Value			Change in Fair Value
SPL Interest Rate Derivatives	$	—		$	—	$	(6	)	$	2
CQP Interest Rate Derivatives	14			5		13			6
CCH Interest Rate Derivatives	(79		)	43		(86		)	52

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 September 30, 2017 and December 31, 2016.

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

Please see Part II, Item 1, “Legal Proceedings - Parallax Litigation” in the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2017.


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, 2016.


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

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended September 30, 2017:



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 Shares That May Yet Be Purchased Under the Plans
July 1 - 31, 2017	11,025	$48.72	—	—
August 1 - 31, 2017	10,122	$44.89	—	—
September 1 - 30, 2017	335	$44.54	—	—


(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
4.1		Indenture, dated as of September 18, 2017, between Cheniere Energy Partners, L.P., the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 18, 2017)
4.2		First Supplemental Indenture, dated as of September 18, 2017, between Cheniere Energy Partners, L.P., the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 18, 2017)
4.3		Form of 5.250% Senior Note due 2025 (Included as Exhibit A-1 to Exhibit 4.2 above)
10.1		Consent for Amendment to the Common Security and Account Agreement, dated September 7, 2017, among Cheniere Corpus Christi Holdings, LLC, as Company, Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P., and Corpus Christi Pipeline GP, LLC, 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 (Incorporated by reference to Exhibit 10.51 to CCH’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017)
10.2		Consent for Amendment to the Common Terms Agreement, dated September 7, 2017, among Cheniere Corpus Christi Holdings, LLC, as Borrower, Corpus Christi Liquefaction, LLC, Cheniere Corpus Christi Pipeline, L.P., Corpus Christi Pipeline GP, LLC, as Guarantors, Société Générale, as Term Loan Facility Agent and Intercreditor Agent and any other facility agents party thereto from time to time (Incorporated by reference to Exhibit 10.52 to CCH’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017)
10.3*		Administrative Amendment, dated August 7, 2017, to the Credit and Guaranty Agreement among Cheniere Partners, as Borrower, certain subsidiaries of Cheniere Partners, as Subsidiary Guarantors, the lenders from time to time party thereto, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank, Administrative Agent and Coordinating Lead Arranger, and certain arrangers and other participants
10.4		Registration Rights Agreement, dated as of September 18, 2017, between Cheniere Energy Partners, L.P., the guarantors party thereto and Credit Suisse Securities (USA) LLC (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 18, 2017)
10.5*		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00059 Insurance Provisional Sum Closeout, dated May 18, 2017
10.6*		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00037 HPAA Compressor MODBUS Link, dated June 28, 2017 and (ii) the Change Order CO-00038 Existing Facility Labor Provisional Sum Closure, dated August 24, 2017
10.7*		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00021 Soils Preparation Provisional Sum Partial True-Up RECON 3, dated August 24, 2017
10.8		Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between Corpus Christi Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00036 Security Fencing Revisions, 138kV Overhead Power Stop Work, Additional Permanent Plant Access Control System Changes, and Wet/Dry Flare Expansion Loop Relocation, dated August 3, 2017 and (ii) the Change Order CO-00037 9% Nickel Lump Sum Conversion, dated September 14, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.50 to CCH’s Registration Statement on Form S-4 (SEC File No. 333-221307), filed on November 2, 2017)
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



Exhibit No.		Description
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:	November 8, 2017	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)

Date:	November 8, 2017	By:	/s/ Leonard Travis
			Leonard Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)