10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2018

OR

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

 For the transition period fromto

Sabine Pass Liquefaction, LLC

(Exact name of registrant as specified in its charter)

Delaware	333-192373	27-3235920
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer Identification No.)
700 Milam Street, Suite 1900 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 375-5000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes x    No ¨

Note: As of January 1, 2018, the registrant is a voluntary filer not subject to the filing requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934. However, the registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes x No ¨

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

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

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

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

Indicate the number of shares outstanding of the issuer’s classes of common stock, as of the latest practicable date:    Not applicable

SABINE PASS LIQUEFACTION, LLC

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Financial Statements	2
	Balance Sheets	2
	Statements of Operations	3
	Statement of Member’s Equity (Deficit)	4
	Statements of Cash Flows	5
	Notes to Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	29
Item 4.	Controls and Procedures	29
Part II. Other Information
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 6.	Exhibits	31
	Signatures	32

i

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
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

Company Abbreviations

Cheniere	Cheniere Energy, Inc.
Cheniere Investments	Cheniere Energy Investments, LLC
Cheniere Marketing	Cheniere Marketing International LLP
Cheniere Partners	Cheniere Energy Partners, L.P.
Cheniere Terminals	Cheniere LNG Terminals, LLC
CTPL	Cheniere Creole Trail Pipeline, L.P.
SPLNG	Sabine Pass LNG, L.P.

Unless the context requires otherwise, references to “SPL,” the “Company,” “we,” “us” and “our” refer to Sabine Pass Liquefaction, LLC.

1

PART I. FINANCIAL INFORMATION 

ITEM 1. FINANCIAL STATEMENTS

SABINE PASS LIQUEFACTION, LLC

BALANCE SHEETS

(in millions)

	March 31,		December 31,
	2018		2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	561		544
Accounts and other receivables	238		189
Accounts receivable—affiliate	114		163
Advances to affiliate	91		26
Inventory	72		85
Other current assets	38		54
Other current assets—affiliate	22		21
Total current assets	1,136		1,082
Property, plant and equipment, net	12,933		12,920
Debt issuance costs, net	16		18
Non-current derivative assets	9		17
Other non-current assets, net	159		169
Total assets	$	14,253	$	14,206
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	7	$	8
Accrued liabilities	451		606
Due to affiliates	32		66
Deferred revenue	69		84
Derivative liabilities	4		—
Total current liabilities	563		764
Long-term debt, net	13,483		13,477
Non-current derivative liabilities	3		3
Member’s equity (deficit)	204		(38		)
Total liabilities and member’s equity (deficit)	$	14,253	$	14,206

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

2

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF OPERATIONS

(in millions)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Revenues
LNG revenues	$	1,015		$	492
LNG revenues—affiliate	503			331
Total revenues	1,518			823
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	838			510
Cost of sales—affiliate	8			4
Operating and maintenance expense	78			39
Operating and maintenance expense—affiliate	103			59
General and administrative expense	2			2
General and administrative expense—affiliate	12			17
Depreciation and amortization expense	86			47
Total operating costs and expenses	1,127			678
Income from operations	391			145
Other income (expense)
Interest expense, net of capitalized interest	(151		)	(105		)
Loss on early extinguishment of debt	—			(42		)
Derivative loss, net	—			(2		)
Other income	2			—
Total other expense	(149		)	(149		)
Net income (loss)	$	242		$	(4	)

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

3

SABINE PASS LIQUEFACTION, LLC

STATEMENT OF MEMBER’S EQUITY (DEFICIT)

(in millions)

(unaudited)

	Sabine Pass LNG-LP, LLC			Total Member’s Equity (Deficit)
Balance at December 31, 2017	$	(38	)	$	(38	)
Net income	242			242
Balance at March 31, 2018	$	204		$	204

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

4

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities
Net income (loss)	$	242		$	(4	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	86			47
Amortization of debt issuance costs, deferred commitment fees, premium and discount	5			5
Loss on early extinguishment of debt	—			42
Total losses on derivatives, net	50			41
Net cash used for settlement of derivative instruments	(5		)	(11		)
Changes in operating assets and liabilities:
Accounts and other receivables	(49		)	(11		)
Accounts receivable—affiliate	48			56
Advances to affiliate	(60		)	(40		)
Inventory	12			18
Accounts payable and accrued liabilities	(94		)	(39		)
Due to affiliates	(17		)	2
Deferred revenue	(15		)	(10		)
Deferred revenue—affiliate	—			19
Other, net	3			3
Other, net—affiliate	—			(2		)
Net cash provided by operating activities	206			116
Cash flows from investing activities
Property, plant and equipment, net	(189		)	(528		)
Net cash used in investing activities	(189		)	(528		)
Cash flows from financing activities
Proceeds from issuances of debt	—			2,314
Repayments of debt	—			(703		)
Debt issuance and deferred financing costs	—			(26		)
Net cash provided by financing activities	—			1,585
Net increase in cash, cash equivalents and restricted cash	17			1,173
Cash, cash equivalents and restricted cash—beginning of period	544			358
Cash, cash equivalents and restricted cash—end of period	$	561		$	1,531

Balances per Balance Sheet:

	March 31, 2018
Cash and cash equivalents	$	—
Restricted cash	561
Total cash, cash equivalents and restricted cash	$	561

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

5

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We were formed by Cheniere Partners to own, develop and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities owned and operated by SPLNG. Our Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal, which is located on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place.

Basis of Presentation

The accompanying unaudited Financial Statements of SPL 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 Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

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

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

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

NOTE 2—RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. As of March 31, 2018 and December 31, 2017, restricted cash consisted of the following (in millions):

	March 31,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	561	$	544

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

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

	March 31,		December 31,
	2018		2017
Trade receivable	$	232	$	185
Other accounts receivable	6		4
Total accounts and other receivables	$	238	$	189

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.

6

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 4—INVENTORY

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

	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	14		26
Materials and other	42		42
Total inventory	$	72	$	85

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	9,945		$	9,963
LNG terminal construction-in-process	3,397			3,283
Accumulated depreciation	(414		)	(330		)
Total LNG terminal costs, net	12,928			12,916
Fixed assets
Fixed assets	11			10
Accumulated depreciation	(6		)	(6		)
Total fixed assets, net	5			4
Property, plant and equipment, net	$	12,933		$	12,920

Depreciation expense was $84 million and $45 million during the three months ended March 31, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $124 million in the three months ended March 31, 2017 that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three months ended March 31, 2018.

NOTE 6—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). We had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of our credit facilities (“Interest Rate Derivatives”), and these Interest Rate Derivatives were settled in March 2017.

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 Statements of Operations to the extent not utilized for the commissioning process.

7

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Fair Value Measurements as of
	March 31, 2018								December 31, 2017
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset	$	—	$	—	$	10	$	10	$	2	$	10	$	43	$	55

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

We value our Liquefaction Supply Derivatives using market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available and other relevant data.

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

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

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

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$10	Market approach incorporating present value techniques	Basis Spread	$(0.515) - $0.095

8

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

Interest Rate Derivatives

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

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

	Three Months Ended March 31,
	2018		2017
Interest Rate Derivatives loss	$	—	$	(2	)

Liquefaction Supply Derivatives

We had secured up to approximately 2,179TBtu and 2,214TBtu of natural gas feedstock through natural gas supply contracts as of March 31, 2018 and December 31, 2017, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,521TBtu and 1,520TBtu as of March 31, 2018 and December 31, 2017, respectively.

9

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Fair Value Measurements as of (1)
Balance Sheet Location	March 31, 2018			December 31, 2017
Other current assets	$	8		$	41
Non-current derivative assets	9			17
Total derivative assets	17			58
Derivative liabilities	(4		)	—
Non-current derivative liabilities	(3		)	(3		)
Total derivative liabilities	(7		)	(3		)
Derivative asset, net	$	10		$	55

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

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

		Three Months Ended March 31,
	Statement of Operations Location (1)	2018		2017
Liquefaction Supply Derivatives loss (2)	Cost of sales	$	50	$	39

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

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

Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our 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 Balance Sheets			Net Amounts Presented in the Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2018
Liquefaction Supply Derivatives	$	25		$	(8	)	$	17
Liquefaction Supply Derivatives	(9		)	2			(7		)
As of December 31, 2017
Liquefaction Supply Derivatives	$	64		$	(6	)	$	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

10

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 7—OTHER NON-CURRENT ASSETS

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

	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	—		1
Information technology service assets	19		19
Total other non-current assets, net	$	159	$	169

NOTE 8—ACCRUED LIABILITIES

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

	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	143	$	230
Liquefaction Project costs	308		376
Total accrued liabilities	$	451	$	606

NOTE 9—DEBT

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

	March 31,			December 31,
	2018			2017
Long-term debt
5.625% Senior Secured Notes due 2021 (“2021 Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
6.25% Senior Secured Notes due 2022 (“2022 Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 Senior Notes”), net of unamortized premium of $5 and $5	1,505			1,505
5.75% Senior Secured Notes due 2024 (“2024 Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 Senior Notes”), net of unamortized discount of $1 and $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 Senior Notes”)	800			800
Unamortized debt issuance costs	(176		)	(183		)
Total long-term debt, net	13,483			13,477
Current debt
$1.2 billion Working Capital Facility (“Working Capital Facility”)	—			—
Total debt, net	$	13,483		$	13,477

11

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Working Capital Facility

Below is a summary of our Working Capital Facility as of March 31, 2018 (in millions):

	Working Capital Facility
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	706
Available commitment	$	494
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%
Maturity date	December 31, 2020, with various terms for underlying loans

Restrictive Debt Covenants

As of March 31, 2018, we were in compliance with all covenants related to our debt agreements.

Interest Expense

Total interest expense consisted of the following (in millions):

	Three Months Ended March 31,
	2018			2017
Total interest cost	$	198		$	186
Capitalized interest	(47		)	(81		)
Total interest expense, net	$	151		$	105

Fair Value Disclosures

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

	March 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	12,859	$	13,631	$	12,860	$	13,955
2037 Senior Notes (2)	800		838		800		871

(1) Includes 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 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 interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 

12

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—REVENUES FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues	$	996	$	485
LNG revenues—affiliate	503		331
Total revenues from customers	1,499		816
Revenues from derivative instruments	19		7
Total revenues	$	1,518	$	823

LNG Revenues

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

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

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

Deferred Revenue Reconciliation

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

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	84		$	46
Cash received but not yet recognized	69			36
Revenue recognized from prior period deferral	(84		)	(46		)
Deferred revenues, end of period	$	69		$	36

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

13

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	55.2	10.0

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

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of natural gas at Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. The receipt of such variable consideration is considered constrained due to the uncertainty of ultimate pricing and receipt and we have not included such variable consideration in the transaction price. During the three months ended March 31, 2018, approximately 56% of our LNG Revenues and 100% of our LNG revenues—affiliate 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 a final investment decision on a certain liquefaction Train or obtaining financing. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above.

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

14

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Operations for the three months ended March 31, 2018 and 2017 (in millions):

	Three Months Ended March 31,
	2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	503	$	331
Cost of sales—affiliate
Cargo loading fees under TUA	8		4
Operating and maintenance expense—affiliate
TUA	64		33
Natural Gas Transportation Agreement	20		16
Services Agreements	19		10
Total operating and maintenance expense—affiliate	103		59
General and administrative expense—affiliate
Services Agreements	12		17

LNG Terminal-Related Agreements

Terminal Use Agreements

We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2.0Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least 20 years after May 2016. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, we, Cheniere Investments and SPLNG also entered into a terminal use rights assignment and agreement(the “TURA”) pursuant to which Cheniere Investments has the right to use our reserved capacity under the TUA and has the obligation to pay the TUA Fees required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal and its respective percentage of TUA Fees payable was reduced from 100% to zero as each of Trains 1 through 4 reached commercial operations.

Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process.

In connection with our TUA, we are required to pay for a portion of the cost to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is based on our share of the commercial LNG storage capacity at the Sabine Pass LNG terminal.

Cheniere Marketing SPA

Cheniere Marketing has an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

15

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Marketing Master SPA

We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement.

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, we executed a confirmation with Cheniere Marketing that obligates Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. has control of, and is commissioning, Train 5 of the Liquefaction Project.

Natural Gas Transportation Agreements

To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have a transportation precedent agreement and a negotiated rate agreement to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. These agreements have a primary term of 20 years from commercial operation of Train 2 and thereafter continue in effect from year to year until terminated by either party upon written notice of 1 year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to two consecutive ten-year terms. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise.

Services Agreements

As of March 31, 2018 and December 31, 2017, we had $91 million and $26 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under the services agreements described below are recorded in general and administrative expense—affiliate.

Liquefaction O&M Agreement

We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on our behalf, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train.

Liquefaction MSA

We have a management services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

16

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investment’s subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.

LNG Site Sublease Agreement

We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple 10-year extensions with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements.

Cooperation Agreement

We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We did not convey any assets to SPLNG under this agreement during the three months ended March 31, 2018 and 2017.

Contract for Sale and Purchase of Natural Gas and LNG

We have an agreement with SPLNG that allows us to sell and purchase natural gas and LNG with SPLNG. Natural gas and LNG purchased under this agreement are recorded as inventory, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after August 2012.

NOTE 12—CUSTOMER CONCENTRATION

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

	Percentage of Total Third-Party Revenues			Percentage of Accounts Receivable from Third Parties
		Three Months Ended March 31,		March 31,	December 31,
		2018	2017	2018	2017
Customer A		34%	61%	34%	39%
Customer B		27%	33%	19%	32%
Customer C		27%	—%	19%	27%
Customer D		11%	—%	26%	—%

17

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	230	$	154

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $189 million and $306 million, as of March 31, 2018 and 2017, respectively.

NOTE 14—RECENT ACCOUNTING STANDARDS

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

Standard	Description	Expected Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Financial Statements. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we expect that the requirement to recognize all leases on our Balance Sheets will be a significant change from current practice but will not have a material impact upon our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition.

18

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

Standard	Description	Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 10—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Financial Statements or related disclosures.

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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements.” 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 natural gas liquefaction project, 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, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any such EPC or other contractor, and anticipated costs related thereto;

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

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

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

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

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

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

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

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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 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

We were formed by Cheniere Partners to own, develop and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities owned and operated by SPLNG. 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. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG.

Overview of Significant Events

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

Operational

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

Financial

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

Liquidity and Capital Resources

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

	March 31,		December 31,
	2018		2017
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the Liquefaction Project	561		544
Available commitments under the $1.2 billion Working Capital Facility (“Working Capital Facility”)	494		470

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For additional information regarding our debt agreements, see Note 9—Debt of our Notes to Financial Statements in this quarterly report and Note 10—Debt of our Notes to Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

Liquefaction Facilities

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

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

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

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

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

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

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from five to 10 years from the date the order was issued. In addition, we received an order providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes we were 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 us to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing 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

We have entered into six fixed price SPAs with terms of at least 20 years (plus extension rights) with third parties to make available an aggregate amount of LNG that is between approximately 80% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 through 5. Under these SPAs, the customers will purchase LNG from us 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 fees under our 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

22

Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Under our SPA with BG Gulf Coast LNG, LLC (“BG”), BG has contracted for volumes related to Trains 3 and 4 for which the obligation to make LNG available to BG is expected to commence approximately one year after the date of first commercial delivery for the respective Train.

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

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

Natural Gas Transportation, Storage and Supply

To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. We have entered into firm storage services agreements with third parties to assist in managing volatility in natural gas needs for the Liquefaction Project. We have also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of March 31, 2018, we have secured up to approximately 2,179TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts.

Construction

We have entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 5 of the Liquefaction 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 us to enter into a change order, or we agree with Bechtel to a change order.

The total contract price of the EPC contract for Train 5 of the Liquefaction Project is approximately $3.1 billion reflecting amounts incurred under change orders through March 31, 2018. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.5 billion and $18.5 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Train 6

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

Terminal Use Agreements

We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2.0Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least 20 years after May 2016. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, we, Cheniere Investments and SPLNG also entered into a terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments has the right to use our reserved capacity under the TUA and has the obligation to pay the TUA Fees required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal and its respective percentage of TUA Fees payable was reduced from 100% to zero as each of Trains 1 through 4 reached commercial operations.

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Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA. During the three months ended March 31, 2018, we recorded operating and maintenance expense—affiliate of $64 million for the TUA Fees and cost of sales—affiliate of $8 million for cargo loading services incurred under the TUA. During the three months ended March 31, 2017, we recorded operating and maintenance expense—affiliate of $33 million for the TUA Fees and cost of sales—affiliate of $4 million for cargo loading services incurred under the TUA.

Additionally, we have entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 3, we gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement provides us 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 us to more flexibly manage our LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the three months ended March 31, 2018 and 2017, we recorded $8 million and zero, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Capital Resources

We currently expect that our capital resources requirements with respect to Trains 1 through 5 of the Liquefaction Project will be financed through project debt and borrowings and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Train 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. We began generating cash flows from operations from the Liquefaction Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2, 3 and 4 subsequently achieved substantial completion in September 2016, March 2017 and October 2017, respectively. We realized offsets to LNG terminal costs of $124 million in the three months ended March 31, 2017 that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations, during the testing phase for the construction of those Trains of the Liquefaction Project. We did not realize any offsets to LNG terminal costs in the three months ended March 31, 2018.

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

	March 31,		December 31,
	2018		2017
Senior notes (1)	$	13,650	$	13,650
Working Capital Facility outstanding balance	—		—
Letters of credit issued under Working Capital Facility	706		730
Available commitments under Working Capital Facility	494		470
Total capital resources from borrowings and available commitments	$	14,850	$	14,850

(1) Includes 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 Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 Senior Notes”) and 5.00% Senior Secured Notes due 2037 (the “2037 Senior Notes”)(collectively, the “Senior Notes”).

For additional information regarding our debt agreements related to the Liquefaction Project, see Note 9—Debt of our Notes to Financial Statements in this quarterly report and Note 10—Debt of our Notes to Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

Senior Notes

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

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

Both the indenture governing the 2037 Senior Notes (the “2037 Senior Notes Indenture”) and the common indenture governing the remainder of the Senior Notes(the “Indenture”) include restrictive covenants. We 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 our current outstanding indebtedness, including the Senior Notes and the Working Capital Facility. Under the 2037 Senior Notes Indenture and the Indenture, we 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. As of March 31, 2018, we were in compliance with all covenants related to the Senior Notes. Semi-annual principal payments for the 2037 Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025.

Working Capital Facility

In September 2015, we entered into the Working Capital Facility, which is intended to be used for loans (“Working Capital Loans”), the issuance of letters of credit, as well as for swing line loans (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. We may, from time to time, request increases in the commitments under the Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million. As of March 31, 2018 and December 31, 2017, we had $494 million and $470 million of available commitments and $706 million and $730 million aggregate amount of issued letters of credit under the Working Capital Facility, respectively. As of both March 31, 2018 and December 31, 2017, we had zero loans outstanding under the Working Capital Facility.

The 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. Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the Working Capital Facility, (2) the date 15 days after such Swing Line Loan is made and (3) the first borrowing date for a Working Capital Loan or Swing Line Loan occurring at least three business days following the date the Swing Line Loan is made. We are required to reduce the aggregate outstanding principal amount of all Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. As of March 31, 2018, we were in compliance with all covenants related to the Working Capital Facility. Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as all of our membership interests on a pari passu basis with the Senior Notes.

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Sources and Uses of Cash

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

	Three Months Ended March 31,
	2018			2017
Operating cash flows	$	206		$	116
Investing cash flows	(189		)	(528		)
Financing cash flows	—			1,585
Net increase in cash, cash equivalents and restricted cash	17			1,173
Cash, cash equivalents and restricted cash—beginning of period	544			358
Cash, cash equivalents and restricted cash—end of period	$	561		$	1,531

Operating Cash Flows

Our operating cash inflows during the three months ended March 31, 2018 and 2017 were $206 million and $116 million, respectively. The $90 million increase in operating cash inflows in 2018 compared to 2017 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the of additional Trains that were operating at the Liquefaction Project in 2018. There were four Trains operating during the three months ended March 31, 2018, whereas two Trains were operating during the three months ended March 31, 2017.

Investing Cash Flows

Investing cash outflows during the three months ended March 31, 2018 and 2017 were $189 million and $528 million, respectively, and were primarily used to fund the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion.

Financing Cash Flows

There were no financing cash flows during the three months ended March 31, 2018. Financing cash inflows during the three months ended March 31, 2017 were $1.6 billion, primarily as a result of:

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

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

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

• $26 million of debt issuance costs related to up-front fees paid upon the closing of these transactions.

Results of Operations

Our net income was $242 million in the three months ended March 31, 2018, compared to a net loss of $4 million in the three months ended March 31, 2017. This $246 million increase in net income in 2017 was primarily a result of increased income from operations due to additional Trains operating between the periods and decreased loss on early extinguishment of debt, which were partially offset by increased interest expense, net of amounts capitalized.

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Revenues

	Three Months Ended March 31,
(in millions, except volumes)	2018		2017		Change
LNG revenues	$	1,015	$	492	$	523
LNG revenues—affiliate	503		331		172
Total revenues	$	1,518	$	823	$	695
LNG volumes recognized as revenues (in TBtu)	241		128		113

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

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process because these amounts are earned or loaded during the testing phase for the construction of that Train. We realized offset to LNG terminal costs of $124 million corresponding to 18 TBtu of LNG in the three months ended March 31, 2017 that was related to the sale of commissioning cargoes. There were no commissioning cargoes sold that were realized as offsets to LNG terminal costs in the three months ended March 31, 2018.

Operating costs and expenses

	Three Months Ended March 31,
(in millions)	2018		2017		Change
Cost of sales	$	838	$	510	$	328
Cost of sales—affiliate	8		4		4
Operating and maintenance expense	78		39		39
Operating and maintenance expense—affiliate	103		59		44
General and administrative expense	2		2		—
General and administrative expense—affiliate	12		17		(5		)
Depreciation and amortization expense	86		47		39
Total operating costs and expenses	$	1,127	$	678	$	449

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

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

Operating and maintenance expense (including affiliates) increased during the three months ended March 31, 2018 from the three months ended March 31, 2017, as a result of the increase in operating Trains during 2018. Operating and maintenance expense includes costs associated with operating and maintaining the Liquefaction Project. The increase during the three months ended March 31, 2018 from the three months ended March 31, 2017 was primarily related to TUA reservation charges paid to SPLNG and to Total from payments under the partial TUA assignment agreement, natural gas transportation and storage capacity demand charges paid to CTPL and third parties, third-party service and maintenance contract costs and payroll and benefit costs

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of operations personnel. Operating and maintenance expense (including affiliates) also includes insurance and regulatory costs and other operating costs.

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

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

Other expense (income)

	Three Months Ended March 31,
(in millions)	2018			2017		Change
Interest expense, net of capitalized interest	$	151		$	105	$	46
Loss on early extinguishment of debt	—			42		(42		)
Derivative loss, net	—			2		(2		)
Other income	(2		)	—		(2		)
Total other expense	$	149		$	149	$	—

Interest expense, net of capitalized interest, increased during the three months ended March 31, 2018 compared to the three months ended March 31, 2017 primarily as a result of a decrease in the portion of total interest costs that could be capitalized as additional Trains of the Liquefaction Project completed construction between the periods. For the three months ended March 31, 2018, we incurred $198 million of total interest cost, of which we capitalized $47 million, which was directly related to the construction of the Liquefaction Project. For the three months ended March 31, 2017, we incurred $186 million of total interest cost, of which we capitalized $81 million, which was directly related to the construction of the Liquefaction Project.

Loss on early extinguishment of debt decreased during the three months ended March 31, 2018, as compared to the three months ended March 31, 2017. Loss on early extinguishment of debt recognized during the three months ended March 31, 2017 was attributable to the $42 million write-off of debt issuance costs in March 2017 upon termination of the remaining available balance of $1.6 billion under the previous credit facilities in connection with the issuance of the 2028 Senior Notes and the 2037 Senior Notes.

Off-Balance Sheet Arrangements

As of March 31, 2018, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our financial position or operating results. 

Summary of Critical Accounting Estimates

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

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 14—Recent Accounting Standards of our Notes to Financial Statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project(“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):

	March 31, 2018				December 31, 2017
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	10	$	—	$	55	$	5

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 Securities Exchange Act of 1934, as amended(the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.

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

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

In February 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Corrective Action Order (the “CAO”) to us 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, we and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO.  We continue to work with PHMSA and other appropriate regulatory authorities to address the matters identified in the Consent Order. We do not expect that the Consent Order and related analysis, repair and remediation will have a material adverse impact on our financial results or operations.

ITEM 1A. RISK FACTORS

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

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ITEM 6. EXHIBITS

Exhibit No.	Description
10.1*	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between the Company and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00025 BOG and LNG Rundown, dated January 19, 2018, (ii) the Change Order CO-00026 Design Analysis of Existing East & West Jetty Piping and Structure for Simultaneous Loading, dated February 1, 2018, (iii) the Change Order CO-00027 Performance and Attendance Bonus (PAB) Transfer from Stage 2, dated February 1, 2018, and (iv) the Change Order CO-00028 Existing Jetty Structural Steel Supply, dated February 27, 2018
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.
**	Furnished herewith.

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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.

		SABINE PASS LIQUEFACTION, LLC
Date:	May 3, 2018	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	May 3, 2018	By:	/s/ Leonard Travis
			Leonard Travis
			Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

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EX-10.1

Exhibit 10.1

CHANGE ORDER FORM

BOG and LNG Rundown

PROJECT NAME:  Sabine Pass LNG Stage 3 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: May 4, 2015 CHANGE ORDER NUMBER: CO-00025 DATE OF CHANGE ORDER: January 19, 2018

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

1. Per Article 6.1.B of the Agreement, the Parties agree Contractor will perform the Procurement and Construction services for the BOG and LNG Rundown tie-ins. These services will be based on the Engineering for the BOG and LNG Rundown that was included in the original RFS (RFS 109265 Revision 5).

2. The BOG and LNG Rundown line tie-in packages will be developed after the HAZOP and Model review occurs. These packages will include IFC drawings to procure and construct the required materials. Potential changes due to HAZOP or Model review action items are excluded from this Change Order. For clarity, the tie-ins are depicted in Exhibit A of this Change Order.

3. This Change Order is not included as part of Stage 3 Substantial Completion and will not prevent achievement thereof.

4. The cost breakdown for this Change Order is detailed in Exhibit B.

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

Adjustment to Contract Price

The original Contract Price was	$	2,987,000,000
Net change by previously authorized Change Orders (#00001-00024)	$	95,972,403
The Contract Price prior to this Change Order was	$	3,082,972,403
The Contract Price will be increased by this Change Order in the amount of	$	506,471
The new Contract Price including this Change Order will be	$	3,083,478,874

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

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

Adjustment to Payment Schedule: Yes. See Exhibit C.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials:

/s/ BT Contractor Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ Ed Lehotsky	/s/ Bhupesh Thakkar
Owner	Contractor
Ed Lehotsky	Bhupesh Thakkar
Name	Name
SVP LNG E&C	Senior Project Manager
Title	Title
February 15, 2018	January 19, 2018
Date of Signing	Date of Signing

CHANGE ORDER FORM

Design Analysis of Existing East & West Jetty Piping and Structure for Simultaneous Loading

PROJECT NAME:  Sabine Pass LNG Stage 3 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: May 4, 2015 CHANGE ORDER NUMBER: CO-00026 DATE OF CHANGE ORDER: February 1, 2018

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

1. Per Article 6.1.B of the Agreement, the Parties agree Contractor shall perform various transient runs along with CSA/PD&P design analysis of the existing East and West Jetty piping and structure for simultaneous loading. The key items for this analysis are listed as follows:

a. Validation of Contractor’s transient model.

b. Completion of 8,000 m³/hr simultaneous loading analysis to the existing East and West Jetty. Results will be reviewed by PD&P Pipe Stress to update load tables and identify pipe supports exceeding the original design loads.

c. Completion of CSA and PD&P design analysis to support loading lines from the existing LNG tanks to the East and West Jetty. In addition, for the proposed modifications, the associated CSA and PD&P redline markups and IFC drawings will be provided to Owner.

2. Owner may not disclose the Contractor Work Product to any third party, unless Contractor's prior written consent has been obtained (such consent not to be unreasonably withheld or delayed), provided that Contractor's prior written consent is hereby deemed to be given for disclosure to the Parties listed in Exhibit A to the extent such Parties have entered into a confidentiality agreement with Owner no less stringent than this Agreement.

3. Notwithstanding anything to the contrary herein, Contractor shall perform the Work in accordance with the standard of skill and care reasonably to be expected in the international engineering and construction industry for projects of the type, size and complexity of the Work contemplated herein. In the event that any such Work under this Change Order fails to meet that standard of performance, Contractor's sole liability and Owner’s sole remedy shall be limited to Contractor reperforming such Work at its own expense; provided that notice of such failure is given by Owner within a reasonable time and no later than twelve (12) months from the completion of the Work in question.

4. The Work to be performed under this Change Order is not a condition to and will not prevent the achievement of Substantial Completion of Subproject 5.

5. The cost breakdown for this Change Order is detailed in Exhibit B.

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

Adjustment to Contract Price

The original Contract Price was	$	2,987,000,000
Net change by previously authorized Change Orders (#00001-00025)	$	96,478,874
The Contract Price prior to this Change Order was	$	3,083,478,874
The Contract Price will be increased by this Change Order in the amount of	$	671,121
The new Contract Price including this Change Order will be	$	3,084,149,995

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

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

Adjustment to Payment Schedule: Yes. See Exhibit C.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials:

/s/ BT Contractor /s/ EL Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ Ed Lehotsky	/s/ Bhupesh Thakkar
Owner	Contractor
Ed Lehotsky	Bhupesh Thakkar
Name	Name
SVP LNG E&C	Senior Project Manager
Title	Title
February 15, 2018	February 1, 2018
Date of Signing	Date of Signing

CHANGE ORDER FORM

Performance and Attendance Bonus (PAB) Transfer from Stage 2

PROJECT NAME:  Sabine Pass LNG Stage 3 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: May 4, 2015 CHANGE ORDER NUMBER: CO-00027 DATE OF CHANGE ORDER: February 1, 2018

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

1. The value of the Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum incorporated into the Agreement in Change Order CO-00005, dated March 16, 2016, was U.S. $36,900,000. Parties now agree the Stage 2 accrued cost for retention of the PAB incentive will be transferred to Stage 3 and invoiced against the PAB value in the Stage 3 Agreement due to Craft personnel moving to Stage 3 as opposed to being released as part of a reduction of Stage 2 workforce. The amount to be transferred is $8,100,000. The contract price will be increased by $8,100,000.

2. The Provisional Sum breakdown is described as follows:

a. The previous PAB Incentive Program Provisional Sum in Article 2.6 of Attachment EE of the Agreement was Thirty-Six Million, Nine Hundred Thousand U.S. Dollars (U.S. $36,900,000). This Change Order will increase the PAB Incentive Program Provisional Sum by $8,100,000 and the value will be $45,000,000.

b. The Parties agree to adjust the Aggregate Provisional Sum specified in Article 7.1A of the Agreement which prior to this Change Order was Three Hundred Sixteen Million, Two Hundred Forty-Six Thousand, Four Hundred Thirty-Seven U.S. Dollars (U.S. $316,246,437). This Change Order will increase the Aggregate Provisional Sum amount by Eight Million, One Hundred Thousand U.S. Dollars (U.S. $8,100,000) and the new Aggregate Provisional Sum value shall be Three Hundred Twenty-Four Million, Three Hundred Forty-Six Thousand, Four Hundred Thirty-Seven U.S. Dollars (U.S. $324,346,437).

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

Adjustment to Contract Price

The original Contract Price was	$	2,987,000,000
Net change by previously authorized Change Orders (#00001-00026)	$	97,149,995
The Contract Price prior to this Change Order was	$	3,084,149,995
The Contract Price will be increased by this Change Order in the amount of	$	8,100,000
The new Contract Price including this Change Order will be	$	3,092,249,995

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

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

Adjustment to Payment Schedule: Yes. See Exhibit A.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials:

/s/ BT Contractor /s/ EL Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ Ed Lehotsky	/s/ Bhupesh Thakkar
Owner	Contractor
Ed Lehotsky	Bhupesh Thakkar
Name	Name
SVP LNG E&C	Senior Project Manager
Title	Title
February 15, 2018	February 1, 2018
Date of Signing	Date of Signing

CHANGE ORDER FORM

Existing Jetty Structural Steel Supply

PROJECT NAME:  Sabine Pass LNG Stage 3 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: May 4, 2015 CHANGE ORDER NUMBER: CO-00028 DATE OF CHANGE ORDER: February 27, 2018

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

1. Per Article 6.1.B of the Agreement, the Parties agree Contractor will obtain structural steel from CIVES via purchase order to support the modifications of the existing jetty. This will require award of a purchase order referencing the existing Stage 3 CIVES purchase order and will require review by the CSA team prior to delivery of the steel to the Site.

2. The following areas will be revised by CIVES: Area 1R1, Area 2R1, Area 3R1 and Area 22R. For clarity, the revised areas are depicted in Exhibit A of this Change Order.

3. The steel associated with this Change Order will be free issued to Owner. The existing Stage 3 contract terms are not applicable to this work and Contractor’s obligation is limited to providing steel of good quality and ensuring the steel is fabricated in accordance with the specification, design drawings and fabrication details.

4. The work pursuant to this Change Order is not a condition to and will not prevent the achievement of Stage 3 Substantial Completion or impact the Stage 3 warranty period.

5. The cost breakdown for this Change Order is detailed in Exhibit B.

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

Adjustment to Contract Price

The original Contract Price was	$	2,987,000,000
Net change by previously authorized Change Orders (#00001-00027)	$	105,249,995
The Contract Price prior to this Change Order was	$	3,092,249,995
The Contract Price will be increased by this Change Order in the amount of	$	34,820
The new Contract Price including this Change Order will be	$	3,092,284,815

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

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

Adjustment to Payment Schedule: Yes. See Exhibit C.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials:

/s/ BT Contractor /s/ EL Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ Ed Lehotsky	/s/ Bhupesh Thakkar
Owner	Contractor
Ed Lehotsky	Bhupesh Thakkar
Name	Name
SVP LNG E&C	Senior Project Manager
Title	Title
March 13, 2018	February 27, 2018
Date of Signing	Date of Signing

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Jack A. Fusco, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Sabine Pass Liquefaction, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f )) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

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

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

Date: May 3, 2018

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Sabine Pass Liquefaction, LLC

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Michael J. Wortley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Sabine Pass Liquefaction, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f )) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

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

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

Date: May 3, 2018

/s/ Michael J. Wortley

Michael J. Wortley

Chief Financial Officer of

Sabine Pass Liquefaction, LLC

EX-32.1

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Sabine Pass Liquefaction, LLC (the “Company”) on Form 10-Q for the quarter ended March 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: May 3, 2018

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Sabine Pass Liquefaction, LLC

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Sabine Pass Liquefaction, LLC (the “Company”) on Form 10-Q for the quarter ended March 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Wortley, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: May 3, 2018

/s/ Michael J. Wortley

Michael J. Wortley

Chief Financial Officer of

Sabine Pass Liquefaction, LLC

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2018 shares
Document and Entity Information [Abstract]
Entity Registrant Name	Sabine Pass Liquefaction, LLC
Entity Central Index Key	0001499200
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding	0

XML

Balance Sheets - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 0	$ 0
Restricted cash	561	544
Accounts and other receivables	238	189
Accounts receivable—affiliate	114	163
Advances to affiliate	91	26
Inventory	72	85
Other current assets	38	54
Other current assets—affiliate	22	21
Total current assets	1,136	1,082
Property, plant and equipment, net	12,933	12,920
Debt issuance costs, net	16	18
Non-current derivative assets	9	17
Other non-current assets, net	159	169
Total assets	14,253	14,206
Current liabilities
Accounts payable	7	8
Accrued liabilities	451	606
Due to affiliates	32	66
Deferred revenue	69	84
Derivative liabilities	4	0
Total current liabilities	563	764
Long-term debt, net	13,483	13,477
Non-current derivative liabilities	3	3
Member’s equity (deficit)	204	(38)
Total liabilities and member’s equity (deficit)	$ 14,253	$ 14,206

XML

Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues
LNG revenues	$ 1,015	$ 492
LNG revenues—affiliate	503	331
Total revenues	1,518	823
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	838	510
Cost of sales—affiliate	8	4
Operating and maintenance expense	78	39
Operating and maintenance expense—affiliate	103	59
General and administrative expense	2	2
General and administrative expense—affiliate	12	17
Depreciation and amortization expense	86	47
Total operating costs and expenses	1,127	678
Income from operations	391	145
Other income (expense)
Interest expense, net of capitalized interest	(151)	(105)
Loss on early extinguishment of debt	0	(42)
Derivative loss, net	0	(2)
Other income	2	0
Total other expense	(149)	(149)
Net income (loss)	$ 242	$ (4)

XML

Statement of Member's Equity (Deficit) - 3 months ended Mar. 31, 2018 - USD ($) $ in Millions	Total	Sabine Pass LNG-LP, LLC [Member]
Members' equity, beginning of period at Dec. 31, 2017	$ (38)	$ (38)
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	242	242
Member's equity, end of period at Mar. 31, 2018	$ 204	$ 204

XML

Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities
Net income (loss)	$ 242	$ (4)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	86	47
Amortization of debt issuance costs, deferred commitment fees, premium and discount	5	5
Loss on early extinguishment of debt	0	42
Total losses on derivatives, net	50	41
Net cash used for settlement of derivative instruments	(5)	(11)
Changes in operating assets and liabilities:
Accounts and other receivables	(49)	(11)
Accounts receivable—affiliate	48	56
Advances to affiliate	(60)	(40)
Inventory	12	18
Accounts payable and accrued liabilities	(94)	(39)
Due to affiliates	(17)	2
Deferred revenue	(15)	(10)
Deferred revenue—affiliate	0	19
Other, net	3	3
Other, net—affiliate	0	(2)
Net cash provided by operating activities	206	116
Cash flows from investing activities
Property, plant and equipment, net	(189)	(528)
Net cash used in investing activities	(189)	(528)
Cash flows from financing activities
Proceeds from issuances of debt	0	2,314
Repayments of debt	0	(703)
Debt issuance and deferred financing costs	0	(26)
Net cash provided by financing activities	0	1,585
Net increase in cash, cash equivalents and restricted cash	17	1,173
Cash, cash equivalents and restricted cash—beginning of period	544	358
Cash, cash equivalents and restricted cash—end of period	$ 561	$ 1,531

XML

Statements of Cash Flows - Balances per Balance Sheet - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Balances per Balance Sheet:
Cash and cash equivalents	$ 0	$ 0
Restricted cash	561	544
Total cash, cash equivalents and restricted cash	$ 561	$ 544	$ 1,531	$ 358

XML

Nature of Operations and Basis of Presentation

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We were formed by Cheniere Partners to own, develop and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities owned and operated by SPLNG. Our Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal, which is located on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place.

Basis of Presentation

The accompanying unaudited Financial Statements of SPL 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 Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

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

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

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

XML

Restricted Cash

3 Months Ended

Mar. 31, 2018

Restricted Cash [Abstract]

Restricted Cash

RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. As of March 31, 2018 and December 31, 2017, restricted cash consisted of the following (in millions):

	March 31,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	561	$	544

XML

Accounts and Other Receivables

3 Months Ended

Mar. 31, 2018

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

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

	March 31,		December 31,
	2018		2017
Trade receivable	$	232	$	185
Other accounts receivable	6		4
Total accounts and other receivables	$	238	$	189

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.

XML

Inventory

3 Months Ended

Mar. 31, 2018

Inventory Disclosure [Abstract]

Inventory

INVENTORY

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

	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	14		26
Materials and other	42		42
Total inventory	$	72	$	85

XML

Property, Plant and Equipment

3 Months Ended

Mar. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	9,945		$	9,963
LNG terminal construction-in-process	3,397			3,283
Accumulated depreciation	(414		)	(330		)
Total LNG terminal costs, net	12,928			12,916
Fixed assets
Fixed assets	11			10
Accumulated depreciation	(6		)	(6		)
Total fixed assets, net	5			4
Property, plant and equipment, net	$	12,933		$	12,920

Depreciation expense was $84 million and $45 million during the three months ended March 31, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $124 million in the three months ended March 31, 2017 that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three months ended March 31, 2018.

XML

Derivative Instruments

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). We had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of our credit facilities (“Interest Rate Derivatives”), and these Interest Rate Derivatives were settled in March 2017.

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 Statements of Operations to the extent not utilized for the commissioning process.

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

	Fair Value Measurements as of
	March 31, 2018								December 31, 2017
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset	$	—	$	—	$	10	$	10	$	2	$	10	$	43	$	55

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

We value our Liquefaction Supply Derivatives using market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available and other relevant data.

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

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

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

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$10	Market approach incorporating present value techniques	Basis Spread	$(0.515) - $0.095

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

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

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

Interest Rate Derivatives

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

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

	Three Months Ended March 31,
	2018		2017
Interest Rate Derivatives loss	$	—	$	(2	)

Liquefaction Supply Derivatives

We had secured up to approximately 2,179TBtu and 2,214TBtu of natural gas feedstock through natural gas supply contracts as of March 31, 2018 and December 31, 2017, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,521TBtu and 1,520TBtu as of March 31, 2018 and December 31, 2017, respectively.

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

	Fair Value Measurements as of (1)
Balance Sheet Location	March 31, 2018			December 31, 2017
Other current assets	$	8		$	41
Non-current derivative assets	9			17
Total derivative assets	17			58
Derivative liabilities	(4		)	—
Non-current derivative liabilities	(3		)	(3		)
Total derivative liabilities	(7		)	(3		)
Derivative asset, net	$	10		$	55

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

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

		Three Months Ended March 31,
	Statement of Operations Location (1)	2018		2017
Liquefaction Supply Derivatives loss (2)	Cost of sales	$	50	$	39

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

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

Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our 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 Balance Sheets			Net Amounts Presented in the Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2018
Liquefaction Supply Derivatives	$	25		$	(8	)	$	17
Liquefaction Supply Derivatives	(9		)	2			(7		)
As of December 31, 2017
Liquefaction Supply Derivatives	$	64		$	(6	)	$	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

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Other Non-Current Assets

3 Months Ended

Mar. 31, 2018

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

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

	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	—		1
Information technology service assets	19		19
Total other non-current assets, net	$	159	$	169

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Accrued Liabilities

3 Months Ended

Mar. 31, 2018

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

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

	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	143	$	230
Liquefaction Project costs	308		376
Total accrued liabilities	$	451	$	606

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Debt

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Debt

DEBT

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

	March 31,			December 31,
	2018			2017
Long-term debt
5.625% Senior Secured Notes due 2021 (“2021 Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
6.25% Senior Secured Notes due 2022 (“2022 Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 Senior Notes”), net of unamortized premium of $5 and $5	1,505			1,505
5.75% Senior Secured Notes due 2024 (“2024 Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 Senior Notes”), net of unamortized discount of $1 and $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 Senior Notes”)	800			800
Unamortized debt issuance costs	(176		)	(183		)
Total long-term debt, net	13,483			13,477
Current debt
$1.2 billion Working Capital Facility (“Working Capital Facility”)	—			—
Total debt, net	$	13,483		$	13,477

Working Capital Facility

Below is a summary of our Working Capital Facility as of March 31, 2018 (in millions):

	Working Capital Facility
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	706
Available commitment	$	494
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%
Maturity date	December 31, 2020, with various terms for underlying loans

Restrictive Debt Covenants

As of March 31, 2018, we were in compliance with all covenants related to our debt agreements.

Interest Expense

Total interest expense consisted of the following (in millions):

	Three Months Ended March 31,
	2018			2017
Total interest cost	$	198		$	186
Capitalized interest	(47		)	(81		)
Total interest expense, net	$	151		$	105

Fair Value Disclosures

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

	March 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	12,859	$	13,631	$	12,860	$	13,955
2037 Senior Notes (2)	800		838		800		871

(1) Includes 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 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 interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

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Revenues from Contracts with Customers

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenues from Contracts with Customers

REVENUES FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues	$	996	$	485
LNG revenues—affiliate	503		331
Total revenues from customers	1,499		816
Revenues from derivative instruments	19		7
Total revenues	$	1,518	$	823

LNG Revenues

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

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

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

Deferred Revenue Reconciliation

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

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	84		$	46
Cash received but not yet recognized	69			36
Revenue recognized from prior period deferral	(84		)	(46		)
Deferred revenues, end of period	$	69		$	36

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

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	55.2	10.0

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

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of natural gas at Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. The receipt of such variable consideration is considered constrained due to the uncertainty of ultimate pricing and receipt and we have not included such variable consideration in the transaction price. During the three months ended March 31, 2018, approximately 56% of our LNG Revenues and 100% of our LNG revenues—affiliate 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 a final investment decision on a certain liquefaction Train or obtaining financing. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above.

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

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Related Party Transactions

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Operations for the three months ended March 31, 2018 and 2017 (in millions):

	Three Months Ended March 31,
	2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	503	$	331
Cost of sales—affiliate
Cargo loading fees under TUA	8		4
Operating and maintenance expense—affiliate
TUA	64		33
Natural Gas Transportation Agreement	20		16
Services Agreements	19		10
Total operating and maintenance expense—affiliate	103		59
General and administrative expense—affiliate
Services Agreements	12		17

LNG Terminal-Related Agreements

Terminal Use Agreements

We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2.0Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least 20 years after May 2016. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, we, Cheniere Investments and SPLNG also entered into a terminal use rights assignment and agreement(the “TURA”) pursuant to which Cheniere Investments has the right to use our reserved capacity under the TUA and has the obligation to pay the TUA Fees required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal and its respective percentage of TUA Fees payable was reduced from 100% to zero as each of Trains 1 through 4 reached commercial operations.

Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process.

In connection with our TUA, we are required to pay for a portion of the cost to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is based on our share of the commercial LNG storage capacity at the Sabine Pass LNG terminal.

Cheniere Marketing SPA

Cheniere Marketing has an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Cheniere Marketing Master SPA

We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement.

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, we executed a confirmation with Cheniere Marketing that obligates Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. has control of, and is commissioning, Train 5 of the Liquefaction Project.

Natural Gas Transportation Agreements

To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have a transportation precedent agreement and a negotiated rate agreement to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. These agreements have a primary term of 20 years from commercial operation of Train 2 and thereafter continue in effect from year to year until terminated by either party upon written notice of 1 year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to two consecutive ten-year terms. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise.

Services Agreements

As of March 31, 2018 and December 31, 2017, we had $91 million and $26 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under the services agreements described below are recorded in general and administrative expense—affiliate.

Liquefaction O&M Agreement

We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on our behalf, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train.

Liquefaction MSA

We have a management services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investment’s subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.

LNG Site Sublease Agreement

We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple 10-year extensions with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements.

Cooperation Agreement

We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We did not convey any assets to SPLNG under this agreement during the three months ended March 31, 2018 and 2017.

Contract for Sale and Purchase of Natural Gas and LNG

We have an agreement with SPLNG that allows us to sell and purchase natural gas and LNG with SPLNG. Natural gas and LNG purchased under this agreement are recorded as inventory, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after August 2012.

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Customer Concentration

3 Months Ended

Mar. 31, 2018

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

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

	Percentage of Total Third-Party Revenues			Percentage of Accounts Receivable from Third Parties
		Three Months Ended March 31,		March 31,	December 31,
		2018	2017	2018	2017
Customer A		34%	61%	34%	39%
Customer B		27%	33%	19%	32%
Customer C		27%	—%	19%	27%
Customer D		11%	—%	26%	—%

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	230	$	154

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $189 million and $306 million, as of March 31, 2018 and 2017, respectively.

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Recent Accounting Standards

3 Months Ended

Mar. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards

RECENT ACCOUNTING STANDARDS

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

Standard	Description	Expected Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Financial Statements. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we expect that the requirement to recognize all leases on our Balance Sheets will be a significant change from current practice but will not have a material impact upon our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition.

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

Standard	Description	Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 10—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Financial Statements or related disclosures.

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Nature of Operations and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

Basis of Presentation

The accompanying unaudited Financial Statements of SPL 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 Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

Income Taxes, Policy

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

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Restricted Cash (Tables)

3 Months Ended

Mar. 31, 2018

Restricted Cash [Abstract]

Schedule of Restricted Cash

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

	March 31,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	561	$	544

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Accounts and Other Receivables (Tables)

3 Months Ended

Mar. 31, 2018

Receivables [Abstract]

Schedule of Accounts and Other Receivables

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

	March 31,		December 31,
	2018		2017
Trade receivable	$	232	$	185
Other accounts receivable	6		4
Total accounts and other receivables	$	238	$	189

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Inventory (Tables)

3 Months Ended

Mar. 31, 2018

Inventory Disclosure [Abstract]

Schedule of Inventory

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

	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	14		26
Materials and other	42		42
Total inventory	$	72	$	85

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	9,945		$	9,963
LNG terminal construction-in-process	3,397			3,283
Accumulated depreciation	(414		)	(330		)
Total LNG terminal costs, net	12,928			12,916
Fixed assets
Fixed assets	11			10
Accumulated depreciation	(6		)	(6		)
Total fixed assets, net	5			4
Property, plant and equipment, net	$	12,933		$	12,920

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

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

	Fair Value Measurements as of
	March 31, 2018								December 31, 2017
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset	$	—	$	—	$	10	$	10	$	2	$	10	$	43	$	55

Fair Value Inputs, Assets, Quantitative Information

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2018:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$10	Market approach incorporating present value techniques	Basis Spread	$(0.515) - $0.095

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

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

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

Derivative Net Presentation on Balance Sheets

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 Balance Sheets			Net Amounts Presented in the Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2018
Liquefaction Supply Derivatives	$	25		$	(8	)	$	17
Liquefaction Supply Derivatives	(9		)	2			(7		)
As of December 31, 2017
Liquefaction Supply Derivatives	$	64		$	(6	)	$	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Derivative Instruments, Gain (Loss)

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

	Three Months Ended March 31,
	2018		2017
Interest Rate Derivatives loss	$	—	$	(2	)

Liquefaction Supply Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Instruments by Balance Sheet Location

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

	Fair Value Measurements as of (1)
Balance Sheet Location	March 31, 2018			December 31, 2017
Other current assets	$	8		$	41
Non-current derivative assets	9			17
Total derivative assets	17			58
Derivative liabilities	(4		)	—
Non-current derivative liabilities	(3		)	(3		)
Total derivative liabilities	(7		)	(3		)
Derivative asset, net	$	10		$	55

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

Derivative Instruments, Gain (Loss)

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

		Three Months Ended March 31,
	Statement of Operations Location (1)	2018		2017
Liquefaction Supply Derivatives loss (2)	Cost of sales	$	50	$	39

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

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

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Other Non-Current Assets (Tables)

3 Months Ended

Mar. 31, 2018

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

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

	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	—		1
Information technology service assets	19		19
Total other non-current assets, net	$	159	$	169

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Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

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

	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	143	$	230
Liquefaction Project costs	308		376
Total accrued liabilities	$	451	$	606

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Debt (Tables)

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Schedule of Debt Instruments

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

	March 31,			December 31,
	2018			2017
Long-term debt
5.625% Senior Secured Notes due 2021 (“2021 Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
6.25% Senior Secured Notes due 2022 (“2022 Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 Senior Notes”), net of unamortized premium of $5 and $5	1,505			1,505
5.75% Senior Secured Notes due 2024 (“2024 Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 Senior Notes”), net of unamortized discount of $1 and $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 Senior Notes”)	800			800
Unamortized debt issuance costs	(176		)	(183		)
Total long-term debt, net	13,483			13,477
Current debt
$1.2 billion Working Capital Facility (“Working Capital Facility”)	—			—
Total debt, net	$	13,483		$	13,477

Schedule of Line of Credit Facilities

Below is a summary of our Working Capital Facility as of March 31, 2018 (in millions):

	Working Capital Facility
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	706
Available commitment	$	494
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%
Maturity date	December 31, 2020, with various terms for underlying loans

Schedule of Interest Expense

Total interest expense consisted of the following (in millions):

	Three Months Ended March 31,
	2018			2017
Total interest cost	$	198		$	186
Capitalized interest	(47		)	(81		)
Total interest expense, net	$	151		$	105

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	March 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	12,859	$	13,631	$	12,860	$	13,955
2037 Senior Notes (2)	800		838		800		871

(1) Includes 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 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 interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

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Revenues from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended March 31,
	2018		2017
LNG revenues	$	996	$	485
LNG revenues—affiliate	503		331
Total revenues from customers	1,499		816
Revenues from derivative instruments	19		7
Total revenues	$	1,518	$	823

Contract Balances Reconciliation

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

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	84		$	46
Cash received but not yet recognized	69			36
Revenue recognized from prior period deferral	(84		)	(46		)
Deferred revenues, end of period	$	69		$	36

Transaction Price Allocated to Future Performance Obligations

The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of March 31, 2018:

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	55.2	10.0

(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.

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary of our related party transactions as reported on our Statements of Operations for the three months ended March 31, 2018 and 2017 (in millions):

	Three Months Ended March 31,
	2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	503	$	331
Cost of sales—affiliate
Cargo loading fees under TUA	8		4
Operating and maintenance expense—affiliate
TUA	64		33
Natural Gas Transportation Agreement	20		16
Services Agreements	19		10
Total operating and maintenance expense—affiliate	103		59
General and administrative expense—affiliate
Services Agreements	12		17

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Customer Concentration (Tables)

3 Months Ended

Mar. 31, 2018

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

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

	Percentage of Total Third-Party Revenues			Percentage of Accounts Receivable from Third Parties
		Three Months Ended March 31,		March 31,	December 31,
		2018	2017	2018	2017
Customer A		34%	61%	34%	39%
Customer B		27%	33%	19%	32%
Customer C		27%	—%	19%	27%
Customer D		11%	—%	26%	—%

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Three Months Ended March 31,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	230	$	154

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Recent Accounting Standards (Tables)

3 Months Ended

Mar. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards, Not Yet Adopted

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

Standard	Description	Expected Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Financial Statements. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we expect that the requirement to recognize all leases on our Balance Sheets will be a significant change from current practice but will not have a material impact upon our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition.

Recent Accounting Standards, Adopted

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

Standard	Description	Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 10—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Financial Statements or related disclosures.

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Nature of Operations and Basis of Presentation (Details)	3 Months Ended
	Mar. 31, 2018 USD ($) trains
Nature of Operations and Basis of Presentation [Line Items]
Income Tax Expense (Benefit) | $	$ 0
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	6

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Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 561	$ 544
Liquefaction Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 561	$ 544

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Accounts and Other Receivables (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Receivables [Abstract]
Trade receivable	$ 232	$ 185
Other accounts receivable	6	4
Total accounts and other receivables	$ 238	$ 189

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Inventory (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Inventory [Line Items]
Inventory	$ 72	$ 85
Natural gas [Member]
Inventory [Line Items]
Inventory	16	17
LNG [Member]
Inventory [Line Items]
Inventory	14	26
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 42	$ 42

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 12,933	$ 12,920
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(414)	(330)
Property, plant and equipment, net	12,928	12,916
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	9,945	9,963
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	3,397	3,283
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	11	10
Accumulated depreciation	(6)	(6)
Property, plant and equipment, net	$ 5	$ 4

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Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 84	$ 45
Offsets to LNG terminal costs	$ 0	$ 124

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Derivative Instruments - Narrative (Details) $ in Millions	1 Months Ended
	Mar. 31, 2017 USD ($)	Mar. 31, 2018 tbtu	Dec. 31, 2017 tbtu
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Energy Units Secured Through Natural Gas Supply Contracts | tbtu		2,179	2,214
2015 Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease | $	$ 1,600
Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Loss, Net | $	$ 7
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount | tbtu		1,521	1,520

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, at Fair Value, Net	$ 10	$ 55
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, at Fair Value, Net	0	2
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, at Fair Value, Net	0	10
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, at Fair Value, Net	$ 10	$ 43

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	3 Months Ended
	Mar. 31, 2018 USD ($)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Net Fair Value Asset	$ 10,000,000
Valuation Approach	Market approach incorporating present value techniques
Significant Unobservable Input	Basis Spread
Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Significant Unobservable Inputs Range	$ (0.515)
Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Significant Unobservable Inputs Range	$ 0.095

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Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period	$ 43	$ 79
Realized and mark-to-market losses:
Included in cost of sales	(13)	(41)
Purchases and settlements:
Purchases	3	4
Settlements	(23)	(1)
Balance, end of period	10	41
Change in unrealized gains relating to instruments still held at end of period	$ (13)	$ (41)

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Non-current derivative assets		$ 9	$ 17
Derivative liabilities		(4)	0
Non-current derivative liabilities		(3)	(3)
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[1]	17	58
Total derivative liabilities	[1]	(7)	(3)
Derivative asset, net	[1]	10	55
Derivative, collateral call		1	1
Liquefaction Supply Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	8	41
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[1]	9	17
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(4)	0
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[1]	$ (3)	$ (3)

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

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Derivative Instruments - Derivative Gain (Loss) (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended
		Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Interest Rate Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative loss, net		$ 7
Interest Rate Derivatives [Member] | Derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative loss, net			$ 0	$ 2
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative loss, net	[1],[2]		$ 50	$ 39

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

[2] 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.

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Derivative Instruments - Derivative Net Presentation on Balance Sheets (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 25	$ 64
Derivative Asset, Gross Amounts Offset in the Balance Sheets	(8)	(6)
Net Amounts Presented in our Balance Sheets	17	58
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(9)	(3)
Derivative Liability, Gross Amounts Offset in the Balance Sheets	2	0
Net Amounts Presented in our Balance Sheets	$ (7)	$ (3)

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Other Non-Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Other Assets, Noncurrent [Abstract]
Advances made under EPC and non-EPC contracts	$ 18	$ 26
Advances made to municipalities for water system enhancements	93	93
Advances and other asset conveyances to third parties to support LNG terminals	29	30
Tax-related payments and receivables	0	1
Information technology service assets	19	19
Other non-current assets, net	$ 159	$ 169

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Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 143	$ 230
Liquefaction Project costs	308	376
Total accrued liabilities	$ 451	$ 606

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Debt - Schedule of Debt Instruments (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term Debt, Net	$ 13,483,000,000	$ 13,477,000,000
Unamortized Debt Issuance Costs, Noncurrent	(176,000,000)	(183,000,000)
Current Debt, Working Capital Facility	0	0
Total Debt, Net	13,483,000,000	13,477,000,000
2021 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 2,005,000,000	2,006,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debt Instrument, Unamortized Premium	$ 5,000,000	6,000,000
2022 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,000,000,000	1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.25%
2023 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,505,000,000	1,505,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debt Instrument, Unamortized Premium	$ 5,000,000	5,000,000
2024 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%
2025 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2026 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2028 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,349,000,000	1,349,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.20%
Debt Instrument, Unamortized Discount	$ 1,000,000	1,000,000
2037 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 800,000,000	800,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Working Capital Facility [Member]
Debt Instrument [Line Items]
Current Debt, Working Capital Facility	$ 0	$ 0
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,200,000,000.0

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Debt - Credit Facilities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Outstanding balance	$ 0	$ 0
Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	1,200
Outstanding balance	0	$ 0
Letters of credit issued	706
Available commitment	$ 494
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Debt Instrument, Maturity Date, Description	December 31, 2020, with various terms for underlying loans
Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Working Capital Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Debt Disclosure [Abstract]
Total interest cost	$ 198	$ 186
Capitalized interest	(47)	(81)
Total interest expense, net	$ 151	$ 105

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value		$ 13,483	$ 13,477
Senior Notes, net of premium or discount [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[1]	12,859	12,860
Senior Notes, net of premium or discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	13,631	13,955
2037 Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[2]	800	800
2037 Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	$ 838	$ 871

[1] Includes 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 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 interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

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Revenues from Contracts with Customers (Details)	3 Months Ended
	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	56.00%
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	100.00%

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Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	$ 1,499	$ 816
Revenues	1,518	823
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	996	485
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	503	331
Derivative Instruments [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 19	$ 7

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Revenues from Contracts with Customers - Schedule of Deferred Revenue Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	$ 84	$ 46
Cash received but not yet recognized	69	36
Revenue recognized from prior period deferral	(84)	(46)
Deferred revenues, end of period	$ 69	$ 36

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Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - LNG [Member] $ in Billions	3 Months Ended
	Mar. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 55.2
Weighted Average Recognition Timing	10 years	[1]

[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.

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 503	$ 331
Cost of sales—affiliate	8	4
Operating and maintenance expense—affiliate	103	59
General and administrative expense—affiliate	12	17
Cheniere Marketing SPA and Cheniere Marketing Master SPA [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	503	331
Terminal Use Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—affiliate	8	4
Operating and maintenance expense—affiliate	64	33
Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	20	16
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	19	10
General and administrative expense—affiliate	$ 12	$ 17

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Related Party Transactions - Narrative (Details)	3 Months Ended
	Mar. 31, 2018 USD ($) bcf / d item $ / MMBTU	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
Advances to affiliate	$ 91,000,000		$ 26,000,000
Terminal Use Agreement [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Regasification Capacity | bcf / d	2.0
Related Party Transaction, Committed Annual Fee	$ 250,000,000
Related Party Agreement Term	20 years
Terminal Use Rights Assignment and Agreement [Member] | SPLNG [Member] | Cheniere Investments [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Percentage Of Committed Monthly Payment	100.00%
Terminal Use Rights Assignment and Agreement [Member] | SPLNG [Member] | Cheniere Investments [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Percentage Of Committed Monthly Payment	0.00%
LNG Sale and Purchase Agreement [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price | $ / MMBTU	3.00
Natural Gas Transportation Agreement [Member] | CTPL [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term	20 years
Related Party Agreement, Termination Notice Period	1 year
Related Party Agreement, Number Of Available Extensions | item	2
Related Party Agreement, Term Of Available Extension	10 years
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to affiliate	$ 91,000,000		$ 26,000,000
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	0.60%
Related Party Transaction, Committed Monthly Fee	$ 83,333
Management Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	2.40%
Related Party Transaction, Committed Monthly Fee	$ 541,667
LNG Site Sublease Agreement [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Annual Sublease Payment	$ 1,000,000
Term of available extension	10 years
Review Period for Inflation Adjustment	5 years
Cooperation Agreement [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Assets conveyed under the agreement	$ 0	$ 0
Tax Sharing Agreement [Member] | Cheniere [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0

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Customer Concentration (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Customer A [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	34.00%	61.00%
Customer A [Member] | Accounts Receivable from Third Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	34.00%		39.00%
Customer B [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	27.00%	33.00%
Customer B [Member] | Accounts Receivable from Third Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%		32.00%
Customer C [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	27.00%	0.00%
Customer C [Member] | Accounts Receivable from Third Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%		27.00%
Customer D [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%	0.00%
Customer D [Member] | Accounts Receivable from Third Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	26.00%		0.00%

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 230	$ 154
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 189	$ 306