Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2019

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

For the transition period from to

Commission file number 001-16383

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)



Delaware			95-4352386
(State or other jurisdiction of incorporation or organization)			(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)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $ 0.003 par value	LNG	NYSE American

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

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

As of August 2, 2019, the issuer had 256,779,983 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 Statements of Stockholders’ Equity	5
	Consolidated Statements of Cash Flows	7
	Notes to Consolidated Financial Statements	8

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

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	50

Item 4.	Controls and Procedures	51

Part II. Other Information
Item 1.	Legal Proceedings	52

Item 1A.	Risk Factors	52

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

Item 6.	Exhibits	53

	Signatures	54

DEFINITIONS

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

Common Industry and Other Terms



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

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of June 30, 2019, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

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

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)



	June 30,			December 31,
	2019			2018
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	2,279		$	981
Restricted cash	1,161			2,175
Accounts and other receivables	433			585
Inventory	290			316
Derivative assets	127			63
Other current assets	135			114
Total current assets	4,425			4,234

Property, plant and equipment, net	29,073			27,245
Operating lease assets, net	502			—
Debt issuance costs, net	55			72
Non-current derivative assets	103			54
Goodwill	77			77
Other non-current assets, net	337			305
Total assets	$	34,572		$	31,987

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	120		$	58
Accrued liabilities	1,572			1,169
Current debt	—			239
Deferred revenue	136			139
Current operating lease liabilities	292			—
Derivative liabilities	84			128
Other current liabilities	3			9
Total current liabilities	2,207			1,742

Long-term debt, net	29,944			28,179
Non-current operating lease liabilities	202			—
Non-current finance lease liabilities	58			57
Non-current derivative liabilities	94			22
Other non-current liabilities	44			58

Commitments and contingencies (see Note 16)

Stockholders’ equity
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—			—
Common stock, $0.003 par value
Authorized: 480.0 million shares at June 30, 2019 and December 31, 2018
Issued: 270.5 million shares at June 30, 2019 and 269.8 million shares at December 31, 2018
Outstanding: 257.5 million shares at June 30, 2019 and 257.0 million shares at December 31, 2018	1			1
Treasury stock: 13.0 million shares and 12.8 million shares at June 30, 2019 and December 31, 2018, respectively, at cost	(423		)	(406		)
Additional paid-in-capital	4,097			4,035
Accumulated deficit	(4,129		)	(4,156		)
Total stockholders’ deficit	(454		)	(526		)
Non-controlling interest	2,477			2,455
Total equity	2,023			1,929
Total liabilities and equity	$	34,572		$	31,987

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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Revenues
LNG revenues	$	2,173		$	1,442		$	4,316		$	3,608
Regasification revenues	67			65			133			130
Other revenues	52			36			104			47
Total revenues	2,292			1,543			4,553			3,785

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	1,277			873			2,491			2,051
Operating and maintenance expense	295			147			516			287
Development expense	3			3			4			4
Selling, general and administrative expense	77			73			150			140
Depreciation and amortization expense	204			111			348			220
Impairment expense and loss on disposal of assets	4			—			6			—
Total operating costs and expenses	1,860			1,207			3,515			2,702

Income from operations	432			336			1,038			1,083

Other income (expense)
Interest expense, net of capitalized interest	(372		)	(216		)	(619		)	(432		)
Loss on modification or extinguishment of debt	—			(15		)	—			(15		)
Derivative gain (loss), net	(74		)	32			(109		)	109
Other income	16			10			32			17
Total other expense	(430		)	(189		)	(696		)	(321		)

Income before income taxes and non-controlling interest	2			147			342			762
Income tax benefit (provision)	—			3			(3		)	(12		)
Net income	2			150			339			750
Less: net income attributable to non-controlling interest	116			168			312			411
Net income (loss) attributable to common stockholders	$	(114	)	$	(18	)	$	27		$	339

Net income (loss) per share attributable to common stockholders—basic (1)	$	(0.44	)	$	(0.07	)	$	0.11		$	1.42
Net income (loss) per share attributable to common stockholders—diluted (1)	$	(0.44	)	$	(0.07	)	$	0.11		$	1.40

Weighted average number of common shares outstanding—basic	257.4			242.8			257.3			239.2
Weighted average number of common shares outstanding—diluted	257.4			242.8			258.6			241.7

(1) Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in millions)

(unaudited)



Three and Six Months Ended June 30, 2019
	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, 2018	257.0		$	1	12.8	$	(406	)	$	4,035	$	(4,156	)	$	2,455		$	1,929
Vesting of restricted stock units	0.6		—		—	—			—		—			—			—
Share-based compensation	—		—		—	—			28		—			—			28
Shares withheld from employees related to share-based compensation, at cost	(0.2	)	—		0.2	(12		)	—		—			—			(12		)
Net income attributable to non-controlling interest	—		—		—	—			—		—			196			196
Distributions and dividends to non-controlling interest	—		—		—	—			—		—			(144		)	(144		)
Net income	—		—		—	—			—		141			—			141
Balance at March 31, 2019	257.4		1		13.0	(418		)	4,063		(4,015		)	2,507			2,138
Vesting of restricted stock units	0.1		—		—	—			—		—			—			—
Share-based compensation	—		—		—	—			33		—			—			33
Shares withheld from employees related to share-based compensation, at cost	—		—		—	(2		)	—		—			—			(2		)
Shares repurchased, at cost	—		—		—	(3		)	—		—			—			(3		)
Net income attributable to non-controlling interest	—		—		—	—			—		—			116			116
Equity portion of convertible notes, net	—		—		—	—			1		—			—			1
Distributions and dividends to non-controlling interest	—		—		—	—			—		—			(146		)	(146		)
Net loss	—		—		—	—			—		(114		)	—			(114		)
Balance at June 30, 2019	257.5		$	1	13.0	$	(423	)	$	4,097	$	(4,129	)	$	2,477		$	2,023

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY—CONTINUED

(in millions)

(unaudited)



Three and Six Months Ended June 30, 2018
	Total Stockholders’ Equity
	Common Stock				Treasury Stock				Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Equity
	Shares		Par Value Amount		Shares	Amount			Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Equity
Balance at December 31, 2017	237.6		$	1	12.5	$	(386	)	$	3,248	$	(4,627	)	$	3,004		$	1,240
Vesting of restricted stock units	0.3		—		—	—			—		—			—			—
Share-based compensation	—		—		—	—			16		—			—			16
Shares withheld from employees related to share-based compensation, at cost	—		—		0.1	(6		)	—		—			—			(6		)
Net income attributable to non-controlling interest	—		—		—	—			—		—			243			243
Distributions and dividends to non-controlling interest	—		—		—	—			—		—			(143		)	(143		)
Net income	—		—		—	—			—		357			—			357
Balance at March 31, 2018	237.9		1		12.6	(392		)	3,264		(4,270		)	3,104			1,707
Issuance of stock to acquire additional interest in Cheniere Holdings	10.3		—		—	—			376		—			(376		)	—
Share-based compensation	—		—		—	—			23		—			—			23
Shares withheld from employees related to share-based compensation, at cost	(0.1	)	—		—	(2		)	—		—			—			(2		)
Net income attributable to non-controlling interest	—		—		—	—			—		—			168			168
Equity portion of convertible notes, net	—		—		—	—			1		—			—			1
Distributions and dividends to non-controlling interest	—		—		—	—			—		—			(145		)	(145		)
Net loss	—		—		—	—			—		(18		)	—			(18		)
Balance at June 30, 2018	248.1		$	1	12.6	$	(394	)	$	3,664	$	(4,288	)	$	2,751		$	1,734

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)



	Six Months Ended June 30,
	2019			2018
Cash flows from operating activities
Net income	$	339		$	750
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	348			220
Share-based compensation expense	61			58
Non-cash interest expense	93			30
Amortization of debt issuance costs, deferred commitment fees, premium and discount	44			35
Amortization of operating lease assets	158			—
Loss on modification or extinguishment of debt	—			15
Total losses (gains) on derivatives, net	(147		)	4
Net cash provided by (used for) settlement of derivative instruments	62			(8		)
Impairment expense and loss on disposal of assets	6			—
Other	2			(5		)
Changes in operating assets and liabilities:
Accounts and other receivables	59			80
Inventory	33			10
Other current assets	(46		)	(61		)
Accounts payable and accrued liabilities	(80		)	(132		)
Deferred revenue	(2		)	(13		)
Operating lease liabilities	(163		)	—
Other, net	(7		)	(1		)
Net cash provided by operating activities	760			982

Cash flows from investing activities
Property, plant and equipment, net	(1,508		)	(1,508		)
Investment in equity method investment	(34		)	—
Other	—			16
Net cash used in investing activities	(1,542		)	(1,492		)

Cash flows from financing activities
Proceeds from issuances of debt	2,021			1,799
Repayments of debt	(630		)	(281		)
Debt issuance and deferred financing costs	(20		)	(46		)
Debt extinguishment costs	—			(8		)
Distributions and dividends to non-controlling interest	(290		)	(288		)
Payments related to tax withholdings for share-based compensation	(14		)	(8		)
Repurchase of common stock	(3		)	—
Other	2			—
Net cash provided by financing activities	1,066			1,168

Net increase in cash, cash equivalents and restricted cash	284			658
Cash, cash equivalents and restricted cash—beginning of period	3,156			2,613
Cash, cash equivalents and restricted cash—end of period	$	3,440		$	3,271

Balances per Consolidated Balance Sheet:



	June 30, 2019
Cash and cash equivalents	$	2,279
Restricted cash	1,161
Total cash, cash equivalents and restricted cash	$	3,440

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 own and operate two natural gas liquefaction and export facilities at Sabine Pass and Corpus Christi. 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 in various stages of constructing and operating six 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. Trains 1 through 5 are operational and Train 6 is under construction. 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.

The Corpus Christi LNG terminal is located near Corpus Christi, Texas and is operated by our wholly owned subsidiary CCL. We also operate a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the liquefaction facilities, the “CCL Project”) through our wholly owned subsidiary CCP. The CCL Project is being developed in stages with the first phase being three Trains (“Phase 1”). The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the CCL Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). Train 1 is operational, Train 2 is undergoing commissioning and Train 3 is under construction.

Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (“Corpus Christi Stage 3”) and filed an application with FERC in June 2018 for seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa and one LNG storage tank.

We remain focused on expansion of our existing sites by leveraging existing infrastructure. We continue to consider development of 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, 2018. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

Results of operations for the three and six months ended June 30, 2019 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2019.

Recent Accounting Standards

We adopted ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard resulted in the recognition of right-of-use assets and lease liabilities for operating leases of approximately $550 million on our Consolidated Balance Sheets, with no material impact on our Consolidated Statements of Operations or Consolidated Statements of Cash Flows. We have elected the practical expedients to (1) carryforward prior conclusions related to lease identification and classification for existing leases, (2) combine lease and non-lease components of an arrangement for all classes of leased assets, (3) omit short-term leases with a term of 12 months or less from recognition on the balance sheet and (4) carryforward our existing accounting for land easements not previously accounted for as leases. See Note 11—Leases for additional information on our leases following the adoption of this standard.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 2—RESTRICTED CASH

Restricted cash consists of funds that are contractually and legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of June 30, 2019 and December 31, 2018, restricted cash consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Current restricted cash
SPL Project	$	596	$	756
Cheniere Partners and cash held by guarantor subsidiaries	—		785
CCL Project	279		289
Cash held by our subsidiaries restricted to Cheniere	286		345
Total current restricted cash	$	1,161	$	2,175

Pursuant to the accounts agreements entered into with the collateral trustees for the benefit of SPL’s debt holders and CCH’s debt holders, SPL and CCH are required to deposit all cash received into reserve accounts controlled by the collateral trustees. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) and other restricted payments.

In May 2019, Cheniere Partners entered into the $1.5 billion credit facilities (the “2019 CQP Credit Facilities”), which replaced the previous $2.8 billion credit facilities (the “2016 CQP Credit Facilities”). The cash held by Cheniere Partners and its guarantor subsidiaries was restricted in use under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to Cheniere Partners, but is no longer restricted under the 2019 CQP Credit Facilities.

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

As of June 30, 2019 and December 31, 2018, accounts and other receivables consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Trade receivables
SPL and CCL	$	257	$	330
Cheniere Marketing	145		205
Other accounts receivable	31		50
Total accounts and other receivables	$	433	$	585

NOTE 4—INVENTORY

As of June 30, 2019 and December 31, 2018, inventory consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Natural gas	$	19	$	30
LNG	38		24
LNG in-transit	104		173
Materials and other	129		89
Total inventory	$	290	$	316

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

As of June 30, 2019 and December 31, 2018, property, plant and equipment, net consisted of the following (in millions):



	June 30,			December 31,
	2019			2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	23,650		$	13,386
LNG site and related costs	319			86
LNG terminal construction-in-process	6,529			14,864
Accumulated depreciation	(1,625		)	(1,299		)
Total LNG terminal costs, net	28,873			27,037
Fixed assets and other
Computer and office equipment	22			17
Furniture and fixtures	22			22
Computer software	104			100
Leasehold improvements	42			41
Land	59			59
Other	20			21
Accumulated depreciation	(127		)	(111		)
Total fixed assets and other, net	142			149
Assets under finance lease
Tug vessels	60			60
Accumulated depreciation	(2		)	(1		)
Total assets under finance lease, net	58			59
Property, plant and equipment, net	$	29,073		$	27,245

Depreciation expense was $203 million and $111 million during the three months ended June 30, 2019 and 2018, respectively, and $346 million and $219 million during the six months ended June 30, 2019 and 2018, respectively.

We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We realized offsets to LNG terminal costs of $202 million during the six months ended June 30, 2019 for sales of commissioning cargoes from the Liquefaction Projects. We did not realize any offsets to LNG terminal costs during the three months ended June 30, 2019 and the three and six months ended June 30, 2018.

NOTE 6—DERIVATIVE INSTRUMENTS

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


•	interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under CCH’s credit facilities (“CCH Interest Rate Derivatives”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH (“CCH Interest Rate Forward Start Derivatives”);


•	commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project, CCL Project and potential future development of Corpus Christi Stage 3 (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”);


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


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

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of June 30, 2019 and December 31, 2018, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions):



	Fair Value Measurements as of
	June 30, 2019											December 31, 2018
	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
CCH Interest Rate Derivatives asset (liability)	$	—		$	(88	)	$	—	$	(88	)	$	—	$	18		$	—		$	18
CCH Interest Rate Forward Start Derivatives liability	—			(7		)	—		(7		)	—		—			—			—
Liquefaction Supply Derivatives asset (liability)	—			1			89		90			6		(19		)	(29		)	(42		)
LNG Trading Derivatives asset (liability)	(4		)	51			—		47			1		(25		)	—			(24		)
FX Derivatives asset	—			10			—		10			—		15			—			15

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

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of June 30, 2019 and December 31, 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration. In determining and recording fair value, we do not use third party sources that derive price based on proprietary models or market surveys.

The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2019:



	Net Fair Value Asset (Liability) (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$89	Market approach incorporating present value techniques	Henry Hub Basis Spread	$(0.700) - $0.056
		Option pricing model	International pricing spread, relative to Henry Hub (1)	128% - 176%

(1) Spread contemplates U.S. dollar-denominated pricing.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and six months ended June 30, 2019 and 2018 (in millions):



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019			2018
Balance, beginning of period	$	31	$	10		$	(29	)	$	43
Realized and mark-to-market gains (losses):
Included in cost of sales	7		(1		)	23			(12		)
Purchases and settlements:
Purchases	50		6			50			6
Settlements	1		(4		)	45			(25		)
Transfers out of Level 3 (1)	—		1			—			—
Balance, end of period	$	89	$	12		$	89		$	12
Change in unrealized gains (losses) relating to instruments still held at end of period	$	7	$	(1	)	$	23		$	(12	)

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

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of netting and any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

Interest Rate Derivatives

During the six months ended June 30, 2019, there were no changes to the terms of the CCH Interest Rate Derivatives entered into by CCH to protect against volatility of future cash flows and hedge a portion of the variable interest payments on its credit facility (the “CCH Credit Facility”).

In June 2019, we entered into the CCH Interest Rate Forward Start Derivatives to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH, which is anticipated by the end of 2020.

Cheniere Partners previously had interest rate swaps (“CQP Interest Rate Derivatives” and, collectively with the CCH Interest Rate Derivatives and the CCH Interest Rate Forward Start Derivatives, the “Interest Rate Derivatives”) to hedge a portion of the variable interest payments on its credit facilities, which were terminated in October 2018.

As of June 30, 2019, 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

CCH Interest Rate Derivatives

$29 million

$4.7 billion

May 20, 2015

May 31, 2022

2.30%

One-month LIBOR

CCH Interest Rate Forward Start Derivatives

$1.0 billion

June 30, 2020

September 30, 2030

2.11%

Three-month LIBOR

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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



	June 30, 2019									December 31, 2018
	CCH Interest Rate Derivatives			CCH Interest Rate Forward Start Derivatives			Total			CCH Interest Rate Derivatives		CCH Interest Rate Forward Start Derivatives		Total
Consolidated Balance Sheet Location
Derivative assets	$	—		$	—		$	—		$	10	$	—	$	10
Non-current derivative assets	—			—			—			8		—		8
Total derivative assets	—			—			—			18		—		18

Derivative liabilities	(21		)	—			(21		)	—		—		—
Non-current derivative liabilities	(67		)	(7		)	(74		)	—		—		—
Total derivative liabilities	(88		)	(7		)	(95		)	—		—		—

Derivative asset (liability), net	$	(88	)	$	(7	)	$	(95	)	$	18	$	—	$	18

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and six months ended June 30, 2019 and 2018 (in millions):



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
CCH Interest Rate Derivatives gain (loss)	$	(67	)	$	29	$	(102	)	$	98
CCH Interest Rate Forward Start Derivatives loss	(7		)	—		(7		)	—
CQP Interest Rate Derivatives gain	—			3		—			11

Commodity Derivatives

SPL, CCL and CCL Stage III have entered into physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the SPL Project, the CCL Project and potential future development of Corpus Christi Stage 3, respectively, which are primarily indexed to the natural gas market and international LNG indices. The terms of the index-based physical natural gas supply contracts range up to approximately 15 years, some of which commence upon the satisfaction of certain conditions precedent.

We have entered into, and may from time to time enter into, financial LNG Trading Derivatives in the form of swaps, forwards, options or futures to economically hedge exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG. We have entered into LNG Trading Derivatives to secure a fixed price position to minimize future cash flow variability associated with LNG purchase and sale transactions.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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



	June 30, 2019									December 31, 2018
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total			Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total
Consolidated Balance Sheet Location
Derivative assets	$	24		$	92		$	116		$	13		$	24		$	37
Non-current derivative assets	94			9			103			46			—			46
Total derivative assets	118			101			219			59			24			83

Derivative liabilities	(13		)	(50		)	(63		)	(79		)	(48		)	(127		)
Non-current derivative liabilities	(15		)	(4		)	(19		)	(22		)	—			(22		)
Total derivative liabilities	(28		)	(54		)	(82		)	(101		)	(48		)	(149		)

Derivative asset (liability), net	$	90		$	47		$	137		$	(42	)	$	(24	)	$	(66	)

Notional amount, net (in TBtu) (3)	6,781			50						5,832			12

(1)

Does not include collateral calls of $6 million and $5 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018, respectively. Includes derivative assets of $2 million and $2 million and non-current assets of $1 million and $3 million as of June 30, 2019 and December 31, 2018, respectively, for a natural gas supply contract CCL has with a related party.


(2)	Does not include collateral of $15 million and $9 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018, respectively.

(3)

SPL had secured up to approximately 3,437 TBtu and 3,464 TBtu as of June 30, 2019 and December 31, 2018, respectively. CCL had secured up to approximately 2,787 TBtu and 2,801 TBtu of natural gas feedstock through natural gas supply contracts as of June 30, 2019 and December 31, 2018, respectively, of which 57 TBtu and 55 TBtu, respectively, were for a natural gas supply contract CCL has with a related party. Corpus Christi Stage 3 had secured up to approximately 754 TBtu of natural gas feedstock through natural gas supply contracts as of June 30, 2019.

The following table shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2019 and 2018 (in millions):



	Consolidated Statements of Operations Location (1)	Three Months Ended June 30,						Six Months Ended June 30,
	Consolidated Statements of Operations Location (1)	2019			2018			2019			2018
LNG Trading Derivatives gain (loss)	LNG revenues	$	94		$	(76	)	$	158		$	(70	)
LNG Trading Derivatives loss	Cost of sales	(51		)	—			(51		)	—
Liquefaction Supply Derivatives gain (loss) (2)	LNG revenues	(1		)	—			1			—
Liquefaction Supply Derivatives gain (loss) (2)(3)	Cost of sales	57			(3		)	139			(53		)


(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.


(3)	Includes $24 million and $36 million that CCL recorded in cost of sales under a natural gas supply contract with a related party during the three and six months ended June 30, 2019, respectively. Of this amount, $4 million was included in accrued liabilities as of June 30, 2019. CCL did not have any transactions during the three and six months ended June 30, 2018 under this contract.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

FX Derivatives

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



		Fair Value Measurements as of
	Consolidated Balance Sheet Location	June 30, 2019			December 31, 2018
FX Derivatives	Derivative assets	$	11		$	16
FX Derivatives	Derivative liabilities	—			(1		)
FX Derivatives	Non-current derivative liabilities	(1		)	—

The total notional amount of our FX Derivatives was $942 million and $379 million as of June 30, 2019 and December 31, 2018, respectively.

The following table shows the changes in the fair value, settlements and location of our FX Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2019 and 2018 (in millions):



		Three Months Ended June 30,				Six Months Ended June 30,
	Consolidated Statements of Operations Location	2019		2018		2019		2018
FX Derivatives gain	LNG revenues	$	—	$	12	$	9	$	10

Consolidated Balance Sheet Presentation

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



	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
As of June 30, 2019
CCH Interest Rate Derivatives	$	(88	)	$	—		$	(88	)
CCH Interest Rate Forward Start Derivatives	(7		)	—			(7		)
Liquefaction Supply Derivatives	121			(3		)	118
Liquefaction Supply Derivatives	(35		)	7			(28		)
LNG Trading Derivatives	109			(8		)	101
LNG Trading Derivatives	(62		)	8			(54		)
FX Derivatives	21			(10		)	11
FX Derivatives	(11		)	10			(1		)
As of December 31, 2018
CCH Interest Rate Derivatives	$	19		$	(1	)	$	18
Liquefaction Supply Derivatives	95			(36		)	59
Liquefaction Supply Derivatives	(121		)	20			(101		)
LNG Trading Derivatives	112			(88		)	24
LNG Trading Derivatives	(92		)	44			(48		)
FX Derivatives	30			(14		)	16
FX Derivatives	(2		)	1			(1		)

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 7—OTHER NON-CURRENT ASSETS

As of June 30, 2019 and December 31, 2018, other non-current assets, net consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Advances made to municipalities for water system enhancements	$	89	$	90
Advances and other asset conveyances to third parties to support LNG terminals	55		54
Tax-related payments and receivables	21		21
Equity method investments	124		94
Advances made under EPC and non-EPC contracts	11		14
Other	37		32
Total other non-current assets, net	$	337	$	305

Equity Method Investments

Our equity method investments consist of interests in privately-held companies. In 2017, we acquired an equity interest in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”). Midship Pipeline is currently constructing an approximately 200-mile natural gas pipeline project (the “Midship Project”) that connects production in the Anadarko Basin to Gulf Coast markets. Construction of the Midship Project commenced in the first quarter of 2019.

Subsequent to Midship Project obtaining its financing in the form of credit facilities, in conjunction with existing equity, Midship Holdings is able to finance its current activities without additional subordinated financial support. As a result of the total equity investment at risk being sufficient to finance its activities, Midship Holdings is no longer a variable interest entity. We continue to report Midship Holdings as an equity method investment due to our ability to exercise significant influence over the operating and financial policies of Midship Holdings through our non-controlling voting rights on its board of managers. Our investment in Midship Holdings was $117 million and $85 million at June 30, 2019 and December 31, 2018, respectively.

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 $3 million in each of the three months ended June 30, 2019 and 2018 and $7 million and $4 million in the six months ended June 30, 2019 and 2018, respectively, of other revenues and $2 million and $4 million of accounts receivable as of June 30, 2019 and December 31, 2018, respectively, for services provided to Midship Pipeline under these agreements. CCL has entered into a transportation precedent agreement and a negotiated rate agreement with Midship Pipeline to secure firm pipeline transportation capacity for a period of 10 years following commencement of the Midship Project. In May 2018, CCL issued a letter of credit to Midship Pipeline for drawings up to an aggregate maximum amount of $16 million. Midship Pipeline had not made any drawings on this letter of credit as of June 30, 2019.

NOTE 8—NON-CONTROLLING INTEREST

We own a 48.6% limited partner interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco LP and the public. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners. Cheniere Partners is accounted for as a variable interest entity. See Note 10—Variable Interest Entities of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2018 for further information.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—ACCRUED LIABILITIES

As of June 30, 2019 and December 31, 2018, accrued liabilities consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Interest costs and related debt fees	$	405	$	233
Accrued natural gas purchases	402		610
LNG terminals and related pipeline costs	630		125
Compensation and benefits	58		117
Accrued LNG inventory	3		14
Other accrued liabilities	74		70
Total accrued liabilities	$	1,572	$	1,169

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—DEBT

As of June 30, 2019 and December 31, 2018, our debt consisted of the following (in millions):



	June 30,			December 31,
	2019			2018
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			1,100
2016 CQP Credit Facilities	—			—
2019 CQP Credit Facilities	649			—
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250			1,250
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500			1,500
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500			1,500
CCH Credit Facility	6,138			5,156
CCH HoldCo II
11.0% Convertible Senior Secured Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,536			1,455
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”)	1,248			1,218
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”)	625			625
$1.25 billion Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	—			—
Unamortized premium, discount and debt issuance costs, net	(752		)	(775		)
Total long-term debt, net	29,944			28,179

Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	—			168
Cheniere Marketing trade finance facilities	—			71
Total current debt	—			239

Total debt, net	$	29,944		$	28,418

2019 Debt Issuances and Terminations

2016 CQP Credit Facilities

In May 2019, the remaining commitments under the 2016 CQP Credit Facilities were terminated. There were no write-offs of debt issuance costs associated with the termination of the 2016 CQP Credit Facilities.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

2019 CQP Credit Facilities

In May 2019, Cheniere Partners entered into the $1.5 billion 2019 CQP Credit Facilities, which consist of a $750 million term loan (“CQP Term Facility”) and a $750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the SPL Project and subject to a sublimit, for general corporate purposes. The CQP Revolving Facility is also available for the issuance of letters of credit.

Loans under the 2019 CQP Credit Facilities will accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50%, and the adjusted one-month LIBOR plus 1.0%), plus the applicable margin. Under the CQP Term Facility, the applicable margin for LIBOR loans is 1.50% per annum, and the applicable margin for base rate loans is 0.50% per annum, in each case with a 0.25% step-up beginning on May 29, 2022. Under the CQP Revolving Facility, the applicable margin for LIBOR loans is 1.25% to 2.125% per annum, and the applicable margin for base rate loans is 0.25% to 1.125% per annum, in each case depending on the then-current rating of Cheniere Partners. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three-month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

Cheniere Partners incurred $20 million of discounts and debt issuance costs in conjunction with the entry into the 2019 CQP Credit Facilities. Cheniere Partners pays a commitment fee equal to an annual rate of 30% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears.

The 2019 CQP Credit Facilities mature on May 29, 2024. The principal of any loans under the 2019 CQP Credit Facilities must be repaid in quarterly installments commencing on May 29, 2023 based on an amortization schedule. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2019 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 and one true-up per fiscal quarter as long as certain conditions are satisfied.

The 2019 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than SPL, Sabine Pass LNG-LP, LLC and certain subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2019 (in millions):



	SPL Working Capital Facility (1)		2019 CQP Credit Facilities		CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Original facility size	$	1,200	$	1,500	$	8,404	$	350	$	750
Incremental commitments	—		—		1,566		850		500
Less:
Outstanding balance	—		649		6,138		—		—
Commitments prepaid or terminated	—		—		3,832		—		—
Letters of credit issued	415		—		—		338		—
Available commitment	$	785	$	851	$	—	$	862	$	1,250

Interest rate on outstanding balance	LIBOR plus 1.75% or base rate plus 0.75%		(2)		LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75%		LIBOR plus 1.75% - 2.50% or base rate plus 0.75% - 1.50%
Weighted average interest rate of outstanding balance	n/a		3.92%		4.15%		n/a		n/a
Maturity date	December 31, 2020		May 29, 2024		June 30, 2024		June 29, 2023		December 23, 2022


(1)	The SPL Working Capital Facility was amended in May 2019 in connection with commercialization and financing of Train 6 of the SPL Project. All terms of the SPL Working Capital Facility substantially remained unchanged.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)


(2)	LIBOR plus 1.50% or base rate plus 0.50%, with a 0.25% step-up beginning on May 29, 2022 for the CQP Term Facility. LIBOR plus 1.25% to 2.125% or base rate plus 0.25% to 1.125%, depending on the then-current rating of Cheniere Partners for the CQP Revolving Facility.

Convertible Notes

Below is a summary of our convertible notes outstanding as of June 30, 2019 (in millions):



	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000		$	1,000		$	625
Debt component, net of discount and debt issuance costs	$	1,172		$	1,519		$	311
Equity component	$	210		$	—		$	194
Interest payment method	Paid-in-kind			Paid-in-kind (1)			Cash
Conversion by us (2)	—			(3)			(4)
Conversion by holders (2)	(5)			(6)			(7)
Conversion basis	Cash and/or stock			Stock			Cash and/or stock
Conversion value in excess of principal	$	—		$	—		$	—
Maturity date	May 28, 2021			May 13, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate (8)	8.4		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (9)	1.9 years			1.3 years			25.7 years


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


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

(3)

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


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


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


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

(7)

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


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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)


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

Restrictive Debt Covenants

As of June 30, 2019, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Interest Expense

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Interest cost on convertible notes:
Interest per contractual rate	$	64		$	58		$	126		$	116
Amortization of debt discount	9			8			19			16
Amortization of debt issuance costs	3			2			6			4
Total interest cost related to convertible notes	76			68			151			136
Interest cost on debt and finance leases excluding convertible notes	382			344			755			680
Total interest cost	458			412			906			816
Capitalized interest	(86		)	(196		)	(287		)	(384		)
Total interest expense, net	$	372		$	216		$	619		$	432

Fair Value Disclosures

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



	June 30, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	19,483	$	21,499	$	19,466	$	19,901
2037 SPL Senior Notes (2)	791		912		791		817
Credit facilities (3)	6,668		6,668		5,294		5,294
2021 Cheniere Convertible Unsecured Notes (2)	1,172		1,302		1,126		1,236
2025 CCH HoldCo II Convertible Senior Notes (2)	1,519		1,771		1,432		1,612
2045 Cheniere Convertible Senior Notes (4)	311		489		310		431

(1)

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


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

(3)

Includes SPL Working Capital Facility, 2016 CQP Credit Facilities, 2019 CQP Credit Facilities, CCH Credit Facility, CCH Working Capital Facility, Cheniere Revolving Credit Facility and Cheniere Marketing trade finance facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.


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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—LEASES

Our leased assets consist primarily of (1) LNG vessel time charters (“vessel charters”), (2) tug vessels, (3) office space and facilities and (4) land sites, all of which are classified as operating leases except for our tug vessels at the Corpus Christi LNG terminal, which are classified as finance leases.

ASC 842 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. As our leases generally do not provide an implicit rate, in order to calculate the lease liability, we discounted our expected future lease payments using our relevant subsidiary’s incremental borrowing rate at the later of January 1, 2019 or the commencement date of the lease. The incremental borrowing rate is an estimate of the rate of interest that a given subsidiary would have to pay to borrow on a collateralized basis over a similar term to that of the lease term.

Many of our leases contain renewal options exercisable at our sole discretion. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability only to the extent they are reasonably certain to be exercised, such as when necessary to satisfy obligations that existed at the execution of the lease or when the non-renewal would otherwise result in an economic penalty.

We have elected the practical expedient to omit leases with an initial term of 12 months or less (“short-term lease”) from recognition on the balance sheet. We recognize short-term lease payments on a straight-line basis over the lease term and variable payments under short-term leases in the period in which the obligation is incurred.

Certain of our leases contain non-lease components which are not separated from the lease components when calculating the right-of-use asset and lease liability per our use of the practical expedient to combine both components of an arrangement for all classes of leased assets.

Certain of our leases also contain variable payments, such as inflation, that are not included when calculating the right-of-use asset and lease liability unless the payments are in-substance fixed.

We recognize lease expense for operating leases on a straight-line basis over the lease term. We recognize lease expense for finance leases as the sum of the amortization of the right-of-use assets on a straight-line basis and the interest on lease liabilities using the effective interest method over the lease term.

The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):



	Consolidated Balance Sheet Location	June 30, 2019
Right-of-use assets—Operating	Operating lease assets, net	$	502
Right-of-use assets—Financing	Property, plant and equipment, net	58
Total right-of-use assets		$	560

Current operating lease liabilities	Current operating lease liabilities	$	292
Current finance lease liabilities	Other current liabilities	1
Non-current operating lease liabilities	Non-current operating lease liabilities	202
Non-current finance lease liabilities	Non-current finance lease liabilities	58
Total lease liabilities		$	553

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the classification and location of our lease cost on our Consolidated Statements of Operations (in millions):



	Consolidated Statement of Operations Location	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost (1)	Operating costs and expenses (2)	$	140	$	277
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	1		2
Interest on lease liabilities	Interest expense, net of capitalized interest	3		5
Total lease cost		$	144	$	284


(1)	Includes $46 million and $93 million of short-term lease costs and $8 million and $13 million of variable lease costs incurred during the three and six months ended June 30, 2019, respectively.


(2)	Presented in cost of sales, operating and maintenance expense or selling, general and administrative expense consistent with the nature of the asset under lease.

Future annual minimum lease payments for operating and finance leases as of June 30, 2019 are as follows (in millions):



Years Ending December 31,	Operating Leases (1)			Finance Leases
2019	$	192		$	5
2020	167			10
2021	39			10
2022	19			10
2023	19			10
Thereafter	166			146
Total lease payments	602			191
Less: Interest	(108		)	(132		)
Present value of lease liabilities	$	494		$	59


(1)	Does not include $1.6 billion of legally binding minimum lease payments for vessel charters which were executed as of June 30, 2019 but will commence primarily between 2020 and 2021 and have lease terms of up to seven years.

Future annual minimum lease payments for operating and capital leases as of December 31, 2018, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows (in millions):



Years Ending December 31,	Operating Leases (1)		Capital Leases (2)
2019 (3)	$	380	$	5
2020	184		5
2021	238		5
2022	264		5
2023	264		5
Thereafter	999		73
Total lease payments	2,329		98
Less: Interest	—		(39		)
Present value of lease liabilities	$	2,329	$	59


(1)	Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components. Also includes $79 million in payments for short-term leases and $1.6 billion in payments for LNG vessel charters which were previously executed but will commence primarily between 2020 and 2021.


(2)	Does not include payments for non-lease components of $98 million.


(3)	Does not include $43 million in aggregate payments we will receive from our LNG vessel subcharters.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the weighted-average remaining lease term (in years) and the weighted-average discount rate for our operating leases and finance leases:



	June 30, 2019
	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	7.2	19.3
Weighted-average discount rate (1)	5.4%	16.2%


(1)	The finance leases commenced prior to the adoption of ASC 842. In accordance with previous accounting guidance, the implied rate is based on the fair value of the underlying assets.

The following table includes other quantitative information for our operating and finance leases (in millions):



	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	174
Operating cash flows from finance leases	5
Financing cash flows from finance leases	—
Right-of-use assets obtained in exchange for new operating lease liabilities	106

LNG Vessel Subcharters

From time to time, we sublease certain LNG vessels under charter to third parties while retaining our existing obligation to the original lessor. We have elected the practical expedient for lessors to combine lease and non-lease components and since the lease component is the predominant component of each arrangement, these subleases are accounted for as operating leases. The subleases have lease terms of up to one year and many contain short-term renewal options exercisable at the discretion of the third party. As of June 30, 2019, we had $13 million in future minimum sublease payments to be received from LNG vessel subcharters, which will be recognized entirely within 2019. We recognize fixed sublease income on a straight-line basis over the lease term of the sublease while variable sublease income is recognized when earned. We recognized $31 million and $68 million of sublease income, including $5 million and $10 million of variable lease payments, during the three and six months ended June 30, 2019, respectively, in other revenues on our Consolidated Statements of Operations.

NOTE 12—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and six months ended June 30, 2019 and 2018 (in millions):



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019		2018
LNG revenues	$	2,080	$	1,516		$	4,147	$	3,668
Regasification revenues	67		65			133		130
Other revenues	21		13			36		23
Total revenues from customers	2,168		1,594			4,316		3,821
Net derivative gains (losses) (1)	93		(64		)	169		(60		)
Other revenues (2)	31		13			68		24
Total revenues	$	2,292	$	1,543		$	4,553	$	3,785


(1)	See Note 6—Derivative Instruments for additional information about our derivatives.


(2)	Includes revenues from LNG vessel subcharters. See Note 11—Leases for additional information about our subleases.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Contract Assets and Liabilities

The following table shows our contract assets, which we classify as other non-current assets, net on our Consolidated Balance Sheets (in millions):



	June 30,		December 31,
	2019		2018
Contract assets	$	8	$	—

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the six months ended June 30, 2019 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

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



	Six Months Ended June 30, 2019
Deferred revenues, beginning of period	$	139
Cash received but not yet recognized	136
Revenue recognized from prior period deferral	(139		)
Deferred revenues, end of period	$	136

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of June 30, 2019 and December 31, 2018:



	June 30, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	108.4	11	$	106.6	11
Regasification revenues	2.5		5	2.6		6
Total revenues	$	110.9		$	109.2


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

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


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

(2)

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes substantially all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 52% and 55% of our LNG revenues from contracts with a duration of over one year during the three months ended June 30, 2019 and 2018, respectively, and approximately 55% of our LNG revenues from contracts with a duration of over one year during

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

each of the six months ended June 30, 2019 and 2018, were related to variable consideration received from customers. During each of the three and six months ended June 30, 2019 and 2018, approximately 3% of our regasification revenues were related to variable consideration received from customers.

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

NOTE 13—INCOME TAXES

We recorded an income tax benefit of zero and $3 million during the three months ended June 30, 2019 and 2018, respectively, and an income tax provision of $3 million and $12 million during the six months ended June 30, 2019 and 2018, respectively. Changes in the income tax recorded between comparative periods are primarily attributable to changes in the income earned and tax transfer pricing applied to our U.K. integrated marketing function.

The effective tax rates during the three and six months ended June 30, 2019 and 2018 were lower than the 21% federal statutory rate during the 2019 and 2018 interim periods primarily as a result of maintaining a valuation allowance against our federal and state net deferred tax assets. Due to historical losses and other available evidence related to our ability to generate taxable income, we continue to maintain a valuation allowance against our federal and state net deferred tax assets at June 30, 2019.

NOTE 14—SHARE-BASED COMPENSATION

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

For the six months ended June 30, 2019, we granted 1.3 million restricted stock units and 0.2 million performance stock units at target performance under the 2011 Plan to certain employees. Restricted stock units are stock awards that vest over a service period of three years and entitle the holder to receive shares of our common stock upon vesting, subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with us prior to the lapse of the restrictions. Performance stock units provide for cliff vesting after a period of three years with payouts based on metrics dependent upon market and performance achieved over the period from January 1, 2019 through December 31, 2021 compared to pre-established performance targets. The settlement amounts of the awards are based on market and performance metrics which include cumulative distributable cash flow per share, and in certain circumstances, total shareholder return (“TSR”) of our common stock. Where applicable, the compensation for performance stock units is based on fair value assigned to the market metric of TSR using a Monte Carlo model upon grant, which remains constant through the vesting period, and a performance metric, which will vary due to changing estimates regarding the expected achievement of the performance metric of cumulative distributable cash flow per share. The number of shares that may be earned at the end of the vesting period ranges from 25% up to 300% of the target award amount if the threshold performance is met. Both restricted stock units and performance stock units will be settled in Cheniere common stock (on a one-for-one basis) and are classified as equity awards.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Share-based compensation costs, pre-tax:
Equity awards	$	32		$	22		$	61		$	39
Liability awards	2			15			5			32
Total share-based compensation	34			37			66			71
Capitalized share-based compensation	(1		)	(7		)	(5		)	(13		)
Total share-based compensation expense	$	33		$	30		$	61		$	58
Tax benefit associated with share-based compensation expense	$	—		$	—		$	1		$	2

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 15—NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

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

The following table reconciles basic and diluted weighted average common shares outstanding for the three and six months ended June 30, 2019 and 2018 (in millions, except per share data):



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019		2018
Weighted average common shares outstanding:
Basic	257.4			242.8			257.3		239.2
Dilutive unvested stock	—			—			1.3		2.5
Diluted	257.4			242.8			258.6		241.7

Basic net income (loss) per share attributable to common stockholders	$	(0.44	)	$	(0.07	)	$	0.11	$	1.42
Diluted net income (loss) per share attributable to common stockholders	$	(0.44	)	$	(0.07	)	$	0.11	$	1.40

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



	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Unvested stock (1)	3.8	5.2	3.8	2.6
Convertible notes (2)	17.8	17.2	17.8	17.2
Total potentially dilutive common shares	21.6	22.4	21.6	19.8


(1)	Does not include 0.6 million shares for each of the three and six months ended June 30, 2019 and 0.4 million shares for each of the three and six months ended June 30, 2018 of unvested stock because the performance conditions had not yet been satisfied as of June 30, 2019 and 2018, respectively.

(2)

Includes number of shares in aggregate issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes. There were no shares included in the computation of diluted net income (loss) per share for the 2025 CCH HoldCo II Convertible Senior Notes because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of June 30, 2019.

NOTE 16—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 June 30, 2019, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

Legal Proceedings

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 LNG Pipeline LLC and Tellurian Services LLC, formerly known as Parallax Services LLC, including claims for tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement, fraudulent transfer, conspiracy/aiding and abetting. Discovery in the Texas State Suit is ongoing. Trial is currently set for February 2020.

On February 15, 2019, we filed an action with CLNGT against Charif Souki, our former Chairman of the Board and Chief Executive Officer, styled, Cause No. 2019-11529, Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC v. Charif Souki, in the 55th District Court of Harris County, Texas, which asserts claims of breach of fiduciary duties, fraudulent transfer, tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement and conspiracy/aiding and abetting. On April 29, 2019, the court consolidated the Souki matter with the earlier filed pending case against Parallax, Tellurian and the individual defendants in the Texas State Suit.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

NOTE 17—CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers:



	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable from External Customers
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2019	2018	2019	2018	2019	2018
Customer A	17%	21%	18%	19%	11%	21%
Customer B	11%	17%	11%	14%	15%	14%
Customer C	11%	18%	12%	22%	15%	18%
Customer D	12%	16%	13%	11%	14%	*
Customer E	*	*	*	*	13%	*
Customer F	*	*	*	*	*	10%

* Less than 10%

NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Six Months Ended June 30,
	2019		2018
Cash paid during the period for interest on debt and finance leases, net of amounts capitalized	$	271	$	282
Cash paid for income taxes	20		4

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $958 million and $935 million as of June 30, 2019 and 2018, respectively.

See Note 11—Leases for our supplemental cash flow information related to our leases.


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 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 or pipelines;


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


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


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


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


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

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” 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, 2018. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than

as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction

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


•	Overview of Business


•	Overview of Significant Events


•	Liquidity and Capital Resources


•	Results of Operations


•	Off-Balance Sheet Arrangements


•	Summary of Critical Accounting Estimates


•	Recent Accounting Standards

Overview of Business

Cheniere, a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. Our vision is to provide clean, secure and affordable energy to the world, while responsibly delivering a reliable, competitive and integrated source of LNG, in a safe and rewarding work environment. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. As of June 30, 2019, we owned 100% of the general partner interest and 48.6% of the limited partner interest in Cheniere Partners. We also own and operate the Corpus Christi LNG terminal in Texas, which is wholly owned by us. The liquefaction of natural gas into LNG allows it to be shipped economically from the United States where natural gas is abundant and inexpensive to produce to our international customers in areas where natural gas demand and infrastructure exist.

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 in various stages of constructing and operating six 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. Trains 1 through 5 are operational and Train 6 is under construction. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG per Train. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines through a wholly owned subsidiary, CTPL.

We also own and operate a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal near Corpus Christi, Texas, and operate a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the liquefaction facilities, the “CCL Project”) through our wholly owned subsidiaries CCL and CCP, respectively. The CCL Project is being developed in stages with the first phase being three Trains (“Phase 1”), 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 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. Train 1 is operational, Train 2 is undergoing commissioning and Train 3 is under construction. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG per Train.

We have contracted approximately 85% of the expected aggregate nominal production capacity from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) on a long-term basis.

We have made an equity investment in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”). Midship Pipeline is constructing a pipeline (the “Midship Project”) with expected capacity of up to 1.44 million Dekatherms per day that will connect new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the Liquefaction Projects. Construction of the Midship Project commenced in the first quarter of 2019.

Overview of Significant Events

Our significant accomplishments since January 1, 2019 and through the filing date of this Form 10-Q include the following:

Strategic


•	In June 2019, our board of directors (the “Board”) appointed Michele A. Evans to serve as a member of the Board. Ms. Evans was also appointed to the Audit Committee and the Governance and Nominating Committee of the Board.


•	In May 2019, our wholly owned subsidiary CCL Stage III entered into an integrated production marketing transaction with Apache Corporation to purchase 140,000 MMBtu per day of natural gas, for a term of approximately 15 years, at a price based on international LNG indices, net of a fixed liquefaction fee and certain costs incurred by Cheniere.


•	In May 2019, the board of directors of the general partner of Cheniere Partners made a positive FID with respect to Train 6 of the SPL Project and issued a full notice to proceed with construction to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) in June 2019.


•	In March 2019, we received a positive Environmental Assessment from the FERC relating to Corpus Christi Stage 3 and anticipate receiving all remaining necessary regulatory approvals for the project by the end of 2019.


•	In February 2019, Midship Pipeline, in which we hold an indirect equity interest, issued full notice to proceed to construct the Midship natural gas pipeline and related compression and interconnect facilities following receipt of final Notice to Proceed from the FERC and obtaining financing to construct the Midship Project.

Operational


•	As of July 31, 2019, over 750 cumulative LNG cargoes have been produced, loaded and exported from the Liquefaction Projects.


•	In June 2019, first LNG production from Train 2 of the CCL Project occurred, and the first commissioning cargo from Train 2 was exported.


•	In February 2019 and March 2019, CCL and SPL achieved substantial completion of Train 1 of the CCL Project and Train 5 of the SPL Project, respectively, and commenced operating activities.

Financial


•	In June 2019, we announced a capital allocation framework which prioritizes investments in the growth of our liquefaction platform, improvement of consolidated leverage metrics, and a return of excess capital to shareholders under a three-year, $1.0 billion share repurchase program.


•	In June 2019, the date of first commercial delivery was reached under the 20-year SPAs with Endesa S.A. and PT Pertamina (Persero) relating to Train 1 of the CCL Project.

•

In June 2019, CCH and its subsidiaries, as guarantors, entered into a note purchase agreement (“CCH Note Purchase Agreement”) with Allianz Global Investors GmbH to issue an aggregate principal amount of $727 million of 4.80% Senior Secured Notes due 2039 (the “2039 CCH Senior Notes”), with closing and funding of the 2039 CCH Senior Notes conditional in part on the 2039 CCH Senior Notes receiving at least two investment grade ratings within 18 months of the date of the CCH Note Purchase Agreement.

•

In May 2019, Cheniere Partners entered into five-year, $1.5 billion credit facilities (the “2019 CQP Credit Facilities”), which consist of a $750 million delayed draw term loan (“CQP Term Facility”) and a $750 million revolving credit facility (“CQP Revolving Facility”), to fund a portion of the development and construction of Train 6, a third LNG berth and supporting infrastructure at the SPL Project.


•	In March 2019, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC relating to Train 4 of the SPL Project.

Liquidity and Capital Resources

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


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


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


•	CCH Group through operating cash flows from CCL and CCP, 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 our subsidiaries and distributions from our investment in Cheniere Partners.

The following table provides a summary of our liquidity position at June 30, 2019 and December 31, 2018 (in millions):



	June 30,		December 31,
	2019		2018
Cash and cash equivalents	$	2,279	$	981
Restricted cash designated for the following purposes:
SPL Project	596		756
Cheniere Partners and cash held by guarantor subsidiaries	—		785
CCL Project	279		289
Other	286		345
Available commitments under the following credit facilities:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	785		775
$1.5 billion 2019 CQP Credit Facilities	851		—
$2.8 billion Cheniere Partners’ Credit Facilities (“2016 CQP Credit Facilities”)	—		115
Amended and restated CCH Credit Facility (“CCH Credit Facility”)	—		982
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	862		716
$1.25 billion Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	1,250		1,250

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, 2018.

Cheniere

Convertible Notes

In November 2014, we issued an aggregate principal amount of $1.0 billion of Convertible Unsecured Notes due 2021 (the “2021 Cheniere Convertible Unsecured Notes”). The 2021 Cheniere Convertible Unsecured Notes are convertible at the option of the holder into our common stock at the then applicable conversion rate, provided that the closing price of our common stock is greater than or equal to the conversion price on the date of conversion. In March 2015, we issued $625 million aggregate

principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”). We have the right, at our option, at any time after March 15, 2020, to redeem all or any part of the 2045 Cheniere Convertible Senior Notes at a redemption price equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date. We have the option to satisfy the conversion obligation for the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes with cash, common stock or a combination thereof.

Cheniere Revolving Credit Facility

In December 2018, we amended and restated the Cheniere Revolving Credit Facility to increase total commitments under the Cheniere Revolving Credit Facility from $750 million to $1.25 billion. The Cheniere Revolving Credit Facility is intended to fund, through loans and letters of credit, equity capital contributions to CCH HoldCo II and its subsidiaries for the development of the CCL Project and, provided that certain conditions are met, for general corporate purposes.

The Cheniere Revolving Credit Facility matures on December 13, 2022 and contains representations, warranties and affirmative and negative covenants customary for companies like us 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) $200 million (the “Liquidity Covenant”).

From and after the time at which certain specified conditions are met (the “Trigger Point”), we will have increased flexibility under the Cheniere Revolving Credit Facility to, among other things, (1) make restricted payments and (2) raise incremental commitments. The Trigger Point will occur once (1) completion has occurred for each of Train 1 of the CCL Project (as defined in the CCH Indenture) and Train 5 of the SPL Project (as defined in SPL’s common terms agreement), which has occurred in February 2019 and March 2019, respectively; (2) the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit under the Cheniere Revolving Credit Facility is less than or equal to 10% of aggregate commitments under the Cheniere Revolving Credit Facility and (3) we elect on a go-forward basis to be governed by a non-consolidated leverage ratio covenant not to exceed 5.75:1.00 (the “Springing Leverage Covenant”), which following such election will apply at any time that the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit under the Cheniere Revolving Credit Facility is greater than 30% of aggregate commitments under the Cheniere Revolving Credit Facility. Following the Trigger Point, at any time that the Springing Leverage Covenant is in effect, the Liquidity Covenant will not apply.

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 and certain other subsidiaries).

Cash Receipts from Subsidiaries

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of June 30, 2019, we owned a 48.6% limited partner interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners. We are eligible to receive quarterly equity distributions from Cheniere Partners related to our ownership interests and our incentive distribution rights.

We also receive fees for providing management services to some of our subsidiaries. We received $36 million and $38 million in total service fees from these subsidiaries during each of the six months ended June 30, 2019 and 2018, respectively.

Share Repurchase Authorization

On June 3, 2019, we announced that our Board authorized a 3-year, $1.0 billion share repurchase program. During the three months ended June 30, 2019, we repurchased an aggregate of 44,600 shares of our common stock for $3 million, for a weighted average price per share of $68.30. As of June 30, 2019, we had $997 million of the share repurchase authorization available. Under the share repurchase program, repurchases can be made from time to time using a variety of methods, which may include open market purchases, privately negotiated transactions or otherwise, all in accordance with the rules of the SEC and other

applicable legal requirements. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by our management based on market conditions and other factors.

Cheniere Partners

CQP Senior Notes

The $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) and $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”) (collectively, the “CQP Senior Notes”) are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (the “CQP Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP. The CQP Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture (together with the CQP Base Indenture, the “2025 CQP Notes Indenture”) and the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”). The 2025 CQP Notes Indenture and the 2026 CQP Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2020 for the 2025 CQP Senior Notes and October 1, 2021 for the 2026 CQP Senior Notes, Cheniere Partners may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020 for the 2025 CQP Senior Notes and October 1, 2021 for the 2026 CQP Senior Notes, Cheniere Partners may redeem up to 35% of the aggregate principal amount of the CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes and 105.625% of the aggregate principal amount of the 2026 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. Cheniere Partners also may at any time on or after October 1, 2020 through the maturity date of October 1, 2025 for the 2025 CQP Senior Notes and October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.

The CQP Senior Notes are Cheniere Partners’ senior obligations, ranking equally in right of payment with Cheniere Partners’ other existing and future unsubordinated debt and senior to any of its future subordinated debt. After applying the proceeds from the 2026 CQP Senior Notes, the CQP Senior Notes became unsecured. In the event that the aggregate amount of Cheniere Partners’ secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on substantially all the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

2016 CQP Credit Facilities

In May 2019, the remaining commitments under the 2016 CQP Credit Facilities were terminated.

2019 CQP Credit Facilities

In May 2019, Cheniere Partners entered into the 2019 CQP Credit Facilities, which consist of a $750 million term loan (“CQP Term Facility”) and a $750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the SPL Project and subject to a sublimit, for general corporate purposes. The CQP Revolving Facility is also available for the issuance of letters of credit.

Loans under the 2019 CQP Credit Facilities will accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50%, and the adjusted one-month LIBOR plus 1.0%), plus the applicable margin. Under the CQP Term Facility, the applicable margin for LIBOR loans is 1.50% per annum, and the applicable margin for base rate loans is 0.50% per annum, in each case with a 0.25% step-up beginning on May 29, 2022. Under the CQP Revolving Facility, the applicable margin for LIBOR loans is 1.25% to 2.125% per annum, and the applicable margin for base rate loans is 0.25% to 1.125% per annum, in each case depending on the then-current rating of Cheniere Partners. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

Cheniere Partners pays a commitment fee equal to an annual rate of 30% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears.

Sabine Pass LNG Terminal

Liquefaction Facilities

We are in various stages of constructing and operating the SPL Project at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completion of Trains 1, 2, 3, 4 and 5 of the SPL Project and commenced operating activities in May 2016, September 2016, March 2017, October 2017 and March 2019, respectively. The following table summarizes the status of Train 6 of the SPL Project as of June 30, 2019:



		SPL Train 6
Overall project completion percentage		32.4%
Completion percentage of:
Engineering		74.1%
Procurement		48.2%
Subcontract work		30.7%
Construction		2.1%
Date of expected substantial completion		1H 2023

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


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


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


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

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

providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes SPL was authorized but unable to export during any portion of the initial 20-year export period of such order.

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

Customers

SPL has entered into fixed price SPAs generally with terms of at least 20 years (plus extension rights) with eight third parties for Trains 1 through 6 of the SPL Project, including an agreement anticipated to be assigned from Cheniere Marketing. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

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

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of June 30, 2019, SPL had secured up to approximately 3,437 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 for the engineering, procurement and construction of Trains 1 through 6 of the SPL Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 6 of the SPL Project is approximately $2.5 billion, including estimated costs for an optional third marine berth.

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, prior to inflation adjustments, 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, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all 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 Train 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the three months ended June 30, 2019 and 2018, SPL recorded $32 million and $7.5 million, respectively, and during the six months ended June 30, 2019 and 2018, SPL recorded $40 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 the SPL Project will be financed through project debt and borrowings, cash flows under the SPAs and equity contributions from Cheniere Partners. We believe that with the net proceeds of borrowings, available commitments under the SPL Working Capital Facility, 2019 CQP Credit Facilities and cash flows from operations, we will have adequate financial resources available to meet our currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the SPL Project. SPL began generating cash flows from operations from the SPL Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2, 3, 4 and 5 subsequently achieved substantial completion in September 2016, March 2017, October 2017 and March 2019, respectively. We realized offsets to LNG terminal costs of $74 million in the six months ended June 30, 2019, 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 Train 5 of the SPL Project during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three months ended June 30, 2019 and the three and six months ended June 30, 2018. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at June 30, 2019 and December 31, 2018 (in millions):



	June 30,		December 31,
	2019		2018
Senior notes (1)	$	16,250	$	16,250
Credit facilities outstanding balance (2)	649		—
Letters of credit issued (3)	415		425
Available commitments under credit facilities (3)	1,636		775
Total capital resources from borrowings and available commitments (4)	$	18,950	$	17,450

(1)

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


(2)	Includes outstanding balances under the SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2019 CQP Credit Facilities that may be used for general corporate purposes.


(3)	Consists of SPL Working Capital Facility and 2019 CQP Credit Facilities. Balance at December 31, 2018 did not include the letters of credit issued or available commitments under the terminated 2016 CQP Credit Facilities, which were 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, 2018.

SPL Senior Notes

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

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

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

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“SPL Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“SPL Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the SPL Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the SPL Project, request an incremental increase in commitments of up to an additional $390 million. As of June 30, 2019 and December 31, 2018, SPL had $785 million and $775 million of available commitments and $415 million and $425 million aggregate amount of issued letters of credit under the SPL Working Capital Facility, respectively. SPL did not have any amounts outstanding under the SPL Working Capital Facility as of both June 30, 2019 and December 31, 2018.

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

We are in various stages of constructing and operating the CCL Project at the Corpus Christi LNG terminal. We have received authorization from the FERC to site, construct and operate Stages 1 and 2 of the CCL Project. We achieved substantial completion of Train 1 of the CCL Project and commenced operating activities in February 2019. The following table summarizes the overall project status of the CCL Project as of June 30, 2019:



	CCL Stage 1		CCL Stage 2
Overall project completion percentage	99.5%		62.4%
Completion percentage of:
Engineering	100%		94.3%
Procurement	100%		92.5%
Subcontract work	96.4%		12.2%
Construction	99.2%		29.2%
Expected date of substantial completion	Train 2	3Q 2019	Train 3	2H 2021

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

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


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


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

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

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

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

Customers

CCL has entered into fixed price SPAs generally with terms of 20 years (plus extension rights) with nine third parties for Trains 1 through 3 of the CCL Project. Under these SPAs, the customers will purchase LNG from CCL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the CCL Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. The SPAs and contracted

volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for the applicable Train, as specified in each SPA.

In aggregate, the minimum fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to approximately $1.4 billion upon the date of first commercial delivery for Train 2 and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the CCL Project.

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

Natural Gas Transportation, Storage and Supply

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing variability in natural gas needs for the CCL Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. As of June 30, 2019, CCL had secured up to approximately 2,787 TBtu of natural gas feedstock through long-term natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.

Construction

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

The total contract prices of the EPC contract for Stage 1 and the EPC contract for Stage 2, which do not include the Corpus Christi Pipeline, are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through June 30, 2019. Total expected capital costs for Trains 1 through 3 are estimated to be between $11.0 billion and $12.0 billion before financing costs and between $15.0 billion and $16.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

Pipeline Facilities

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

Capital Resources

The CCH Group expects 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 from Cheniere. We realized offsets to LNG terminal costs of $128 million in the six months ended June 30, 2019 that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of Train 1 during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three months ended June 30, 2019. The following table provides a summary of the capital resources of the CCH Group from borrowings and available commitments for the CCL Project, excluding equity contributions from Cheniere, at June 30, 2019 and December 31, 2018 (in millions):



	June 30,		December 31,
	2019		2018
Senior notes (1)	$	4,250	$	4,250
11.0% Convertible Senior Secured Notes due 2025 (2)	1,000		1,000
Credit facilities outstanding balance (3)	6,138		5,324
Letters of credit issued (3)	338		316
Available commitments under credit facilities (3)	862		1,698
Total capital resources from borrowings and available commitments (4)	$	12,588	$	12,588


(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 5.125% Senior Secured Notes due 2027 (the “2027 CCH Senior Notes”) (collectively, the “CCH Senior Notes”).


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


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


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

For additional information regarding our debt agreements related to the CCL Project, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 12—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2018.

2025 CCH HoldCo II Convertible Senior Notes

In May 2015, CCH HoldCo II issued $1.0 billion aggregate principal amount of 11.0% Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes”) on a private placement basis. The 2025 CCH HoldCo II Convertible Senior Notes are convertible at the option of CCH HoldCo II or the holders, provided that various conditions are met. CCH HoldCo II is restricted from making distributions to Cheniere under agreements governing its indebtedness generally until, among other requirements, Trains 1 and 2 of the CCL Project are in commercial operation and a historical debt service coverage ratio and a projected fixed debt service coverage ratio of 1.20:1.00 are achieved.

In May 2018, the amended and restated note purchase agreement under which the 2025 CCH HoldCo II Convertible Senior Notes were issued was subsequently amended in connection with commercialization and financing of Train 3 of the CCL Project and to provide the note holders with certain prepayment rights related thereto consistent with those under the CCH Credit Facility. All terms of the 2025 CCH HoldCo II Convertible Senior Notes substantially remained unchanged.

CCH Senior Notes

The CCH Senior Notes are jointly and severally guaranteed by CCH’s subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (the “CCH Guarantors”). The indenture governing the CCH Senior Notes (the “CCH Indenture”) contains customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a

whole; or permit any CCH Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.

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

CCH Credit Facility

In May 2018, CCH amended and restated the CCH Credit Facility to increase total commitments under the CCH Credit Facility from $4.6 billion to $6.1 billion. The obligations of CCH under the CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in CCH. As of June 30, 2019 and December 31, 2018, CCH had zero and $1.0 billion of available commitments and $6.1 billion and $5.2 billion of loans outstanding under the CCH Credit Facility, respectively.

The CCH Credit Facility matures on June 30, 2024, with principal payments due quarterly commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following the completion of the CCL Project as defined in the common terms agreement and (2) a set date determined by reference to the date under which a certain LNG buyer linked to the last Train of the CCL Project to become operational is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the completion of Trains 1 through 3 and designed to achieve a minimum projected fixed debt service coverage ratio of 1.50:1.

Under the CCH Credit Facility, CCH is required to hedge not less than 65% of the variable interest rate exposure of its senior secured debt. CCH is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of Trains 1 through 3 of the CCL Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.

CCH Working Capital Facility

In June 2018, CCH amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility from $350 million to $1.2 billion. The CCH Working Capital Facility is intended to be used for loans to CCH (“CCH Working Capital Loans”) and the issuance of letters of credit on behalf of CCH for certain working capital requirements related to developing and placing into operations the CCL Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the CCH Guarantors. CCH may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility. As of June 30, 2019 and December 31, 2018, CCH had $862 million and $716 million of available commitments, $338 million and $316 million aggregate amount of issued letters of credit and zero and $168 million of loans outstanding under the CCH Working Capital Facility, respectively.

The CCH Working Capital Facility matures on June 29, 2023, and CCH may prepay the CCH Working Capital 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 is required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

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

CCH Note Purchase Agreement

In June 2019, CCH entered into the CCH Note Purchase Agreement with Allianz Global Investors GmbH to issue an aggregate principal amount of $727 million of the 2039 CCH Senior Notes, which will be jointly and severally guaranteed by the CCH Guarantors. The conditions to closing and issuance of the 2039 CCH Senior Notes include the receipt of at least two investment grade ratings for the 2039 CCH Senior Notes, in addition to other customary conditions to closing. Pursuant to the CCH Note Purchase Agreement, CCH has up to 12 months, subject to a six-month extension at CCH’s option, to satisfy the conditions to closing and issuance. The net proceeds from the 2039 CCH Senior Notes will be used by CCH to repay a portion of its outstanding term loans and pay fees, costs and expenses incurred in connection with the repayment of such outstanding term loans and/or the transactions contemplated in the CCH Note Purchase Agreement.

Restrictive Debt Covenants

As of June 30, 2019, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Marketing

We market and sell LNG produced by the Liquefaction Projects 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 Liquefaction Projects but supplemented by volume procured from other locations worldwide, as needed. As of June 30, 2019, we have sold or have options to sell approximately 5,066 TBtu of LNG to be delivered to customers between 2019 and 2045, excluding volume for an agreement anticipated to be assigned to SPL in the future. The cargoes have been sold either on a free on board (“FOB”) basis (delivered to the customer at the Sabine Pass LNG terminal or the Corpus Christi LNG terminal) or a delivered at terminal (“DAT”) basis (delivered to the customer at their LNG receiving terminal). We have chartered LNG vessels to be utilized in DAT transactions. In addition, we have entered into a long-term agreement to sell LNG cargoes on a DAT basis that is conditioned upon the buyer achieving certain milestones.

Cheniere Marketing entered into uncommitted trade finance facilities with available commitments of $420 million as of June 30, 2019, 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 June 30, 2019 and December 31, 2018, Cheniere Marketing had $10 million and $31 million, respectively, in standby letters of credit and guarantees outstanding under the finance facilities. As of June 30, 2019 and December 31, 2018, Cheniere Marketing had zero and $71 million, respectively, in loans outstanding under the finance facilities. Cheniere Marketing pays interest or fees on utilized commitments.

Corporate and Other Activities

We are required to maintain corporate and general and administrative functions to serve our business activities described above. We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require acceptable commercial and financing arrangements before we make an FID. We have made an equity investment in Midship Pipeline, which is constructing 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 Liquefaction Projects.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the six months ended June 30, 2019 and 2018 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Six Months Ended June 30,
	2019			2018
Operating cash flows	$	760		$	982
Investing cash flows	(1,542		)	(1,492		)
Financing cash flows	1,066			1,168

Net increase in cash, cash equivalents and restricted cash	284			658
Cash, cash equivalents and restricted cash—beginning of period	3,156			2,613
Cash, cash equivalents and restricted cash—end of period	$	3,440		$	3,271

Operating Cash Flows

Our operating cash net inflows during the six months ended June 30, 2019 and 2018 were $760 million and $982 million, respectively. The $222 million decrease in operating cash inflows in 2019 compared to 2018 was primarily related to increased operating costs and expenses, partially offset by increased cash receipts from the sale of LNG cargoes, as a result of the additional Trains that were operating at the Liquefaction Projects in 2019. In addition to Trains 1 through 4 of the SPL Project that were operational during both the six months ended June 30, 2019 and 2018, Train 5 of the SPL Project and Train 1 of the CCL Project were operational for approximately four months during the six months ended June 30, 2019.

Investing Cash Flows

Investing cash net outflows during the six months ended June 30, 2019 and 2018 were $1,542 million and $1,492 million, respectively, and were primarily used to fund the construction costs for the Liquefaction Projects. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, we invested $34 million in Midship Holdings, our equity method investment, during the six months ended June 30, 2019.

Financing Cash Flows

Financing cash net inflows during the six months ended June 30, 2019 were $1,066 million, primarily as a result of:


•	$982 million of borrowings under the CCH Credit Facility;


•	$649 million of borrowings under the 2019 CQP Credit Facilities;


•	$390 million of borrowings and $558 million in repayments under the CCH Working Capital Facility;


•	$290 million of distributions to non-controlling interest by Cheniere Partners;


•	$72 million of net repayments related to our Cheniere Marketing trade financing facilities;


•	$20 million of debt issuance costs primarily related to up-front fees paid upon the closing of the 2019 CQP Credit Facilities; and


•	$14 million paid for tax withholdings for share-based compensation.

Financing cash net inflows during the six months ended June 30, 2018 were $1.2 billion, primarily as a result of:


•	$1.7 billion of borrowings and $281 million in repayments under the CCH Credit Facility;


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


•	$123 million of net borrowings related to our Cheniere Marketing trade financing facilities;


•	$46 million of debt issuance costs related to up-front fees paid for the amendment and restatement of the CCH Credit Facility and the CCH Working Capital Facility;


•	$8 million in debt extinguishment costs;


•	$288 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; and


•	$8 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 Liquefaction Projects, which were recognized on our Consolidated Financial Statements during the three and six months ended June 30, 2019:



	Three Months Ended June 30, 2019				Six Months Ended June 30, 2019
(in TBtu)	Operational		Commissioning		Operational		Commissioning
Volumes loaded during the current period	361		3		645		28
Volumes loaded during the prior period but recognized during the current period	27		—		25		3
Less: volumes loaded during the current period and in transit at the end of the period	(36	)	(3	)	(36	)	(3	)
Total volumes recognized in the current period	352		—		634		28

Our consolidated net loss attributable to common stockholders was $114 million, or $0.44 per share (basic and diluted), in the three months ended June 30, 2019, compared to net loss attributable to common stockholders of $18 million, or $0.07 per share (basic and diluted), in the three months ended June 30, 2018. This $96 million increase in net loss attributable to common stockholders in 2019 was primarily attributable to decreased margins per MMBtu due to decreased pricing on LNG, increased interest expense, net of amounts capitalized, increased operating and maintenance expense, increased derivative loss, net, and increased depreciation and amortization expense, which were partially offset by decreased net income attributable to non-controlling interest.

Our consolidated net income attributable to common stockholders was $27 million, or $0.11 per share (basic and diluted), in the six months ended June 30, 2019, compared to net income attributable to common stockholders of $339 million, or $1.42 per share—basic and $1.40 per share—diluted, in the six months ended June 30, 2018. This $312 million decrease in net income attributable to common stockholders in 2019 was primarily attributable to decreased margins per MMBtu due to decreased pricing on LNG, increased operating and maintenance expense, increased derivative loss, net, increased interest expense, net of amounts capitalized and increased depreciation and amortization expense, which were partially offset by decreased net income attributable to non-controlling interest.

We enter into derivative instruments to manage our exposure to (1) changing interest rates, (2) commodity-related marketing and price risks and (3) foreign exchange volatility. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions economically hedged receive accrual accounting treatment, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.

Revenues



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019		2018		Change		2019		2018		Change
LNG revenues	$	2,173	$	1,442	$	731	$	4,316	$	3,608	$	708
Regasification revenues	67		65		2		133		130		3
Other revenues	52		36		16		104		47		57
Total revenues	$	2,292	$	1,543	$	749	$	4,553	$	3,785	$	768

We begin recognizing LNG revenues from the Liquefaction Projects following the substantial completion and the commencement of operating activities of the respective Trains. In addition to Trains 1 through 4 of the SPL Project that were operational during both the six months ended June 30, 2019 and 2018, Train 5 of the SPL Project and Train 1 of the CCL Project

were operational for approximately four months during the six months ended June 30, 2019. The additional revenue from the increased volume of LNG sold following the achievement of substantial completion of these Trains in the three and six months ended June 30, 2019 from the comparable periods in 2018 was offset by decreased revenues per MMBtu, which was primarily affected by sales made at current market prices by our integrated marketing function. We expect our LNG revenues to increase in the future upon Train 6 of the SPL Project and Trains 2 and 3 of the CCL Project becoming operational.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. We realized offsets to LNG terminal costs of $202 million corresponding to 28 TBtu of LNG in the six months ended June 30, 2019 that related to the sale of commissioning cargoes from the Liquefaction Projects. We did not realize any offsets to LNG terminal costs in the three months ended June 30, 2019 and the three and six months ended June 30, 2018.

Also included in LNG revenues are gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery and the sale of natural gas procured for the liquefaction process. During the three months ended June 30, 2019 and 2018, we realized $183 million of gains and $34 million of losses, respectively, from these transactions and other revenues. During the six months ended June 30, 2019 and 2018, we realized $317 million and $8 million, respectively, of gains from these transactions and other revenues.

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019		2018
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	$	1,393	$	1,118		$	2,910	$	2,111
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	566		282			905		1,303
LNG procured from third parties	31		76			184		186
Other revenues and derivative gains (losses)	183		(34		)	317		8
Total LNG revenues	$	2,173	$	1,442		$	4,316	$	3,608

Volumes sold as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	241		189			477		354
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	111		41			157		149
LNG procured from third parties	5		10			23		21
Total volumes sold as LNG revenues	357		240			657		524

(1) Long-term agreements include agreements with tenure of 12 months or more.

Operating costs and expenses



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019		2018		Change		2019		2018		Change
Cost of sales	$	1,277	$	873	$	404	$	2,491	$	2,051	$	440
Operating and maintenance expense	295		147		148		516		287		229
Development expense	3		3		—		4		4		—
Selling, general and administrative expense	77		73		4		150		140		10
Depreciation and amortization expense	204		111		93		348		220		128
Impairment expense and loss on disposal of assets	4		—		4		6		—		6
Total operating costs and expenses	$	1,860	$	1,207	$	653	$	3,515	$	2,702	$	813

Our total operating costs and expenses increased during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018, primarily as a result of the increase in operating Trains between each of the periods and increased third-party service and maintenance costs from additional maintenance and related activities at the SPL Project.

Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Projects, to the extent those costs are not utilized for the commissioning process. Cost of sales increased during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018 due to increased volumes of natural gas feedstock for our LNG sales as a result of substantial completion of Train 5 of the SPL Project and Train 1 of the CCL Project, partially offset by decreased pricing of natural gas feedstock, and increased vessel charter costs. Partially offsetting the increase in cost of natural gas feedstock was an increase in fair value of the derivatives associated with hedges to secure natural gas feedstock for the Liquefaction Projects due to a favorable shift in the long-term forward prices. Cost of sales also includes port and canal fees, variable transportation and storage costs, costs associated with a portion of derivative instruments that settle through physical delivery and the sale of natural gas procured for the liquefaction process and other costs to convert natural gas into LNG.

Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Projects. The increase in operating and maintenance expense during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018 was primarily related to: (1) increased natural gas transportation and storage capacity demand charges from operating Train 5 of the SPL Project and Train 1 of the CCL Project following the respective substantial completions, (2) increased cost of maintenance and related activities at the SPL Project, (3) increased payroll and benefit costs from increased headcount to operate Train 5 of the SPL Project and Train 1 of the CCL Project and (4) increased TUA reservation charges paid to Total from payments under the partial TUA assignment agreement. Operating and maintenance expense also includes insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018 as a result of commencing operations of Train 5 of the SPL Project and Train 1 of the CCL Project in March 2019 and February 2019, respectively, and completing construction of the Corpus Christi Pipeline in the second quarter of 2018, as the related assets began depreciating upon reaching substantial completion.

We expect our operating costs and expenses to generally increase in the future upon Train 6 of the SPL Project and Trains 2 and 3 of the CCL Project achieving substantial completion, although certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.

Other expense (income)



	Three Months Ended June 30,									Six Months Ended June 30,
(in millions)	2019			2018			Change			2019			2018			Change
Interest expense, net of capitalized interest	$	372		$	216		$	156		$	619		$	432		$	187
Loss on modification or extinguishment of debt	—			15			(15		)	—			15			(15		)
Derivative loss (gain), net	74			(32		)	106			109			(109		)	218
Other income	(16		)	(10		)	(6		)	(32		)	(17		)	(15		)
Total other expense	$	430		$	189		$	241		$	696		$	321		$	375

Interest expense, net of capitalized interest, increased during the three and six months ended June 30, 2019 compared to the three and six months ended June 30, 2018, as a result of increased outstanding debt (before unamortized premium, discount and debt issuance costs, net) from $27.6 billion as of June 30, 2018 to $30.7 billion as of June 30, 2019, primarily due to increased borrowings under the CCH Credit Facility, as well as a decrease in the portion of total interest costs that could be capitalized as additional Trains of the Liquefaction Projects completed construction between the periods. For the three months ended June 30, 2019 and 2018, we incurred $458 million and $412 million of total interest cost, respectively, of which we capitalized $86 million and $196 million, respectively, which was primarily related to the construction of the Liquefaction Projects. For the six months ended June 30, 2019 and 2018, we incurred $906 million and $816 million of total interest cost, respectively, of which we capitalized $287 million and $384 million, respectively, which was primarily related to the construction of the Liquefaction Projects.

Loss on modification or extinguishment of debt during the three and six months ended June 30, 2019 decreased from the comparable periods in 2018. Loss on modification or extinguishment of debt recognized in 2018 was attributable to $15 million

of debt modification and extinguishment costs relating to the incurrence of third-party fees and write-off of unamortized debt issuance costs as a result of the amendment and restatement of the CCH Credit Facility.

Derivative loss, net increased during the three and six months ended June 30, 2019 compared to the three and six months ended June 30, 2018, primarily due to an unfavorable shift in the long-term forward LIBOR curve between the periods.

Other income increased during the three and six months ended June 30, 2019 as compared to the three and six months ended June 30, 2018, primarily due to an increase in interest income earned on our cash and cash equivalents.

Income tax benefit (provision)



	Three Months Ended June 30,								Six Months Ended June 30,
(in millions)	2019			2018			Change		2019			2018			Change
Income before income taxes and non-controlling interest	$	2		$	147		(145	)	$	342		$	762		$	(420	)
Income tax benefit (provision)	—			3			(3	)	(3		)	(12		)	9

Effective tax rate	—		%	2.0		%			0.9		%	1.6		%

Income tax benefit decreased $3 million during the three months ended June 30, 2019 and income tax provision decreased $9 million during the six months ended June 30, 2019, respectively, from the comparable periods in 2018 primarily attributable to changes in the income earned and tax transfer pricing applied to our U.K. integrated marketing function. The effective tax rates during each of the three and six months ended June 30, 2019 and 2018 were lower than the 21% federal statutory rate, primarily as a result of maintaining a valuation allowance against our federal and state net deferred tax assets. Given our current and anticipated future earnings, we believe that there is a reasonable possibility that within approximately 6 to 18 months, sufficient positive evidence may become available to allow us to conclude that a significant portion of the valuation allowance will no longer be needed. The release of the valuation allowance would result in the recognition of certain deferred tax assets and an income tax benefit in the period the release is recorded. However, the precise timing and amount of the valuation allowance release are subject to change on the basis of the level of profitability that we are able to achieve.

Net income attributable to non-controlling interest



	Three Months Ended June 30,							Six Months Ended June 30,
(in millions)	2019		2018		Change			2019		2018		Change
Net income attributable to non-controlling interest	$	116	$	168	$	(52	)	$	312	$	411	$	(99	)

Net income attributable to non-controlling interest decreased during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018 due to the decrease of non-controlling interest as a result of our merger with Cheniere Holdings in September 2018, in which all publicly-held shares of Cheniere Holdings were canceled and the non-controlling interest in Cheniere Holdings was reduced to zero. Net income attributable to non-controlling interest also decreased during the three months ended June 30, 2019 from the three months ended June 30, 2018 due to the decrease in consolidated net income recognized by Cheniere Partners in which the non-controlling interests are held. The consolidated net income recognized by Cheniere Partners decreased from $281 million in the three months ended June 30, 2018 to $232 million in the three months ended June 30, 2019 due an increase in interest expense, net of capitalized interest, as a result of the decrease in the portion of total interest costs that could be capitalized as an additional Train of the SPL Project completed construction between the periods.

Off-Balance Sheet Arrangements

As of June 30, 2019, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the year ended December 31, 2018.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation 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 for the commissioning and operation of the SPL Project, the CCL Project and potential future development of Corpus Christi Stage 3 (“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):



	June 30, 2019				December 31, 2018
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
Liquefaction Supply Derivatives	$	90	$	127	$	(42	)	$	6
LNG Trading Derivatives	47		39		(24		)	9

Interest Rate Risk

We are exposed to interest rate risk primarily when we incur debt related to project financing. Interest rate risk is managed in part by replacing outstanding floating-rate debt with fixed-rate debt with varying maturities. CCH has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the CCH Credit Facility (“CCH Interest Rate Derivatives”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH (“CCH Interest Rate Forward Start Derivatives”). In order to test the sensitivity of the fair value of the CCH Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward one-month LIBOR curve across the remaining terms of the CCH Interest Rate Derivatives and CCH Interest Rate Forward Start Derivatives as follows (in millions):



	June 30, 2019					December 31, 2018
	Fair Value			Change in Fair Value		Fair Value		Change in Fair Value
CCH Interest Rate Derivatives	$	(88	)	$	25	$	18	$	37
CCH Interest Rate Forward Start Derivatives	(7		)	20		—		—

Foreign Currency Exchange Risk

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



	June 30, 2019				December 31, 2018
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
FX Derivatives	$	10	$	1	$	15	$	1

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


ITEM 4.	CONTROLS AND PROCEDURES

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

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. Other than discussed below, there have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the year ended December 31, 2018.

In February 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal. These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service. We continue to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation will have a material adverse impact on our financial results or operations.


ITEM 1A.	RISK FACTORS

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2018.


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

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended June 30, 2019:



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	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (3)
April 1 - 30, 2019	425	$64.70	—	—
May 1 - 31, 2019	13,973	$67.87	—	—
June 1 - 30, 2019	45,266	$68.24	44,600	$996,954,020


(1)	Includes 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 the shares.


(3)	On June 3, 2019, we announced that our Board authorized a 3-year, $1 billion share repurchase program.


ITEM 6.	EXHIBITS



Exhibit No.		Description
10.1		Credit and Guaranty Agreement, dated May 29, 2019, among Cheniere Partners, as Borrower, certain subsidiaries of Cheniere Partners, as Subsidiary Guarantors, the lenders from time to time party thereto, Natixis, Société Générale, The Bank of Nova Scotia, Wells Fargo Bank, as Issuing Banks, MUFG Bank, LTD as Administrative Agent and Sole Coordinating Lead Arranger, and certain arrangers and other participants (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on June 3, 2019)
10.2*		Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated September 4, 2015, as amended by (a) Third Omnibus Amendment, dated as of May 23, 2018; (b) Fourth Omnibus Amendment, dated as of September 17, 2018; and (c) Fifth Omnibus Amendment, Consent and Waiver, dated as of May 29, 2019, among SPL, as Borrower, The Bank of Nova Scotia, as Senior Issuing Bank and Senior Facility Agent, ABN Amro Capital USA LLC, HSBC Bank USA, National Association and ING Capital LLC, as Senior Issuing Banks, Société Générale, as Swing Line Lender and Common Security Trustee, and the senior lenders party thereto from time to time
10.3*		Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00051 Fencing Scope Modifications, dated April 19, 2019 and (ii) Change Order CO-00052 West Jetty Manual Gas Sampler, dated April 19, 2019 (Portions of this exhibit have been omitted.)
10.4*		Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-000013 Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD), dated May 2, 2019, (ii) the Change Order CO-00014 Tank B Jump-over Tie-In Interface - Long Lead Items, dated May 2, 2019 and (iii) the Change Order CO-00015 Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD) Q1_2019, dated June 4, 2019 (Portions of this exhibit have been omitted.)
10.5*		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated December 20, 2012, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: the Change Order CO-00045 Letter of Credit Reduction and Extension, dated June 7, 2019
10.6*		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: the Change Order CO-00001 Modifications to Insurance Language Change Order, dated June 3, 2019
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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*		Inline XBRL Taxonomy Extension Schema Document
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*		Inline 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:	August 7, 2019	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:	August 7, 2019	By:	/s/ Leonard E. Travis
			Leonard E. Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)