10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2018

or

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

 For the transition period fromto

Cheniere Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware	001-33366	20-5913059
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer Identification No.)
700 Milam Street, Suite 1900 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 375-5000

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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.

Large accelerated filer  x	Accelerated filer                     o
Non-accelerated filer    o	Smaller reporting company    o
	Emerging growth company    o

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

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

As of November 2, 2018, the registrant had 348,623,792 common units and 135,383,831 subordinated units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Income	4
	Consolidated Statement of Partners’ Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	46
Item 4.	Controls and Procedures	47
Part II. Other Information
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 6.	Exhibits	49
	Signatures	50

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

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of September 30, 2018, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to “Cheniere Partners,” “the Partnership,” “we,” “us” and “our” refer to Cheniere Energy Partners, L.P. and its consolidated subsidiaries, including SPLNG, SPL and CTPL. 

References to “Blackstone Group” refer to The Blackstone Group, L.P. References to “Blackstone CQP Holdco” refer to Blackstone CQP Holdco LP. References to “Blackstone” refer to Blackstone Group and Blackstone CQP Holdco.

2

PART I. FINANCIAL INFORMATION 

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

	September 30,			December 31,
	2018			2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—		$	—
Restricted cash	1,457			1,589
Accounts and other receivables	224			191
Accounts receivable—affiliate	22			163
Advances to affiliate	189			36
Inventory	88			95
Other current assets	55			65
Total current assets	2,035			2,139
Property, plant and equipment, net	15,282			15,139
Debt issuance costs, net	15			38
Non-current derivative assets	25			31
Other non-current assets, net	179			206
Total assets	$	17,536		$	17,553
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	13		$	12
Accrued liabilities	503			637
Due to affiliates	53			68
Deferred revenue	119			111
Deferred revenue—affiliate	—			1
Derivative liabilities	6			—
Total current liabilities	694			829
Long-term debt, net	16,059			16,046
Non-current derivative liabilities	2			3
Other non-current liabilities	10			11
Other non-current liabilities—affiliate	23			25
Partners’ equity
Common unitholders’ interest (348.6 million units issued and outstanding at September 30, 2018 and December 31, 2017)	1,759			1,670
Subordinated unitholders’ interest (135.4 million units issued and outstanding at September 30, 2018 and December 31, 2017)	(1,008		)	(1,043		)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2018 and December 31, 2017)	(3		)	12
Total partners’ equity	748			639
Total liabilities and partners’ equity	$	17,536		$	17,553

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

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per unit data)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues
LNG revenues	$	1,249		$	723		$	3,419		$	1,718
LNG revenues—affiliate	205			111			886			864
Regasification revenues	66			65			196			195
Other revenues	9			3			28			7
Other revenues—affiliate	—			1			—			2
Total revenues	1,529			903			4,529			2,786
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	756			490			2,291			1,580
Operating and maintenance expense	113			73			306			205
Operating and maintenance expense—affiliate	31			31			87			70
Development expense	1			1			2			2
General and administrative expense	3			5			9			10
General and administrative expense—affiliate	18			18			53			63
Depreciation and amortization expense	107			87			318			239
Impairment expense and loss on disposal of assets	8			—			8			—
Other	—			1			—			1
Total operating costs and expenses	1,037			706			3,074			2,170
Income from operations	492			197			1,455			616
Other income (expense)
Interest expense, net of capitalized interest	(183		)	(153		)	(552		)	(437		)
Loss on modification or extinguishment of debt	(12		)	(25		)	(12		)	(67		)
Derivative gain (loss), net	2			1			13			(2		)
Other income	8			3			19			6
Total other expense	(185		)	(174		)	(532		)	(500		)
Net income	$	307		$	23		$	923		$	116
Basic and diluted net income (loss) per common unit	$	0.60		$	(1.10	)	$	1.82		$	(4.12	)
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation	348.6			247.2			348.6			121.2

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

4

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY

(in millions)

(unaudited)

	Common Unitholders’ Interest				Subordinated Unitholder’s Interest				General Partner’s Interest				Total Partners’ Equity
	Units	Amount			Units	Amount			Units	Amount
Balance at December 31, 2017	348.6	$	1,670		135.4	$	(1,043	)	9.9	$	12		$	639
Net income	—	651			—	253			—	19			923
Distributions	—	(562		)	—	(218		)	—	(34		)	(814		)
Balance at September 30, 2018	348.6	$	1,759		135.4	$	(1,008	)	9.9	$	(3	)	$	748

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

5

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Nine Months Ended September 30,
	2018			2017
Cash flows from operating activities
Net income	$	923		$	116
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	318			239
Amortization of debt issuance costs, deferred commitment fees, premium and discount	24			28
Loss on modification or extinguishment of debt	12			67
Total losses on derivatives, net	29			53
Net cash used for settlement of derivative instruments	—			(15		)
Impairment expense and loss on disposal of assets	8			—
Other	5			1
Changes in operating assets and liabilities:
Accounts and other receivables	(33		)	(69		)
Accounts receivable—affiliate	140			82
Advances to affiliate	(79		)	(36		)
Inventory	6			28
Accounts payable and accrued liabilities	(77		)	19
Due to affiliates	(5		)	(47		)
Deferred revenue	6			58
Other, net	(10		)	(9		)
Other, net—affiliate	(3		)	(2		)
Net cash provided by operating activities	1,264			513
Cash flows from investing activities
Property, plant and equipment, net	(578		)	(1,195		)
Net cash used in investing activities	(578		)	(1,195		)
Cash flows from financing activities
Proceeds from issuances of debt	1,100			3,814
Repayments of debt	(1,090		)	(2,173		)
Debt issuance and deferred financing costs	(8		)	(47		)
Debt extinguishment costs	(6		)	—
Distributions to owners	(814		)	(74		)
Net cash provided by (used in) financing activities	(818		)	1,520
Net increase (decrease) in cash, cash equivalents and restricted cash	(132		)	838
Cash, cash equivalents and restricted cash—beginning of period	1,589			605
Cash, cash equivalents and restricted cash—end of period	$	1,457		$	1,443

Balances per Consolidated Balance Sheet:

	September 30,
	2018
Cash and cash equivalents	$	—
Restricted cash	1,457
Total cash, cash equivalents and restricted cash	$	1,457

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

6

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, 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 undergoing commissioning and Train 6 is being commercialized and has all necessary regulatory approvals in place. The Sabine Pass LNG terminal has operational regasification facilities owned by SPLNG and a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL.

Basis of Presentation

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

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

Results of operations for the three and nine months ended September 30, 2018 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2018.

We are not subject to either federal or state income tax, as our partners are taxed individually on their allocable share of our taxable income.

NOTE 2—UNITHOLDERS’ EQUITY

The common units and subordinated units represent limited partner interests in us. The holders of the units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from operating surplus as defined in the partnership agreement.

The holders of common units have the right to receive initial quarterly distributions of $0.425 per common unit, plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. The holders of subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distribution requirement for our common unitholders and general partner and certain reserves.  Subordinated units will convert into common units on a one-for-one basis when we meet financial tests specified in the partnership agreement. Although common and subordinated unitholders are not obligated to fund losses of the Partnership, their capital accounts, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continue to share in losses.

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights (“IDRs”), which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are

7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

During the three months ended September 30, 2018, Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”), which holds limited partner interests in us, merged with a wholly owned subsidiary of Cheniere. As of September 30, 2018, Cheniere, Blackstone CQP Holdco and the public own a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere’s ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.

NOTE 3—RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2018 and December 31, 2017, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	649	$	544
Cash held by us and our guarantor subsidiaries	808		1,045
Total current restricted cash	$	1,457	$	1,589

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

Under our credit facilities (the “CQP Credit Facilities”), we and each of our subsidiaries other than SPL, as our guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the CQP Credit Facilities and the related depositary agreement governing the extension of credit to us. Specifically, we may only withdraw funds from collateral accounts held at a designated depositary bank on a limited basis and for specific purposes, including for the payment of our operating expenses and the operating expenses of our guarantor subsidiaries. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2018 and December 31, 2017, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
SPL trade receivable	$	213	$	185
Other accounts receivable	11		6
Total accounts and other receivables	$	224	$	191

NOTE 5—INVENTORY

As of September 30, 2018 and December 31, 2017, inventory consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Natural gas	$	9	$	17
LNG	21		26
Materials and other	58		52
Total inventory	$	88	$	95

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

As of September 30, 2018 and December 31, 2017, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	12,706		$	12,703
LNG terminal construction-in-process	3,757			3,310
Accumulated depreciation	(1,187		)	(880		)
Total LNG terminal costs, net	15,276			15,133
Fixed assets
Fixed assets	26			23
Accumulated depreciation	(20		)	(17		)
Total fixed assets, net	6			6
Property, plant and equipment, net	$	15,282		$	15,139

Depreciation expense was $104 million and $85 million during the three months ended September 30, 2018 and 2017, respectively, and $310 million and $233 million during the nine months ended September 30, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $79 million and $242 million in the three and nine months ended September 30, 2017, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three and nine months ended September 30, 2018.

NOTE 7—DERIVATIVE INSTRUMENTS

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

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

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

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 September 30, 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 Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2018									December 31, 2017
	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
CQP Interest Rate Derivatives asset	$	—		$	28	$	—	$	28	$	—	$	21	$	—	$	21
Liquefaction Supply Derivatives asset (liability)	(1		)	1		19		19		2		10		43		55

There have been no changes to our evaluation of and accounting for our derivative positions during the nine months ended September 30, 2018. See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information.

9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a 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 Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2018:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$19	Market approach incorporating present value techniques	Basis Spread	$(0.448) - $0.079

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Balance, beginning of period	$	11		$	40		$	43		$	79
Realized and mark-to-market gains (losses):
Included in cost of sales	4			(8		)	(5		)	(43		)
Purchases and settlements:
Purchases	4			(1		)	8			1
Settlements	1			(2		)	(27		)	(8		)
Transfers out of Level 3 (1)	(1		)	—			—			—
Balance, end of period	$	19		$	29		$	19		$	29
Change in unrealized gains relating to instruments still held at end of period	$	4		$	(8	)	$	(5	)	$	(43	)

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

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for 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.

10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Interest Rate Derivatives

We had entered into interest rate swaps (“CQP Interest Rate Derivatives”) to hedge a portion of the variable interest payments on the CQP Credit Facilities, based on a portion of the expected outstanding borrowings over the term of the CQP Credit Facilities. In September 2018, we terminated approximately $1.2 billion of commitments under the CQP Credit Facilities, as discussed in Note 10—Debt. In October 2018, we terminated the CQP Interest Rate Derivatives related to the CQP Credit Facilities, which resulted in a derivative gain of $28 million.

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

As of September 30, 2018, we had the following Interest Rate Derivatives outstanding:

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
CQP Interest Rate Derivatives	$225 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR

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

	September 30,		December 31,
Consolidated Balance Sheet Location	2018		2017
Other current assets	$	19	$	7
Non-current derivative assets	9		14
Total derivative assets	$	28	$	21

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Income during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
CQP Interest Rate Derivatives gain	$	2	$	1	$	13	$	—
SPL Interest Rate Derivatives loss	—		—		—		(2		)

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the physical natural gas supply contracts range up to six years, some of which commence upon the satisfaction of certain conditions precedent.

SPL had secured up to approximately 2,755TBtu and 2,214TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2018 and December 31, 2017, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 2,206TBtu and 1,520TBtu as of September 30, 2018 and December 31, 2017, respectively.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	September 30, 2018			December 31, 2017
Other current assets	$	11		$	41
Non-current derivative assets	16			17
Total derivative assets	27			58
Derivative liabilities	(6		)	—
Non-current derivative liabilities	(2		)	(3		)
Total derivative liabilities	(8		)	(3		)
Derivative asset, net	$	19		$	55

(1) Does not include collateral calls of $2 million and $1 million as of September 30, 2018 and December 31, 2017, respectively, for such contracts, which are included in other current assets in our Consolidated Balance Sheets.

The following table shows the changes in the fair value and settlements of our Liquefaction Supply Derivatives recorded in cost of sales on our Consolidated Statements of Income during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018			2017
Liquefaction Supply Derivatives gain (loss) (1)	$	10	$	(11	)	$	(42	)	$	(51	)

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

Consolidated Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2018
CQP Interest Rate Derivatives	$	28		$	—		$	28
Liquefaction Supply Derivatives	31			(4		)	27
Liquefaction Supply Derivatives	(13		)	5			(8		)
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

12

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—OTHER NON-CURRENT ASSETS

As of September 30, 2018 and December 31, 2017, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	15	$	26
Advances made to municipalities for water system enhancements	90		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	17		25
Information technology service assets	20		24
Other	8		8
Total other non-current assets, net	$	179	$	206

NOTE 9—ACCRUED LIABILITIES

As of September 30, 2018 and December 31, 2017, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Interest costs and related debt fees	$	186	$	253
Accrued natural gas purchases	249		298
LNG terminal and related pipeline costs	59		86
Other accrued liabilities	9		—
Total accrued liabilities	$	503	$	637

NOTE 10—DEBT

As of September 30, 2018 and December 31, 2017, our debt consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			—
CQP Credit Facilities	—			1,090
Unamortized premium, discount and debt issuance costs, net	(191		)	(194		)
Total long-term debt, net	16,059			16,046
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	16,059		$	16,046

13

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

2018 Debt Issuances and Redemptions

2026 CQP Senior Notes

In September 2018, we issued an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP. Net proceeds of the offering of approximately $1.1 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay all of the outstanding indebtedness under the CQP Credit Facilities, resulting in the recognition of debt modification and extinguishment costs of $12 million for the three and nine months ended September 30, 2018 relating to the incurrence of third party fees and write off of unamortized debt issuance costs. As of September 30, 2018, only a $115 million revolving credit facility, all of which is undrawn, remains as part of the CQP Credit Facilities.

Borrowings under the 2026 CQP Senior Notes accrue interest at a fixed rate of 5.625%, and interest on the 2026 CQP Senior Notes is payable semi-annually in arrears. The 2026 CQP Senior Notes are governed by the same base indenture as the 2025 CQP Senior Notes (the “CQP Base Indenture”), and are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

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

The 2026 CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. After applying the proceeds from the 2026 CQP Senior Notes, the 2026 CQP Senior Notes and the 2025 CQP Senior Notes(collectively, the “CQP Senior Notes”) became unsecured. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the CQP Credit Facilities. The obligations under the CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the Guarantors and equity interests in the Guarantors (except, in each case, for certain excluded properties set forth in the CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the CQP Credit Facilities).

In connection with the closing of the 2026 CQP Senior Notes offering, we and the Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, we and the Guarantors have agreed to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2026 CQP Senior Notes for a like aggregate principal amount of our debt securities with terms identical in all material respects to the 2026 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after the notes issuance date of September 11, 2018. Under specified circumstances, we and the Guarantors have also agreed to cause to become effective a shelf registration statement relating to resales of the 2026 CQP Senior Notes. We will be obligated to pay additional interest on the 2026 CQP Senior Notes if we fail to comply with our obligation to register the 2026 CQP Senior Notes within the specified time period.

14

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2018 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		2,685
Letters of credit issued	494		—
Available commitment	$	706	$	115
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020

(1) There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

Restrictive Debt Covenants

As of September 30, 2018, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Total interest cost	$	235		$	227		$	701		$	662
Capitalized interest	(52		)	(74		)	(149		)	(225		)
Total interest expense, net	$	183		$	153		$	552		$	437

Fair Value Disclosures

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

	September 30, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	15,268	$	16,098	$	14,166	$	15,485
2037 SPL Senior Notes (2)	791		831		790		871
Credit facilities (3)	—		—		1,090		1,090

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

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

(3) Includes SPL Working Capital Facility and CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. 

15

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
LNG revenues	$	1,185	$	717	$	3,302	$	1,695
LNG revenues—affiliate	205		111		886		864
Regasification revenues	66		65		196		195
Other revenues	9		3		28		7
Other revenues—affiliate	—		1		—		2
Total revenues from customers	1,465		897		4,412		2,763
Gains from derivative instruments (1)	64		6		117		23
Total revenues	$	1,529	$	903	$	4,529	$	2,786

(1) Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

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 transfer 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 exception for allocating variable consideration to specific parts of the contract. 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 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.

Regasification Revenues

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

16

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

Upon substantial completion of Train 3 of the Liquefaction Project, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During each of the three months ended September 30, 2018 and 2017, SPL recorded $7.5 million and during the nine months ended September 30, 2018 and 2017, SPL recorded $23 million and $15 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

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

	Nine Months Ended September 30, 2018
Deferred revenues, beginning of period	$	111
Cash received but not yet recognized	119
Revenue recognized from prior period deferral	(111		)
Deferred revenues, end of period	$	119

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 nine months ended September 30, 2018 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 September 30, 2018:

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	54.2	10.2
Regasification revenues	2.7		5.8
Total revenues	$	56.9

(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.

17

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During each of the three and nine months ended September 30, 2018, approximately 55% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 3% of our regasification revenues were related to variable consideration received from customers.

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

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 December 31, 2017.

NOTE 12—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	205	$	111	$	886	$	864
Other revenues—affiliate
Terminal Marine Services Agreement	—		1		—		2
Operating and maintenance expense—affiliate
Services Agreements	31		25		87		64
Other agreements	—		6		—		6
Total operating and maintenance expense—affiliate	31		31		87		70
General and administrative expense—affiliate
Services Agreements	18		18		53		63

LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036.

In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is recorded as operating and maintenance expense on our Consolidated Statements of Income.

18

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay the TUA Fees required by the TUA to SPLNG. However, the revenue earned by SPLNG from the TUA Fees and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our Consolidated Financial Statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA.

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing during the three and nine months ended September 30, 2018 and 2017 related to the Amended and Restated VCRA.

Cheniere Marketing SPA

Cheniere Marketing has an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL 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

SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement. SPL 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.

Services Agreements

As of September 30, 2018 and December 31, 2017, we had $189 million and $36 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Cheniere Partners Services Agreement

We have a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $3 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments 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.

SPLNG O&M Agreement

SPLNG has a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SPLNG pays a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between SPLNG and Cheniere Investments at the beginning of each operating year. In addition, SPLNG is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the

19

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPLNG O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to such subsidiary.

SPLNG MSA

SPLNG has a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the SPLNG O&M Agreement. SPLNG pays a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

SPL O&M Agreement

SPL has an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments pursuant to which SPL receives 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 behalf of SPL, 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, SPL is 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, SPL 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. Cheniere Investments provides the services required under the SPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPL O&M Agreement are required to be remitted to such subsidiary.

SPL MSA

SPL has a management services agreement (the “SPL 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 SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s business and operations, entering into financial derivatives on SPL’s 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, SPL pays a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

CTPL O&M Agreement

CTPL has an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M Agreement are required to be remitted to such subsidiary.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represented an aggregate commitment of $25 million in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments

20

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

to Cheniere Marketing equal to ad valorem tax levied on our LNG terminal in the year the Cameron Parish dollar-for-dollar credit is applied.

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of September 30, 2018, we had $2 million in due to affiliates and $23 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing. As of December 31, 2017, we had $25 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. The agreement also provides that Tug Services shall contingently pay the wholly owned subsidiary of Cheniere a portion of its future revenues. Accordingly, Tug Services distributed $4 million to the wholly owned subsidiary of Cheniere during the nine months ended September 30, 2018, which is reported as part of the distributions to our general partner interest holders on the Consolidated Statement of Partners’ Equity. No amounts were distributed during the nine months ended September 30, 2017.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the three and nine months ended September 30, 2018 and 2017.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG 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, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its 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 SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

SPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPL 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, SPL will pay to Cheniere an amount equal to the state and local tax that SPL would be required to pay if SPL’s 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 SPL under this agreement; therefore, Cheniere has not demanded any such payments from SPL. The agreement is effective for tax returns due on or after August 2012.

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL 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, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s 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 CTPL

21

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013.

NOTE 13—NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statement of Partners’ Equity. On October 26, 2018, we declared a $0.58 distribution per common unit and subordinated unit and the related distribution to our general partner and IDR holders to be paid on November 14, 2018 to unitholders of record as of November 5, 2018 for the period from July 1, 2018 to September 30, 2018.

The two-class method dictates that net income (loss) for a period be reduced by the amount of available cash that will be distributed with respect to that period and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and other participating securities on a pro rata basis based on provisions of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

The Class B units, which were mandatorily converted into our common units in accordance with the terms of our partnership agreement on August 2, 2017, were issued at a discount to the market price of the common units into which they were convertible.  This discount, totaling $2,130 million, represented a beneficial conversion feature and was reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statement of Partners’ Equity.  The beneficial conversion feature was considered a dividend that was distributed ratably with respect to any Class B unit from its issuance date through its conversion date, which resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortized the beneficial conversion feature through the mandatory conversion date of August 2, 2017 using the effective yield method, with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ previously held Class B units and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature was also included in earnings per unit for the three and nine months ended September 30, 2017.

22

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table provides a reconciliation of net income and the allocation of net income to the common units, the subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income (loss) per unit (in millions, except per unit data).

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner Units			IDR
Three Months Ended September 30, 2018
Net income	$	307
Declared distributions	297			202			—		79			5			11
Assumed allocation of undistributed net income (1)	$	10		7			—		3			—			—
Assumed allocation of net income				$	209		$	—	$	82		$	5		$	11
Weighted average units outstanding				348.6			—		135.4
Basic and diluted net income per unit (2)				$	0.60				$	0.60
Three Months Ended September 30, 2017
Net income	$	23
Declared distributions	217			153			—		60			4			—
Amortization of beneficial conversion feature of Class B units	—			(288		)	974		(686		)	—			—
Assumed allocation of undistributed net loss	$	(194	)	(137		)	—		(53		)	(4		)	—
Assumed allocation of net income				$	(272	)	$	974	$	(679	)	$	—		$	—
Weighted average units outstanding				247.2			50.6		135.4
Basic and diluted net loss per unit (2)				$	(1.10	)			$	(5.02	)
Nine Months Ended September 30, 2018
Net income	$	923
Declared distributions	859			589			—		229			17			24
Assumed allocation of undistributed net income (1)	$	64		45			—		18			1			—
Assumed allocation of net income				$	634		$	—	$	247		$	18		$	24
Weighted average units outstanding				348.6			—		135.4
Basic and diluted net income per unit				$	1.82				$	1.82
Nine Months Ended September 30, 2017
Net income	$	116
Declared distributions	267			202			—		60			5			—
Amortization of beneficial conversion feature of Class B units	—			(594		)	2,004		(1,410		)	—			—
Assumed allocation of undistributed net loss	$	(151	)	(107		)	—		(41		)	(3		)	—
Assumed allocation of net income				$	(499	)	$	2,004	$	(1,391	)	$	2		$	—
Weighted average units outstanding				121.2			113.4		135.4
Basic and diluted net loss per unit (2)				$	(4.12	)			$	(10.28	)

(1) Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss).

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

23

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 14—CUSTOMER CONCENTRATION

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

	Percentage of Total Third-Party Revenues				Percentage of Accounts Receivable from Third Parties
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2018	2017	2018	2017	2018	2017
Customer A	24%	31%	27%	42%	28%	39%
Customer B	21%	24%	22%	26%	26%	32%
Customer C	21%	35%	23%	18%	22%	26%
Customer D	24%	—%	18%	—%	19%	—%

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	586	$	459

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $204 million and $247 million as of September 30, 2018 and 2017, respectively.

24

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 16—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of a recent accounting standard that had not been adopted by us as of September 30, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	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 may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated 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 anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We anticipate electing the optional transition method to initially apply the standard at the January 1, 2019 adoption date. 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 also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

NOTE 17—SUPPLEMENTAL GUARANTOR INFORMATION

Our CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the CQP Indenture. See Note 10—Debt in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information regarding the CQP Senior Notes.

The following is condensed consolidating financial information for CQP (“Parent Issuer”), the Guarantors on a combined basis and the Non-Guarantors on a combined basis. We have accounted for investments in subsidiaries using the equity method.

26

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Balance Sheet
September 30, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	799		9		649		—			1,457
Accounts and other receivables	1		1		222		—			224
Accounts receivable—affiliate	1		46		21		(46		)	22
Advances to affiliate	—		100		174		(85		)	189
Inventory	—		12		76		—			88
Other current assets	19		1		35		—			55
Other current assets—affiliate	—		—		21		(21		)	—
Total current assets	820		169		1,198		(152		)	2,035
Property, plant and equipment, net	79		2,136		13,091		(24		)	15,282
Debt issuance costs, net	1		—		14		—			15
Non-current derivative assets	9		—		16		—			25
Investments in subsidiaries	2,449		347		—		(2,796		)	—
Other non-current assets, net	—		27		152		—			179
Total assets	$	3,358	$	2,679	$	14,471	$	(2,972	)	$	17,536
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	1	$	5	$	7	$	—		$	13
Accrued liabilities	44		20		439		—			503
Due to affiliates	—		132		52		(131		)	53
Deferred revenue	—		24		95		—			119
Deferred revenue—affiliate	—		21		—		(21		)	—
Derivative liabilities	—		—		6		—			6
Total current liabilities	45		202		599		(152		)	694
Long-term debt, net	2,565		—		13,494		—			16,059
Non-current derivative liabilities	—		—		2		—			2
Other non-current liabilities	—		5		5		—			10
Other non-current liabilities—affiliate	—		23		—		—			23
Partners’ equity	748		2,449		371		(2,820		)	748
Total liabilities and partners’ equity	$	3,358	$	2,679	$	14,471	$	(2,972	)	$	17,536

27

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Balance Sheet
December 31, 2017
(in millions)
	Parent Issuer		Guarantors			Non-Guarantors			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—		$	—		$	—		$	—
Restricted cash	1,033		12			544			—			1,589
Accounts and other receivables	—		2			189			—			191
Accounts receivable—affiliate	—		36			163			(36		)	163
Advances to affiliate	—		20			26			(10		)	36
Inventory	—		10			85			—			95
Other current assets	8		3			54			—			65
Other current assets—affiliate	—		—			21			(21		)	—
Total current assets	1,041		83			1,082			(67		)	2,139
Property, plant and equipment, net	80		2,164			12,920			(25		)	15,139
Debt issuance costs, net	20		—			18			—			38
Non-current derivative assets	14		—			17			—			31
Investments in subsidiaries	2,076		(63		)	—			(2,013		)	—
Other non-current assets, net	—		37			169			—			206
Total assets	$	3,231	$	2,221		$	14,206		$	(2,105	)	$	17,553
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4		$	8		$	—		$	12
Accrued liabilities	23		8			606			—			637
Due to affiliates	—		47			66			(45		)	68
Deferred revenue	—		27			84			—			111
Deferred revenue—affiliate	—		22			—			(21		)	1
Other current liabilities—affiliate	—		1			—			(1		)	—
Total current liabilities	23		109			764			(67		)	829
Long-term debt, net	2,569		—			13,477			—			16,046
Non-current derivative liabilities	—		—			3			—			3
Other non-current liabilities	—		11			—			—			11
Other non-current liabilities—affiliate	—		25			—			—			25
Partners’ equity (deficit)	639		2,076			(38		)	(2,038		)	639
Total liabilities and partners’ equity (deficit)	$	3,231	$	2,221		$	14,206		$	(2,105	)	$	17,553

28

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,249		$	—		$	1,249
LNG revenues—affiliate	—			—			205			—			205
Regasification revenues	—			66			—			—			66
Regasification revenues—affiliate	—			64			—			(64		)	—
Other revenues	—			9			—			—			9
Other revenues—affiliate	—			48			—			(48		)	—
Total revenues	—			187			1,454			(112		)	1,529
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			758			(2		)	756
Cost of sales—affiliate	—			—			8			(8		)	—
Operating and maintenance expense	—			17			96			—			113
Operating and maintenance expense—affiliate	—			39			107			(115		)	31
Development expense	—			1			—			—			1
General and administrative expense	1			1			1			—			3
General and administrative expense—affiliate	3			6			12			(3		)	18
Depreciation and amortization expense	1			19			88			(1		)	107
Impairment expense and loss on disposal of assets	—			8			—			—			8
Total operating costs and expenses	5			91			1,070			(129		)	1,037
Income (loss) from operations	(5		)	96			384			17			492
Other income (expense)
Interest expense, net of capitalized interest	(36		)	(1		)	(146		)	—			(183		)
Loss on modification or extinguishment of debt	(12		)	—			—			—			(12		)
Derivative gain, net	2			—			—			—			2
Equity earnings of subsidiaries	354			243			—			(597		)	—
Other income (expense)	4			(1		)	5			—			8
Total other income (expense)	312			241			(141		)	(597		)	(185		)
Net income	$	307		$	337		$	243		$	(580	)	$	307

29

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	723		$	—		$	723
LNG revenues—affiliate	—			—			111			—			111
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			48			—			(48		)	—
Other revenues	—			3			—			—			3
Other revenues—affiliate	—			51			—			(50		)	1
Total revenues	—			167			834			(98		)	903
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	—			(1		)	488			3			490
Cost of sales—affiliate	—			—			5			(5		)	—
Operating and maintenance expense	1			7			65			—			73
Operating and maintenance expense—affiliate	6			33			82			(90		)	31
Development expense	—			—			1			—			1
General and administrative expense	1			1			3			—			5
General and administrative expense—affiliate	3			6			12			(3		)	18
Depreciation and amortization expense	1			17			69			—			87
Other	—			1			—			—			1
Total operating costs and expenses	12			64			725			(95		)	706
Income (loss) from operations	(12		)	103			109			(3		)	197
Other income (expense)
Interest expense, net of capitalized interest	(29		)	—			(124		)	—			(153		)
Loss on modification or extinguishment of debt	(25		)	—			—			—			(25		)
Derivative gain, net	1			—			—			—			1
Equity earnings (losses) of subsidiaries	88			(12		)	—			(76		)	—
Other income	—			—			3			—			3
Total other income (expense)	35			(12		)	(121		)	(76		)	(174		)
Net income (loss)	$	23		$	91		$	(12	)	$	(79	)	$	23

30

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	3,419		$	—		$	3,419
LNG revenues—affiliate	—			—			886			—			886
Regasification revenues	—			196			—			—			196
Regasification revenues—affiliate	—			194			—			(194		)	—
Other revenues	—			28			—			—			28
Other revenues—affiliate	—			183			—			(183		)	—
Total revenues	—			601			4,305			(377		)	4,529
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			2			2,291			(2		)	2,291
Cost of sales—affiliate	—			—			23			(23		)	—
Operating and maintenance expense	—			48			258			—			306
Operating and maintenance expense—affiliate	—			113			317			(343		)	87
Development expense	—			1			1			—			2
General and administrative expense	3			2			4			—			9
General and administrative expense—affiliate	9			17			36			(9		)	53
Depreciation and amortization expense	2			56			261			(1		)	318
Impairment expense and loss on disposal of assets	—			8			—			—			8
Total operating costs and expenses	14			247			3,191			(378		)	3,074
Income (loss) from operations	(14		)	354			1,114			1			1,455
Other income (expense)
Interest expense, net of capitalized interest	(104		)	(3		)	(445		)	—			(552		)
Loss on modification or extinguishment of debt	(12		)	—			—			—			(12		)
Derivative gain, net	13			—			—			—			13
Equity earnings of subsidiaries	1,030			678			—			(1,708		)	—
Other income	10			—			9			—			19
Total other income (expense)	937			675			(436		)	(1,708		)	(532		)
Net income	$	923		$	1,029		$	678		$	(1,707	)	$	923

31

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,718		$	—		$	1,718
LNG revenues—affiliate	—			—			864			—			864
Regasification revenues	—			195			—			—			195
Regasification revenues—affiliate	—			128			—			(128		)	—
Other revenues	—			7			—			—			7
Other revenues—affiliate	—			162			—			(160		)	2
Total revenues	—			492			2,582			(288		)	2,786
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			1			1,576			3			1,580
Cost of sales—affiliate	—			—			15			(15		)	—
Operating and maintenance expense	4			29			172			—			205
Operating and maintenance expense—affiliate	6			96			224			(256		)	70
Development expense	—			—			2			—			2
General and administrative expense	3			2			5			—			10
General and administrative expense—affiliate	9			19			46			(11		)	63
Depreciation and amortization expense	1			55			183			—			239
Other	—			1			—			—			1
Total operating costs and expenses	23			203			2,223			(279		)	2,170
Income (loss) from operations	(23		)	289			359			(9		)	616
Other income (expense)
Interest expense, net of capitalized interest	(81		)	—			(356		)	—			(437		)
Loss on modification or extinguishment of debt	(25		)	—			(42		)	—			(67		)
Derivative loss, net	—			—			(2		)	—			(2		)
Equity earnings (losses) of subsidiaries	244			(36		)	—			(208		)	—
Other income	1			—			5			—			6
Total other income (expense)	139			(36		)	(395		)	(208		)	(500		)
Net income (loss)	$	116		$	253		$	(36	)	$	(217	)	$	116

32

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by operating activities	$	339		$	408		$	928		$	(411	)	$	1,264
Cash flows from investing activities
Property, plant and equipment, net	—			(24		)	(554		)	—			(578		)
Investments in subsidiaries	(202		)	(81		)	—			283			—
Distributions received from affiliates, net	447			350			—			(797		)	—
Net cash provided by (used in) investing activities	245			245			(554		)	(514		)	(578		)
Cash flows from financing activities
Proceeds from issuances of debt	1,100			—			—			—			1,100
Repayments of debt	(1,090		)	—			—			—			(1,090		)
Debt issuance and deferred financing costs	(8		)	—			—			—			(8		)
Debt extinguishment costs	(6		)	—			—			—			(6		)
Distributions to parent	—			(858		)	(350		)	1,208			—
Contributions from parent	—			202			81			(283		)	—
Distributions to owners	(814		)	—			—			—			(814		)
Net cash used in financing activities	(818		)	(656		)	(269		)	925			(818		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(234		)	(3		)	105			—			(132		)
Cash, cash equivalents and restricted cash—beginning of period	1,033			12			544			—			1,589
Cash, cash equivalents and restricted cash—end of period	$	799		$	9		$	649		$	—		$	1,457

Balances per Condensed Consolidating Balance Sheet:

	September 30, 2018
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Restricted cash	799		9		649		—		1,457
Total cash, cash equivalents and restricted cash	$	799	$	9	$	649	$	—	$	1,457

33

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(89	)	$	293		$	317		$	(8	)	$	513
Cash flows from investing activities
Property, plant and equipment, net	—			(16		)	(1,187		)	8			(1,195		)
Investments in subsidiaries	(216		)	(7		)	—			223			—
Distributions received from affiliates, net	929			450			—			(1,379		)	—
Net cash provided by (used in) investing activities	713			427			(1,187		)	(1,148		)	(1,195		)
Cash flows from financing activities
Proceeds from issuances of debt	1,500			—			2,314			—			3,814
Repayments of debt	(1,470		)	—			(703		)	—			(2,173		)
Debt issuance and deferred financing costs	(18		)	—			(29		)	—			(47		)
Distributions to parent	—			(929		)	(450		)	1,379			—
Contributions from parent	—			216			7			(223		)	—
Distributions to owners	(74		)	—			—			—			(74		)
Net cash provided by (used in) financing activities	(62		)	(713		)	1,139			1,156			1,520
Net increase in cash, cash equivalents and restricted cash	562			7			269			—			838
Cash, cash equivalents and restricted cash—beginning of period	234			13			358			—			605
Cash, cash equivalents and restricted cash—end of period	$	796		$	20		$	627		$	—		$	1,443

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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 regarding our ability to pay distributions to our unitholders; 

• statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL; 

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

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

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

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

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

• statements regarding our planned development and construction of additional Trains, 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 Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis includes the following subjects: 

• Overview of Business 

• Overview of Significant Events

• Liquidity and Capital Resources 

• Results of Operations 

• Off-Balance Sheet Arrangements 

• Summary of Critical Accounting Estimates

• Recent Accounting Standards

Overview of Business

We are a publicly traded Delaware limited partnership formed by Cheniere. 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. Through our wholly owned subsidiary, SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminallocated in Cameron Parish, Louisiana, 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 undergoing commissioning 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, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.5 to 4.9 mtpa of LNG. Through our wholly owned subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. The Sabine Pass LNG terminal has operational regasification facilities owned by SPLNG and a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL.

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 October 31, 2018, more than 215 cargoes have been produced, loaded and exported from the Liquefaction Project year to date. To date, over 475 cumulative LNG cargoes have been exported from the Liquefaction Project, with deliveries to 29 countries and regions worldwide.

• In September 2018, feed gas was introduced to Train 5 of the Liquefaction Project as part of the commissioning process, and first LNG production from Train 5 occurred in October 2018.

Financial

• In September 2018, we issued an aggregate principal amount of $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”). Net proceeds of the offering of approximately $1.1 billion, after deducting commissions, fees and expenses, were used to prepay all of the outstanding indebtedness under our credit facilities (the “CQP Credit Facilities”). As of September 30, 2018, only a $115 million revolving credit facility, which is currently undrawn, remains as part of the CQP Credit Facilities.

36

• We reached the following contractual milestones:

◦ In June 2018, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC (“BG”) relating to Train 3 of the Liquefaction Project.

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

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at September 30, 2018 and December 31, 2017 (in millions):

	September 30,		December 31,
	2018		2017
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the following purposes:
Liquefaction Project	649		544
Cash held by us and our guarantor subsidiaries	808		1,045
Available commitments under the following credit facilities:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	706		470
CQP Credit Facilities	115		220

For additional information regarding our debt agreements, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

CQP Senior Notes

In September 2018, we issued an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, in addition to the existing $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”), which are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP. The 2025 CQP Senior Notes and the 2026 CQP Senior Notes(collectively, the “CQP Senior Notes”) are governed by the same base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture (together with the CQP Base Indenture, the “2025 CQP Notes Indenture”) and the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”). The 2025 CQP Notes Indenture and the 2026 CQP Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

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

The CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. After applying the proceeds from the 2026 CQP Senior Notes, the CQP Senior Notes became unsecured. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base

37

Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the CQP Credit Facilities. The obligations under the CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the Guarantors and equity interests in the Guarantors (except, in each case, for certain excluded properties set forth in the CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the CQP Credit Facilities obligations and any future additional senior secured debt obligations.

CQP Credit Facilities

In February 2016, we entered into the CQP Credit Facilities. The CQP Credit Facilities originally consisted of: (1) a $450 million CTPL tranche term loan that was used to prepay the $400 million term loan facility in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that was used to repay and redeem in November 2016 the approximately $2.1 billion of the senior notes previously issued by SPLNG, (3) a $125 million facility that could be used to satisfy a six-month debt service reserve requirement and (4) a $115 million revolving credit facility that may be used for general business purposes. In September 2017 and September 2018, we issued the 2025 CQP Senior Notes and the 2026 CQP Senior Notes, respectively, and the net proceeds were used to prepay the outstanding term loans under the CQP Credit Facilities. As of September 30, 2018, only a $115 million revolving credit facility, which is currently undrawn, remains as part of the CQP Credit Facilities.

The CQP Credit Facilities mature on February 25, 2020. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit our ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the CQP Credit Facilities, we are required to hedge not less than 50% of the variable interest rate exposure on its projected aggregate outstanding balance, maintain a minimum debt service coverage ratio of at least 1.15x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55x in order to incur additional indebtedness to refinance a portion of the existing obligations.

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

Sabine Pass LNG Terminal

Liquefaction Facilities

We are developing, constructing and operating the 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. Train 5 of the Liquefaction Project is undergoing commissioning and the following table summarizes the status as of September 30, 2018:

	Train 5
Overall project completion percentage	98.5%
Completion percentage of:
Engineering	100%
Procurement	100%
Subcontract work	92.7%
Construction	97.8%
Date of expected substantial completion	1Q 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

38

combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).

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

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

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

Customers

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

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.2 billion for Trains 1 through 3 and the SPA with GAIL for Train 4, increasing to $2.3 billion upon the date of first commercial delivery of Train 4 under the SPA with BG and to $2.9 billion upon the date of first commercial delivery of Train 5, with the applicable fixed fees starting from the date of first commercial delivery from the applicable Train, as specified in each SPA.

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

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of September 30, 2018, SPL had secured up to approximately 2,755TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts.

Construction

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

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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 September 30, 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.

Regasification Facilities

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

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 3 of the Liquefaction Project, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity.  This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During each of the three months ended September 30, 2018 and 2017, SPL recorded $7.5 million and during the nine months ended September 30, 2018 and 2017, SPL recorded $23 million and $15 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

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

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 5 of the 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 SPL 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. SPL 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 $79 million and $242 million in the three and nine months ended September 30, 2017, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations, during the testing phase for the construction of those Trains of the Liquefaction Project. We did not realize any offsets to LNG terminal costs in the three and nine months ended September 30, 2018. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

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The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at September 30, 2018 and December 31, 2017 (in millions):

	September 30,		December 31,
	2018		2017
Senior notes (1)	$	16,250	$	15,150
Credit facilities outstanding balance (2)	—		1,090
Letters of credit issued (3)	494		730
Available commitments under credit facilities (3)	706		470
Total capital resources from borrowings and available commitments	$	17,450	$	17,440

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

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

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

For additional information regarding our debt agreements related to the Sabine Pass LNG Terminal, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017.

SPL Senior Notes

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

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

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

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction

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Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million. As of September 30, 2018 and December 31, 2017, SPL had $706 million and $470 million of available commitments and $494 million and $730 million aggregate amount of issued letters of credit under the SPL Working Capital Facility, respectively. SPL did not have any amounts outstanding under the SPL Working Capital Facility as of both September 30, 2018 and December 31, 2017.

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

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

Restrictive Debt Covenants

As of September 30, 2018, we and SPL were in compliance with all covenants related to our respective debt agreements.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the nine months ended September 30, 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.

	Nine Months Ended September 30,
	2018			2017
Operating cash flows	$	1,264		$	513
Investing cash flows	(578		)	(1,195		)
Financing cash flows	(818		)	1,520
Net increase (decrease) in cash, cash equivalents and restricted cash	(132		)	838
Cash, cash equivalents and restricted cash—beginning of period	1,589			605
Cash, cash equivalents and restricted cash—end of period	$	1,457		$	1,443

Operating Cash Flows

Our operating cash inflows during the nine months ended September 30, 2018 and 2017 were $1.3 billion and $513 million, respectively. The $751 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. During the nine months ended September 30, 2018, Trains 1 through 4 were operational, whereas during the nine months ended September 30, 2017, Trains 1 and 2 were operational for nine months and Train 3 was operational for six months.

Investing Cash Flows

Investing cash outflows during the nine months ended September 30, 2018 and 2017 were $578 million and $1.2 billion, 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.

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Financing Cash Flows

Financing cash outflows during the nine months ended September 30, 2018 were $818 million, primarily as a result of:

• issuance of an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which was used to prepay $1.1 billion of the outstanding borrowings under the CQP Credit Facilities;

• $8 million of debt issuance costs related to up-front fees paid upon the closing of these transactions;

• $6 million in debt extinguishment costs related to the prepayment of the CQP Credit Facilities; and

• $814 million in distributions to unitholders.

Financing cash inflows during the nine months ended September 30, 2017 were $1.5 billion, primarily as a result of:

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

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

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

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

• $47 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and

• $74 million of distributions to unitholders.

Cash Distributions to Unitholders

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus. The following provides a summary of distributions paid by us during the nine months ended September 30, 2018 and 2017:

						Total Distribution (in millions)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Subordinated Units		General Partner Units		Incentive Distribution Rights
August 14, 2018	April 1 - June 30, 2018	$	0.56	$	0.56	$	195	$	76	$	6	$	7
May 15, 2018	January 1 - March 31, 2018	0.55		0.55		192		74		5		6
February 14, 2018	October 1 - December 31, 2017	0.50		0.50		174		68		5		1
August 11, 2017	April 1 - June 30, 2017	$	0.425	$	—	$	24	$	—	$	0.5	$	—
May 15, 2017	January 1 - March 31, 2017	0.425		—		24		—		0.5		—
February 13, 2017	October 1 - December 31, 2016	0.425		—		24		—		0.5		—

On October 26, 2018, we declared a $0.58 distribution per common unit and subordinated unit and the related distribution to our general partner and incentive distribution right holders to be paid on November 14, 2018 to unitholders of record as of November 5, 2018 for the period from July 1, 2018 to September 30, 2018.

The subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distributions requirement for our common unitholders and general partner along with certain reserves. Such available cash could be generated through new business development or fees received from Cheniere Marketing under an amended and restated variable capacity rights agreement pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development.

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Results of Operations

Our consolidated net income was $307 million, or $0.60 income per common unit (basic and diluted), in the three months ended September 30, 2018, compared to a net income of $23 million, or $1.10 loss per common unit (basic and diluted), in the three months ended September 30, 2017. This $284 million increase in net income in 2018 was primarily a result of increased income from operations due to additional Trains operating between the periods and decreased loss on modification or extinguishment of debt, which were partially offset by increased interest expense, net of amounts capitalized.

Our consolidated net income was $923 million, or $1.82 income per common unit (basic and diluted), in the nine months ended September 30, 2018, compared to a net income of $116 million, or $4.12 loss per common unit (basic and diluted), in the nine months ended September 30, 2017. This $807 million increase in net income in 2018 was primarily a result of increased income from operations due to additional Trains operating between the periods and decreased loss on modification or extinguishment of debt, which were partially offset by increased interest expense, net of amounts capitalized.

Revenues

	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions, except volumes)	2018		2017		Change			2018		2017		Change
LNG revenues	$	1,249	$	723	$	526		$	3,419	$	1,718	$	1,701
LNG revenues—affiliate	205		111		94			886		864		22
Regasification revenues	66		65		1			196		195		1
Other revenues	9		3		6			28		7		21
Other revenues—affiliate	—		1		(1		)	—		2		(2		)
Total revenues	$	1,529	$	903	$	626		$	4,529	$	2,786	$	1,743
LNG volumes recognized as revenues (in TBtu)	228		144		84			691		439		252

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 nine months ended September 30, 2018, Trains 1 through 4 were operational, whereas during the nine months ended September 30, 2017, Trains 1 and 2 were operational for nine months and Train 3 was operational for six months. The increase in revenues for the three and nine months ended September 30, 2018 from the comparable periods in 2017 was primarily attributable to the increased volume of LNG sold following the achievement of substantial completion of these Trains, as well as increased revenues per TBtu sold. 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 offsets to LNG terminal costs of $79 million corresponding to 14 TBtu of LNG in the three months ended September 30, 2017 and $242 million corresponding to 40 TBtu of LNG in the nine months ended September 30, 2017 that were 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 and nine months ended September 30, 2018.

Operating costs and expenses

	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions)	2018		2017		Change			2018		2017		Change
Cost of sales	$	756	$	490	$	266		$	2,291	$	1,580	$	711
Operating and maintenance expense	113		73		40			306		205		101
Operating and maintenance expense—affiliate	31		31		—			87		70		17
Development expense	1		1		—			2		2		—
General and administrative expense	3		5		(2		)	9		10		(1		)
General and administrative expense—affiliate	18		18		—			53		63		(10		)
Depreciation and amortization expense	107		87		20			318		239		79
Impairment expense and loss on disposal of assets	8		—		8			8		—		8
Other	—		1		(1		)	—		1		(1		)
Total operating costs and expenses	$	1,037	$	706	$	331		$	3,074	$	2,170	$	904

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Our total operating costs and expenses increased during the three and nine months ended September 30, 2018 from the three and nine months ended September 30, 2017, primarily as a result of additional Trains that were operating between the periods. There were four Trains operating during the nine months ended September 30, 2018, whereas two Trains were operating for nine months and a third Train was operating for six months during the comparable period in 2017.

Cost of sales increased during the three and nine months ended September 30, 2018 from the comparable periods in 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 and nine months ended September 30, 2018 from the comparable periods in 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 and nine months ended September 30, 2018 from the comparable periods in 2017, as a result of the increase in operating Trains during 2018. Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Project. The increase during the three and nine months ended September 30, 2018 from the comparable periods in 2017 was primarily related to natural gas transportation and storage capacity demand charges, third-party service and maintenance contract costs, payroll and benefit costs of operations personnel and TUA reservation charges from payments made under the partial TUA assignment agreement with Total. Operating and maintenance expense (including affiliates) also includes insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the three and nine months ended September 30, 2018 from the three and nine months ended September 30, 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.

Impairment expense and loss on disposal of assets increased during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. The impairment expense and loss on disposal of assets recognized during the nine months ended September 30, 2018 related to the write down of prepaid assets.

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 September 30,									Nine Months Ended September 30,
(in millions)	2018			2017			Change			2018			2017			Change
Interest expense, net of capitalized interest	$	183		$	153		$	30		$	552		$	437		$	115
Loss on modification or extinguishment of debt	12			25			(13		)	12			67			(55		)
Derivative loss (gain), net	(2		)	(1		)	(1		)	(13		)	2			(15		)
Other income	(8		)	(3		)	(5		)	(19		)	(6		)	(13		)
Total other expense	$	185		$	174		$	11		$	532		$	500		$	32

Interest expense, net of capitalized interest, increased during the three and nine months ended September 30, 2018 compared to the three and nine months ended September 30, 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 September 30, 2018 and 2017, we incurred $235 million and $227 million of total interest cost, respectively, of which we capitalized $52 million and $74 million, respectively, which was primarily related to the construction of the Liquefaction Project. For the nine months ended September 30, 2018 and 2017, we incurred $701 million and $662 million of total interest cost, respectively, of which we capitalized $149 million and $225 million, respectively, which was primarily related to the construction of the Liquefaction Project.

Loss on modification or extinguishment of debt decreased during the three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017. Loss on modification or extinguishment of debt of $12 million

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recognized in 2018 was attributable to the incurrence of third party fees and write off of unamortized debt issuance costs in September 2018 as a result of the termination of approximately $1.2 billion of commitments under the CQP Credit Facilities in connection with the issuance of the 2026 CQP Senior Notes. Loss on modification or extinguishment of debt recognized in 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 SPL’s previous credit facilities in connection with the issuance of the 2028 SPL Senior Notes and the 2037 SPL Senior Notes, in addition to the $25 million write-off of debt issuance costs in September 2017 related to the prepayment of $1.5 billion of the outstanding indebtedness under the CQP Credit Facilities in connection with the issuance of the 2025 CQP Senior Notes.

Derivative gain, net increased during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods. During the nine months ended September 30, 2017, the gain attributable to a relative increase in the long-term forward LIBOR curve during the period was partially offset by the $7 million loss in March recognized upon the termination of interest rate swaps associated with approximately $1.6 billion of commitments that were terminated under SPL’s previous credit facilities.

Off-Balance Sheet Arrangements

As of September 30, 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 consolidated financial position or operating results. 

Summary of Critical Accounting Estimates

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

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 16—Recent Accounting Standards of our Notes to Consolidated Financial Statements.

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 for the commissioning and operation of 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):

	September 30, 2018				December 31, 2017
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	19	$	3	$	55	$	5

Interest Rate Risk

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

	September 30, 2018				December 31, 2017
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
CQP Interest Rate Derivatives	$	28	$	5	$	21	$	5

See Note 7—Derivative Instruments for additional details about our derivative instruments.

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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 general partner’s management, including our general partner’s Chief Executive Officer and 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 general partner’s Chief Executive Officer and 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.

Please see Part II, Item 1, “Legal Proceedings” in our Quarterly Report on Form 10-Q for the period ended June 30, 2018.

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
4.1	Second Supplemental Indenture, dated as of September 11, 2018, among the Partnership, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on September 12, 2018)
10.1*	Fourth Omnibus Amendment, dated as of September 17, 2018, to (a) the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, by and among SPL, as Borrower, Société Générale, as the Common Security Trustee and as the Intercreditor Agent, The Bank of Nova Scotia, as the Secured Debt Holder Group Representative for the Working Capital Debt and other Secured Debt Holder Group Representatives party thereto from time to time, the Secured Hedge Representatives and the Secured Gas Hedge Representatives party thereto from time to time and (b) the Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated as of September 4, 2015, by and among SPL, as Borrower, Société Générale as the Swing Line Lender and as the Common Security Trustee, The Bank of Nova Scotia as the Senior Issuing Bank and Senior Facility Agent and the other agents and lenders from time to time party thereto
10.2	Registration Rights Agreement, dated as of September 11, 2018, among the Partnership, the guarantors party thereto and J.P. Morgan Securities LLC (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on September 12, 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.

49

SIGNATURES

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

		CHENIERE ENERGY PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC,
			its general partner
Date:	November 7, 2018	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	November 7, 2018	By:	/s/ Leonard E. Travis
			Leonard E. Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

50

EX-10.1

Exhibit 10.1

Execution Version

FOURTH OMNIBUS AMENDMENT

This Fourth Omnibus Amendment (this “Amendment”), dated as of September 17, 2018 amends (a) the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015 (as it may be further amended, restated, supplemented or otherwise modified from time to time, the “Common Terms Agreement”), by and among Sabine Pass Liquefaction, LLC, a Delaware limited liability company (the “Borrower”), Société Générale, as the Common Security Trustee (in such capacity, the “Common Security Trustee”) and as the Intercreditor Agent (in such capacity, the “Intercreditor Agent”), The Bank of Nova Scotia, as the Secured Debt Holder Group Representative for the Working Capital Debt and other Secured Debt Holder Group Representatives party thereto from time to time, the Secured Hedge Representatives and the Secured Gas Hedge Representatives party thereto from time to time and (b) the Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated as of September 4, 2015 (as it may be further amended, restated, supplemented or otherwise modified from time to time, the “Working Capital Facility”), by and among the Borrower, Société Générale as the Swing Line Lender and as the Common Security Trustee (in such capacity, the “Common Security Trustee”), The Bank of Nova Scotia as the Senior Issuing Bank and Senior Facility Agent (the “Facility Agent”) and the other agents and lenders from time to time party thereto. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Common Terms Agreement and, if not defined therein, the Working Capital Facility.

WHEREAS, the Borrower has requested that the Common Security Trustee, the Intercreditor Agent, the Secured Debt Holder Group Representative for the Working Capital Debt and the Working Capital Lenders (collectively, the “Lenders” and each individually, a “Lender”) constituting the Required Senior Lenders under the Working Capital Facility agree to amend the Common Terms Agreement and Working Capital Facility as set forth in Section 1 and Section 2 herein, respectively; and

WHEREAS, (a) the Secured Debt Holder Group Representative for the Working Capital Debt, the Common Security Trustee and the Intercreditor Agent are willing to amend the Common Terms Agreement as set forth in Section 1 herein and (b) the Facility Agent, each Lender party hereto and the Common Security Trustee are willing to amend the Working Capital Facility as set forth in Section 2 herein;

NOW, THEREFORE, in consideration of the foregoing premises and the agreements, provisions and covenants herein contained, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto agree as follows:

Section 1.Amendments to the Common Terms Agreement. Pursuant to Section 10.1 of the Common Terms Agreement and Section 4.1(i) of the Intercreditor Agreement, the Borrower, the Common Security Trustee, the Intercreditor Agent and the Secured Debt Holder

Group Representative for the Working Capital Debt hereby consent to the following amendments to the Common Terms Agreement:

1.1Clause (B) of the proviso of clause (c) of the definition of “Additional Material Project Document” in the Common Terms Agreement is hereby amended by replacing “until Train 6 Debt has been incurred” with “until the Train 6 FID Date”.

1.2Clause (C) of the proviso of clause (c) of the definition of “Additional Material Project Document” in the Common Terms Agreement is hereby amended and restated in its entirety as follows:

“(C)     until the Train 6 FID Date, any agreement containing obligations or liabilities of the Borrower which are not effective by their terms unless and until Train 6 FID has occurred (other than reimbursement obligations under any precedent agreement with a transporter not exceeding $25,000,000 in the aggregate for all precedent agreements entered into under this clause (C))”.

1.3The definition of “Train 6 FOB Sale and Purchase Agreement” in the Common Terms Agreement is hereby amended and restated in its entirety as follows:

““Train 6 FOB Sale and Purchase Agreement” means any LNG sale and purchase agreement entered into by the Borrower with respect to Train 6.”

1.4The following definition of “Train 6 FID” is hereby added to Schedule 1 of the Common Terms Agreement in the appropriate alphabetical order:

““Train 6 FID” means a positive final investment decision approved by the Borrower in accordance with all applicable requirements under the Borrower's Organic Documents in respect of the Train 6 Development to construct the liquefaction facilities and any other required facilities, or modify existing facilities, comprising Train 6.”

1.5The following definition of “Train 6 FID Date” is hereby added to Schedule 1 of the Common Terms Agreement in the appropriate alphabetical order:

““Train 6 FID Date” means the date on which Train 6 FID has occurred, as evidenced by copies of any resolution or other written documentation approving Train 6 FID delivered by or on behalf of the Borrower to the Common Security Trustee and Intercreditor Agent.”

1.6Each occurrence of the phrase “Train 6 Debt has been incurred” in the Common Terms Agreement is hereby replaced with the phrase “Train 6 Debt has been incurred or the Train 6 FID Date has occurred”.

1.7Clause (iii) of Section 4.12 in the Common Terms Agreement is hereby amended by replacing “and, to the extent incurred, Train 6 Debt” with “amounts available to make Restricted Payments pursuant to Section 5.01(c)(iii)(B) of the Accounts Agreement and, to the extent the Train 6 FID Date has occurred, Train 6 Debt or other Indebtedness permitted to be incurred by the Borrower under the Financing Documents”.

1.8The definition of “Construction Budget” in the Common Terms Agreement is hereby amended by replacing “the date on which Train 6 Debt is incurred” with “the date on which Train 6 Debt has been incurred or the Train 6 FID has occurred” in each of the two places such phrase appears.

1.9The definition of “Construction Schedule” in the Common Terms Agreement is hereby amended by replacing “the date on which Train 6 Debt is incurred” with “the date on which Train 6 Debt has been incurred or the Train 6 FID has occurred” in each of the two places such phrase appears.

1.10The definition of “Permitted Completion Costs” in the Common Terms Agreement is hereby amended by replacing “the revised Construction Budget delivered pursuant to Section 2.7(a)(xi) (Train 6 Debt)” with “the revised Construction Budget delivered pursuant to Section 2.7(a)(xi) (Train 6 Debt) or otherwise delivered on the Train 6 FID Date”.

Section 2.Amendments to the Working Capital Facility. Pursuant to Section 11.01 of the Working Capital Facility Agreement and Section 4.1(i) of the Intercreditor Agreement, the Borrower, the Common Security Trustee, the Intercreditor Agent and the Facility Agent (as the Secured Debt Holder Group Representative for the Working Capital Debt) hereby consent to the following modifications to the Common Terms Agreement:

2.1Each occurrence of the phrase “Train 6 Debt has been incurred” in the Working Capital Facility Agreement is hereby replaced with the phrase “Train 6 Debt has been incurred or the Train 6 FID Date has occurred”.

2.2Other than as specifically noted in Section 2.4 and Section 2.5 below, each occurrence of the phrase “Train 6 Debt Effective Date” in the Working Capital Facility Agreement is hereby replaced with the phrase “earlier of the Train 6 Debt Effective Date or the Train 6 FID Date”.

2.3Section 7.02(b)(i)(z)(G) of the Working Capital Facility Agreement is hereby amended by replacing the phrase “Train 6 Debt is incurred” with the phrase “Train 6 Debt is incurred or the Train 6 FID Date has occurred”.

2.4Section 9.01(b)(ix)(D)(III) of the Working Capital Facility Agreement is hereby amended by replacing the phrase “Train 6 Debt Effective Date” with “Train 6 Debt Effective Date or the Train 6 FID Date”.

2.5Section 2.13(a)(iv) of Schedule 8.01 of the Working Capital Facility Agreement is hereby amended by replacing each occurrence of the phrase “Train 6 Debt Effective Date” with “Train 6 Debt Effective Date or the Train 6 FID Date”.

Section 3.Effectiveness. This Amendment shall become effective as of the date hereof only upon the execution of this Amendment by the Common Security Trustee and receipt by the Common Security Trustee of executed counterparts of this Amendment by each of (a) the Borrower, (b) the Intercreditor Agent, (c) the Secured Debt Holder Group Representative for the Working Capital Debt (who constitutes the Majority Aggregate Secured Credit Facilities Debt Participants (as defined in the Intercreditor Agreement)), and (d) Lenders constituting the Required Senior Lenders under the Working Capital Facility.

Section 4.Representations and Warranties. The Borrower hereby represents and warrants to the Lenders that:

4.1no Default or Event of Default has occurred and is continuing as of the date hereof or will result from the consummation of the transactions contemplated by the Amendment; and

4.2each of the representations and warranties of the Borrower in the Common Terms Agreement, the Working Capital Facility and the other Financing Documents is true and correct in all material respects except for (A) those representations and warranties that are qualified by materiality, which shall be true and correct in all respects, on and as of the date hereof (or, if stated to have been made solely as of an earlier date, as of such earlier date) and (B) the representations and warranties that, pursuant to Section 4.1(b) (General) of the Common Terms Agreement, are not deemed repeated.

Section 5.Financing Document. This Amendment constitutes a Financing Document as such term is defined in, and for purposes of, the Common Terms Agreement.

Section 6.Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, UNITED STATES OF AMERICA, WITHOUT ANY REFERENCE TO THE CONFLICT OF LAW PRINCIPLES THEREOF (OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).

Section 7.Headings. All headings in this Amendment are included only for convenience and ease of reference and shall not be considered in the construction and interpretation of any provision hereof.

Section 8.Binding Nature and Benefit. This Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted assigns.

Section 9.Counterparts. This Amendment may be executed in multiple counterparts, each of which shall be deemed an original for all purposes, but all of which together

shall constitute one and the same instrument. Delivery of an executed counterpart of a signature page of this Amendment by facsimile or portable document format (“pdf”) shall be effective as delivery of a manually executed counterpart of this Amendment.

Section 10.No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Common Terms Agreement and the Working Capital Facility Agreement shall continue unchanged and shall remain in full force and effect. Each amendment granted herein shall apply solely to the matters set forth herein and such amendment shall not be deemed or construed as an amendment of any other matters, nor shall such amendment apply to any other matters.

Section 11.Direction to Secured Credit Facilities Debt Holder Group Representatives, Intercreditor Agent and Common Security Trustee.

a.by their signature below, each of the undersigned Lenders instructs the Secured Debt Holder Group Representative for the Working Capital Debt to (i) execute this Amendment and (ii) direct the Intercreditor Agent to execute this Amendment;

b.based on the instructions above, the Secured Debt Holder Group Representative for the Working Capital Debt, constituting the Majority Aggregate Secured Credit Facilities Debt Participants (as defined in the Intercreditor Agreement), hereby directs the Intercreditor Agent to (i) execute this Amendment and (ii) direct the Common Security Trustee to execute this Amendment; and

c.by its signature below, the Intercreditor Agent, in such capacity, hereby directs the Common Security Trustee to execute this Amendment.

[Remainder of the page left intentionally blank.]

IN WITNESS WHEREOF,the Parties have caused this Amendment to be duly executed by their officers thereunto duly authorized as of the day and year first above written.

SABINE PASS LIQUEFACTION, LLC,
as the Borrower
By:	/s/ Lisa C. Cohen
Name: Lisa C. Cohen
Title: Treasurer

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

SOCIÉTÉ GÉNÉRALE,
as Common Security Trustee and Secured
Debt Holder Group Representative for the
Commercial Banks Facility
By:	/s/ Ellen Turkel
Name: Ellen Turkel
Title: Director
SOCIÉTÉ GÉNÉRALE,
as the Intercreditor Agent
By:	/s/ Ellen Turkel
Name: Ellen Turkel
Title: Director
SOCIÉTÉ GÉNÉRALE,
as Commercial Bank Lender, Swing Line Lender
and Working Capital Lender
By:	/s/ Ellen Turkel
Name: Ellen Turkel
Title: Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

THE BANK OF NOVA SCOTIA, HOUSTON BRANCH
as the Secured Debt Holder Group Representative for the Working Capital Facility
By:	/s/ Alfredo Brahim
Name: Alfredo Brahim
Title: Director
THE BANK OF NOVA SCOTIA, HOUSTON BRANCH
as Senior Issuing Bank and Working Capital Lender
By:	/s/ Alfredo Brahim
Name: Alfredo Brahim
Title: Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

ABN AMRO CAPITAL USA LLC,
as Senior Issuing Bank and Working Capital Lender
By:	/s/ Casey Lowary
Name: Casey Lowary
Title: Managing Director
By:	/s/ Darrell Holley
Name: Darrell Holley
Title: Managing Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

MUFG BANK, LTD.,
as Working Capital Lender
By:	/s/ Saad Iqbal
Name: Saad Iqbal
Title: Managing Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

INDUSTRIAL AND COMMERCIAL BANK
OF CHINA LIMITED, NEW YORK BANK,
as Working Capital Lender
By:	/s/ Michael Fabisiak
Name: Michael Fabisiak
Title: Head of Project Finance, Americas
By:	/s/ N/A
Name:
Title:

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

ING CAPITAL LLC,
as Working Capital Lender
By:	/s/ Subha Pasumarti
Name: Subha Pasumarti
Title: Managing Director
By:	/s/ Hans Beekmans
Name: Hans Beekmans
Title: Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

LANDESBANK BADEN­-WÜRTTEMBERG,
NEW YORK BRANCH,
as Working Capital Lender
By:	/s/ Adam Rahal
Name: Adam Rahal
Title: Legal Counsel
By:	/s/ Michael Thier
Name: Michael Thier
Title: Senior Risk Manager

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

LLOYDS BANK PLC,
as Working Capital Lender
By:	/s/ Kamala Basdeo
Name: Kamala Basdeo
Title: Assistant Manager
	Transaction Execution
	Category A
	B002
By:	/s/ Jennifer Larrow
Name: Jennifer Larrow
Title: Assistant Manager
	Transaction Execution
	Category A
	L003

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

MORGAN STANLEY BANK, N.A.,
as Working Capital Lender
By:	/s/ Jake Dowden
Name: Jake Dowden
Title: Authorized Signatory

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

SUMITOMO MITSUI BANKING
CORPORATION,
as Working Capital Lender
By:	/s/ Juan Kreutz
Name: Juan Kreutz
Title: Managing Director

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

COMMONWEALTH BANK OF AUSTRALIA,
as Working Capital Lender
By its attorney under Power of Attorney dated
24 June 2013:
Signature of Attorney:	/s/ Annette Tomoski
Name of Attorney:	Annette Tomoski
Signed by its duly constituted attorney in the
presence of:
Signature of Witness:	/s/ Daniel Sardelic
Name of Witness:	Daniel Sardelic

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

Acknowledged and agreed as of the first date set forth above.

WELLS FARGO BANK, N.A.,
as Working Capital Lender
By:	/s/ J. Michael Quigley
Name: J. Michael Quigley
Title: Assistant Vice President

SIGNATURE PAGE TO FOURTH OMNIBUS AMENDMENT

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 Cheniere Energy Partners, L.P.;

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, including its consolidated subsidiaries, 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: November 7, 2018

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

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 Cheniere Energy Partners, L.P.;

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, including its consolidated subsidiaries, 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: November 7, 2018

/s/ Michael J. Wortley

Michael J. Wortley

Chief Financial Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

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 Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, 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 Partnership.

Date: November 7, 2018

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

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 Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Wortley, Chief Financial Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, 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 Partnership.

Date: November 7, 2018

/s/ Michael J. Wortley

Michael J. Wortley

Chief Financial Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 02, 2018
Entity Information [Line Items]
Entity Registrant Name	Cheniere Energy Partners, L.P.
Entity Central Index Key	0001383650
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Small Business	false
Entity Emerging Growth Company	false
Common Units [Member]
Entity Information [Line Items]
Entity Units, Units Outstanding		348,623,792
Subordinated Units [Member]
Entity Information [Line Items]
Entity Units, Units Outstanding		135,383,831

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 0	$ 0
Restricted cash	1,457	1,589
Accounts and other receivables	224	191
Accounts receivable—affiliate	22	163
Advances to affiliate	189	36
Inventory	88	95
Other current assets	55	65
Total current assets	2,035	2,139
Property, plant and equipment, net	15,282	15,139
Debt issuance costs, net	15	38
Non-current derivative assets	25	31
Other non-current assets, net	179	206
Total assets	17,536	17,553
Current liabilities
Accounts payable	13	12
Accrued liabilities	503	637
Due to affiliates	53	68
Deferred revenue	119	111
Deferred revenue—affiliate	0	1
Derivative liabilities	6	0
Total current liabilities	694	829
Long-term debt, net	16,059	16,046
Non-current derivative liabilities	2	3
Other non-current liabilities	10	11
Other non-current liabilities—affiliate	23	25
Partners’ equity
Common unitholders’ interest (348.6 million units issued and outstanding at September 30, 2018 and December 31, 2017)	1,759	1,670
Subordinated unitholders’ interest (135.4 million units issued and outstanding at September 30, 2018 and December 31, 2017)	(1,008)	(1,043)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2018 and December 31, 2017)	(3)	12
Total partners’ equity	748	639
Total liabilities and partners’ equity	$ 17,536	$ 17,553

XML

Consolidated Balance Sheets Parentheticals - shares shares in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
General Partner Ownership Interest Percentage	2.00%	2.00%
General Partners' Capital Account, Units Issued	9.9	9.9
General Partners' Capital Account, Units Outstanding	9.9	9.9
Common Units [Member]
Limited Partners' Capital Account, Units Issued	348.6	348.6
Limited Partners' Capital Account, Units Outstanding	348.6	348.6
Subordinated Units [Member]
Limited Partners' Capital Account, Units Issued	135.4	135.4
Limited Partners' Capital Account, Units Outstanding	135.4	135.4

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues
Revenue earned from contracts with customers	$ 1,465	$ 897	$ 4,412	$ 2,763
Revenues	1,529	903	4,529	2,786
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	756	490	2,291	1,580
Operating and maintenance expense	113	73	306	205
Operating and maintenance expense—affiliate	31	31	87	70
Development expense	1	1	2	2
General and administrative expense	3	5	9	10
General and administrative expense—affiliate	18	18	53	63
Depreciation and amortization expense	107	87	318	239
Impairment expense and loss on disposal of assets	8	0	8	0
Other	0	1	0	1
Total operating costs and expenses	1,037	706	3,074	2,170
Income (loss) from operations	492	197	1,455	616
Other income (expense)
Interest expense, net of capitalized interest	(183)	(153)	(552)	(437)
Loss on modification or extinguishment of debt	(12)	(25)	(12)	(67)
Derivative gain (loss), net	2	1	13	(2)
Other income	8	3	19	6
Total other income (expense)	(185)	(174)	(532)	(500)
Net income (loss)	$ 307	$ 23	$ 923	$ 116
Basic and diluted net income (loss) per common unit	$ 0.60	$ (1.10)	$ 1.82	$ (4.12)
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation	348.6	247.2	348.6	121.2
LNG [Member]
Revenues
Revenue earned from contracts with customers	$ 1,185	$ 717	$ 3,302	$ 1,695
Revenues	1,249	723	3,419	1,718
LNG—affiliate [Member]
Revenues
Revenue earned from contracts with customers	205	111	886	864
Regasification [Member]
Revenues
Revenue earned from contracts with customers	66	65	196	195
Other [Member]
Revenues
Revenue earned from contracts with customers	9	3	28	7
Other—affiliate [Member]
Revenues
Revenue earned from contracts with customers	$ 0	$ 1	$ 0	$ 2

XML

Consolidated Statement of Partners' Equity - 9 months ended Sep. 30, 2018 - USD ($) shares in Millions, $ in Millions	Total	Common Units [Member]	Subordinated Units [Member]	General Partner [Member]
Units, Outstanding, beginning of period at Dec. 31, 2017		348.6	135.4
Partners' equity, beginning of period at Dec. 31, 2017	$ 639	$ 1,670	$ (1,043)	$ 12
General partner units, Outstanding, beginning of period at Dec. 31, 2017	9.9			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 923	651	253	$ 19
Distributions	(814)	$ (562)	$ (218)	(34)
Units, Outstanding, end of period at Sep. 30, 2018		348.6	135.4
Partners' equity, end of period at Sep. 30, 2018	$ 748	$ 1,759	$ (1,008)	$ (3)
General partner units, Outstanding, end of period at Sep. 30, 2018	9.9			9.9

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities
Net income	$ 923	$ 116
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	318	239
Amortization of debt issuance costs, deferred commitment fees, premium and discount	24	28
Loss on modification or extinguishment of debt	12	67
Total losses on derivatives, net	29	53
Net cash used for settlement of derivative instruments	0	(15)
Impairment expense and loss on disposal of assets	8	0
Other	5	1
Changes in operating assets and liabilities:
Accounts and other receivables	(33)	(69)
Accounts receivable—affiliate	140	82
Advances to affiliate	(79)	(36)
Inventory	6	28
Accounts payable and accrued liabilities	(77)	19
Due to affiliates	(5)	(47)
Deferred revenue	6	58
Other, net	(10)	(9)
Other, net—affiliate	(3)	(2)
Net cash provided by operating activities	1,264	513
Cash flows from investing activities
Property, plant and equipment, net	(578)	(1,195)
Net cash provided by (used in) investing activities	(578)	(1,195)
Cash flows from financing activities
Proceeds from issuances of debt	1,100	3,814
Repayments of debt	(1,090)	(2,173)
Debt issuance and deferred financing costs	(8)	(47)
Debt extinguishment costs	(6)	0
Distributions to owners	(814)	(74)
Net cash provided by (used in) financing activities	(818)	1,520
Net increase (decrease) in cash, cash equivalents and restricted cash	(132)	838
Cash, cash equivalents and restricted cash—beginning of period	1,589	605
Cash, cash equivalents and restricted cash—end of period	$ 1,457	$ 1,443

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Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheet - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	$ 0	$ 0
Restricted cash	1,457	1,589
Total cash, cash equivalents and restricted cash	$ 1,457	$ 1,589	$ 1,443	$ 605

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Nature of Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, 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 undergoing commissioning and Train 6 is being commercialized and has all necessary regulatory approvals in place. The Sabine Pass LNG terminal has operational regasification facilities owned by SPLNG and a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL.

Basis of Presentation

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

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

Results of operations for the three and nine months ended September 30, 2018 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2018.

We are not subject to either federal or state income tax, as our partners are taxed individually on their allocable share of our taxable income.

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Unitholders' Equity

9 Months Ended

Sep. 30, 2018

Partners' Capital Notes [Abstract]

Unitholders' Equity

UNITHOLDERS’ EQUITY

The common units and subordinated units represent limited partner interests in us. The holders of the units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from operating surplus as defined in the partnership agreement.

The holders of common units have the right to receive initial quarterly distributions of $0.425 per common unit, plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. The holders of subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distribution requirement for our common unitholders and general partner and certain reserves.  Subordinated units will convert into common units on a one-for-one basis when we meet financial tests specified in the partnership agreement. Although common and subordinated unitholders are not obligated to fund losses of the Partnership, their capital accounts, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continue to share in losses.

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights (“IDRs”), which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

During the three months ended September 30, 2018, Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”), which holds limited partner interests in us, merged with a wholly owned subsidiary of Cheniere. As of September 30, 2018, Cheniere, Blackstone CQP Holdco and the public own a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere’s ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.

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Restricted Cash

9 Months Ended

Sep. 30, 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 Consolidated Balance Sheets. As of September 30, 2018 and December 31, 2017, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	649	$	544
Cash held by us and our guarantor subsidiaries	808		1,045
Total current restricted cash	$	1,457	$	1,589

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

Under our credit facilities (the “CQP Credit Facilities”), we and each of our subsidiaries other than SPL, as our guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the CQP Credit Facilities and the related depositary agreement governing the extension of credit to us. Specifically, we may only withdraw funds from collateral accounts held at a designated depositary bank on a limited basis and for specific purposes, including for the payment of our operating expenses and the operating expenses of our guarantor subsidiaries. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions.

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Accounts and Other Receivables

9 Months Ended

Sep. 30, 2018

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2018 and December 31, 2017, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
SPL trade receivable	$	213	$	185
Other accounts receivable	11		6
Total accounts and other receivables	$	224	$	191

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Inventory

9 Months Ended

Sep. 30, 2018

Inventory Disclosure [Abstract]

Inventory

INVENTORY

As of September 30, 2018 and December 31, 2017, inventory consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Natural gas	$	9	$	17
LNG	21		26
Materials and other	58		52
Total inventory	$	88	$	95

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

As of September 30, 2018 and December 31, 2017, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	12,706		$	12,703
LNG terminal construction-in-process	3,757			3,310
Accumulated depreciation	(1,187		)	(880		)
Total LNG terminal costs, net	15,276			15,133
Fixed assets
Fixed assets	26			23
Accumulated depreciation	(20		)	(17		)
Total fixed assets, net	6			6
Property, plant and equipment, net	$	15,282		$	15,139

Depreciation expense was $104 million and $85 million during the three months ended September 30, 2018 and 2017, respectively, and $310 million and $233 million during the nine months ended September 30, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $79 million and $242 million in the three and nine months ended September 30, 2017, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three and nine months ended September 30, 2018.

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Derivative Instruments

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

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

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

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

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 September 30, 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 Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2018									December 31, 2017
	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
CQP Interest Rate Derivatives asset	$	—		$	28	$	—	$	28	$	—	$	21	$	—	$	21
Liquefaction Supply Derivatives asset (liability)	(1		)	1		19		19		2		10		43		55

There have been no changes to our evaluation of and accounting for our derivative positions during the nine months ended September 30, 2018. See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information.

We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a 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 Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2018:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$19	Market approach incorporating present value techniques	Basis Spread	$(0.448) - $0.079

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Balance, beginning of period	$	11		$	40		$	43		$	79
Realized and mark-to-market gains (losses):
Included in cost of sales	4			(8		)	(5		)	(43		)
Purchases and settlements:
Purchases	4			(1		)	8			1
Settlements	1			(2		)	(27		)	(8		)
Transfers out of Level 3 (1)	(1		)	—			—			—
Balance, end of period	$	19		$	29		$	19		$	29
Change in unrealized gains relating to instruments still held at end of period	$	4		$	(8	)	$	(5	)	$	(43	)

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

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for 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 swaps (“CQP Interest Rate Derivatives”) to hedge a portion of the variable interest payments on the CQP Credit Facilities, based on a portion of the expected outstanding borrowings over the term of the CQP Credit Facilities. In September 2018, we terminated approximately $1.2 billion of commitments under the CQP Credit Facilities, as discussed in Note 10—Debt. In October 2018, we terminated the CQP Interest Rate Derivatives related to the CQP Credit Facilities, which resulted in a derivative gain of $28 million.

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

As of September 30, 2018, we had the following Interest Rate Derivatives outstanding:

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
CQP Interest Rate Derivatives	$225 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR

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

	September 30,		December 31,
Consolidated Balance Sheet Location	2018		2017
Other current assets	$	19	$	7
Non-current derivative assets	9		14
Total derivative assets	$	28	$	21

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Income during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
CQP Interest Rate Derivatives gain	$	2	$	1	$	13	$	—
SPL Interest Rate Derivatives loss	—		—		—		(2		)

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the physical natural gas supply contracts range up to six years, some of which commence upon the satisfaction of certain conditions precedent.

SPL had secured up to approximately 2,755TBtu and 2,214TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2018 and December 31, 2017, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 2,206TBtu and 1,520TBtu as of September 30, 2018 and December 31, 2017, respectively.

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

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	September 30, 2018			December 31, 2017
Other current assets	$	11		$	41
Non-current derivative assets	16			17
Total derivative assets	27			58
Derivative liabilities	(6		)	—
Non-current derivative liabilities	(2		)	(3		)
Total derivative liabilities	(8		)	(3		)
Derivative asset, net	$	19		$	55

(1) Does not include collateral calls of $2 million and $1 million as of September 30, 2018 and December 31, 2017, respectively, for such contracts, which are included in other current assets in our Consolidated Balance Sheets.

The following table shows the changes in the fair value and settlements of our Liquefaction Supply Derivatives recorded in cost of sales on our Consolidated Statements of Income during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018			2017
Liquefaction Supply Derivatives gain (loss) (1)	$	10	$	(11	)	$	(42	)	$	(51	)

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

Consolidated Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2018
CQP Interest Rate Derivatives	$	28		$	—		$	28
Liquefaction Supply Derivatives	31			(4		)	27
Liquefaction Supply Derivatives	(13		)	5			(8		)
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

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Other Non-Current Assets

9 Months Ended

Sep. 30, 2018

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

As of September 30, 2018 and December 31, 2017, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	15	$	26
Advances made to municipalities for water system enhancements	90		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	17		25
Information technology service assets	20		24
Other	8		8
Total other non-current assets, net	$	179	$	206

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Accrued Liabilities

9 Months Ended

Sep. 30, 2018

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

As of September 30, 2018 and December 31, 2017, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Interest costs and related debt fees	$	186	$	253
Accrued natural gas purchases	249		298
LNG terminal and related pipeline costs	59		86
Other accrued liabilities	9		—
Total accrued liabilities	$	503	$	637

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Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Debt

DEBT

As of September 30, 2018 and December 31, 2017, our debt consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			—
CQP Credit Facilities	—			1,090
Unamortized premium, discount and debt issuance costs, net	(191		)	(194		)
Total long-term debt, net	16,059			16,046
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	16,059		$	16,046

2018 Debt Issuances and Redemptions

2026 CQP Senior Notes

In September 2018, we issued an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP. Net proceeds of the offering of approximately $1.1 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay all of the outstanding indebtedness under the CQP Credit Facilities, resulting in the recognition of debt modification and extinguishment costs of $12 million for the three and nine months ended September 30, 2018 relating to the incurrence of third party fees and write off of unamortized debt issuance costs. As of September 30, 2018, only a $115 million revolving credit facility, all of which is undrawn, remains as part of the CQP Credit Facilities.

Borrowings under the 2026 CQP Senior Notes accrue interest at a fixed rate of 5.625%, and interest on the 2026 CQP Senior Notes is payable semi-annually in arrears. The 2026 CQP Senior Notes are governed by the same base indenture as the 2025 CQP Senior Notes (the “CQP Base Indenture”), and are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

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

The 2026 CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. After applying the proceeds from the 2026 CQP Senior Notes, the 2026 CQP Senior Notes and the 2025 CQP Senior Notes(collectively, the “CQP Senior Notes”) became unsecured. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the CQP Credit Facilities. The obligations under the CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the Guarantors and equity interests in the Guarantors (except, in each case, for certain excluded properties set forth in the CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the CQP Credit Facilities).

In connection with the closing of the 2026 CQP Senior Notes offering, we and the Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, we and the Guarantors have agreed to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2026 CQP Senior Notes for a like aggregate principal amount of our debt securities with terms identical in all material respects to the 2026 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after the notes issuance date of September 11, 2018. Under specified circumstances, we and the Guarantors have also agreed to cause to become effective a shelf registration statement relating to resales of the 2026 CQP Senior Notes. We will be obligated to pay additional interest on the 2026 CQP Senior Notes if we fail to comply with our obligation to register the 2026 CQP Senior Notes within the specified time period.

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2018 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		2,685
Letters of credit issued	494		—
Available commitment	$	706	$	115
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020

(1) There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

Restrictive Debt Covenants

As of September 30, 2018, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Total interest cost	$	235		$	227		$	701		$	662
Capitalized interest	(52		)	(74		)	(149		)	(225		)
Total interest expense, net	$	183		$	153		$	552		$	437

Fair Value Disclosures

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

	September 30, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	15,268	$	16,098	$	14,166	$	15,485
2037 SPL Senior Notes (2)	791		831		790		871
Credit facilities (3)	—		—		1,090		1,090

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

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

(3) Includes SPL Working Capital Facility and CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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Revenues from Contracts with Customers

9 Months Ended

Sep. 30, 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 and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
LNG revenues	$	1,185	$	717	$	3,302	$	1,695
LNG revenues—affiliate	205		111		886		864
Regasification revenues	66		65		196		195
Other revenues	9		3		28		7
Other revenues—affiliate	—		1		—		2
Total revenues from customers	1,465		897		4,412		2,763
Gains from derivative instruments (1)	64		6		117		23
Total revenues	$	1,529	$	903	$	4,529	$	2,786

(1) Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

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 transfer 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 exception for allocating variable consideration to specific parts of the contract. 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 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.

Regasification Revenues

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

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

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

Upon substantial completion of Train 3 of the Liquefaction Project, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During each of the three months ended September 30, 2018 and 2017, SPL recorded $7.5 million and during the nine months ended September 30, 2018 and 2017, SPL recorded $23 million and $15 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

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

	Nine Months Ended September 30, 2018
Deferred revenues, beginning of period	$	111
Cash received but not yet recognized	119
Revenue recognized from prior period deferral	(111		)
Deferred revenues, end of period	$	119

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 nine months ended September 30, 2018 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 September 30, 2018:

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	54.2	10.2
Regasification revenues	2.7		5.8
Total revenues	$	56.9

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

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During each of the three and nine months ended September 30, 2018, approximately 55% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 3% of our regasification revenues were related to variable consideration received from customers.

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

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 December 31, 2017.

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Related Party Transactions

9 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	205	$	111	$	886	$	864
Other revenues—affiliate
Terminal Marine Services Agreement	—		1		—		2
Operating and maintenance expense—affiliate
Services Agreements	31		25		87		64
Other agreements	—		6		—		6
Total operating and maintenance expense—affiliate	31		31		87		70
General and administrative expense—affiliate
Services Agreements	18		18		53		63

LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036.

In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is recorded as operating and maintenance expense on our Consolidated Statements of Income.

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay the TUA Fees required by the TUA to SPLNG. However, the revenue earned by SPLNG from the TUA Fees and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our Consolidated Financial Statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA.

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing during the three and nine months ended September 30, 2018 and 2017 related to the Amended and Restated VCRA.

Cheniere Marketing SPA

Cheniere Marketing has an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL 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

SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement. SPL 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.

Services Agreements

As of September 30, 2018 and December 31, 2017, we had $189 million and $36 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Cheniere Partners Services Agreement

We have a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $3 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments 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.

SPLNG O&M Agreement

SPLNG has a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SPLNG pays a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between SPLNG and Cheniere Investments at the beginning of each operating year. In addition, SPLNG is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the SPLNG O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to such subsidiary.

SPLNG MSA

SPLNG has a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the SPLNG O&M Agreement. SPLNG pays a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

SPL O&M Agreement

SPL has an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments pursuant to which SPL receives 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 behalf of SPL, 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, SPL is 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, SPL 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. Cheniere Investments provides the services required under the SPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPL O&M Agreement are required to be remitted to such subsidiary.

SPL MSA

SPL has a management services agreement (the “SPL 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 SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s business and operations, entering into financial derivatives on SPL’s 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, SPL pays a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

CTPL O&M Agreement

CTPL has an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M Agreement are required to be remitted to such subsidiary.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represented an aggregate commitment of $25 million in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to ad valorem tax levied on our LNG terminal in the year the Cameron Parish dollar-for-dollar credit is applied.

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of September 30, 2018, we had $2 million in due to affiliates and $23 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing. As of December 31, 2017, we had $25 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. The agreement also provides that Tug Services shall contingently pay the wholly owned subsidiary of Cheniere a portion of its future revenues. Accordingly, Tug Services distributed $4 million to the wholly owned subsidiary of Cheniere during the nine months ended September 30, 2018, which is reported as part of the distributions to our general partner interest holders on the Consolidated Statement of Partners’ Equity. No amounts were distributed during the nine months ended September 30, 2017.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the three and nine months ended September 30, 2018 and 2017.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG 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, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its 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 SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

SPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPL 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, SPL will pay to Cheniere an amount equal to the state and local tax that SPL would be required to pay if SPL’s 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 SPL under this agreement; therefore, Cheniere has not demanded any such payments from SPL. The agreement is effective for tax returns due on or after August 2012.

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL 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, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s 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 CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013.

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Net Income (Loss) per Common Unit

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Net Income (Loss) per Common Unit

NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statement of Partners’ Equity. On October 26, 2018, we declared a $0.58 distribution per common unit and subordinated unit and the related distribution to our general partner and IDR holders to be paid on November 14, 2018 to unitholders of record as of November 5, 2018 for the period from July 1, 2018 to September 30, 2018.

The two-class method dictates that net income (loss) for a period be reduced by the amount of available cash that will be distributed with respect to that period and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and other participating securities on a pro rata basis based on provisions of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

The Class B units, which were mandatorily converted into our common units in accordance with the terms of our partnership agreement on August 2, 2017, were issued at a discount to the market price of the common units into which they were convertible.  This discount, totaling $2,130 million, represented a beneficial conversion feature and was reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statement of Partners’ Equity.  The beneficial conversion feature was considered a dividend that was distributed ratably with respect to any Class B unit from its issuance date through its conversion date, which resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortized the beneficial conversion feature through the mandatory conversion date of August 2, 2017 using the effective yield method, with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ previously held Class B units and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature was also included in earnings per unit for the three and nine months ended September 30, 2017.

The following table provides a reconciliation of net income and the allocation of net income to the common units, the subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income (loss) per unit (in millions, except per unit data).

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner Units			IDR
Three Months Ended September 30, 2018
Net income	$	307
Declared distributions	297			202			—		79			5			11
Assumed allocation of undistributed net income (1)	$	10		7			—		3			—			—
Assumed allocation of net income				$	209		$	—	$	82		$	5		$	11
Weighted average units outstanding				348.6			—		135.4
Basic and diluted net income per unit (2)				$	0.60				$	0.60
Three Months Ended September 30, 2017
Net income	$	23
Declared distributions	217			153			—		60			4			—
Amortization of beneficial conversion feature of Class B units	—			(288		)	974		(686		)	—			—
Assumed allocation of undistributed net loss	$	(194	)	(137		)	—		(53		)	(4		)	—
Assumed allocation of net income				$	(272	)	$	974	$	(679	)	$	—		$	—
Weighted average units outstanding				247.2			50.6		135.4
Basic and diluted net loss per unit (2)				$	(1.10	)			$	(5.02	)
Nine Months Ended September 30, 2018
Net income	$	923
Declared distributions	859			589			—		229			17			24
Assumed allocation of undistributed net income (1)	$	64		45			—		18			1			—
Assumed allocation of net income				$	634		$	—	$	247		$	18		$	24
Weighted average units outstanding				348.6			—		135.4
Basic and diluted net income per unit				$	1.82				$	1.82
Nine Months Ended September 30, 2017
Net income	$	116
Declared distributions	267			202			—		60			5			—
Amortization of beneficial conversion feature of Class B units	—			(594		)	2,004		(1,410		)	—			—
Assumed allocation of undistributed net loss	$	(151	)	(107		)	—		(41		)	(3		)	—
Assumed allocation of net income				$	(499	)	$	2,004	$	(1,391	)	$	2		$	—
Weighted average units outstanding				121.2			113.4		135.4
Basic and diluted net loss per unit (2)				$	(4.12	)			$	(10.28	)

(1) Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss).

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

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Customer Concentration

9 Months Ended

Sep. 30, 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 September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2018	2017	2018	2017	2018	2017
Customer A	24%	31%	27%	42%	28%	39%
Customer B	21%	24%	22%	26%	26%	32%
Customer C	21%	35%	23%	18%	22%	26%
Customer D	24%	—%	18%	—%	19%	—%

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 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):

	Nine Months Ended September 30,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	586	$	459

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $204 million and $247 million as of September 30, 2018 and 2017, respectively.

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Recent Accounting Standards

9 Months Ended

Sep. 30, 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 September 30, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	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 may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated 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 anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We anticipate electing the optional transition method to initially apply the standard at the January 1, 2019 adoption date. 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 also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. 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 Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 11—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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Supplemental Guarantor Information

9 Months Ended

Sep. 30, 2018

Supplemental Guarantor Information [Abstract]

Supplemental Guarantor Information

SUPPLEMENTAL GUARANTOR INFORMATION

Our CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the CQP Indenture. See Note 10—Debt in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information regarding the CQP Senior Notes.

The following is condensed consolidating financial information for CQP (“Parent Issuer”), the Guarantors on a combined basis and the Non-Guarantors on a combined basis. We have accounted for investments in subsidiaries using the equity method.

Condensed Consolidating Balance Sheet
September 30, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	799		9		649		—			1,457
Accounts and other receivables	1		1		222		—			224
Accounts receivable—affiliate	1		46		21		(46		)	22
Advances to affiliate	—		100		174		(85		)	189
Inventory	—		12		76		—			88
Other current assets	19		1		35		—			55
Other current assets—affiliate	—		—		21		(21		)	—
Total current assets	820		169		1,198		(152		)	2,035
Property, plant and equipment, net	79		2,136		13,091		(24		)	15,282
Debt issuance costs, net	1		—		14		—			15
Non-current derivative assets	9		—		16		—			25
Investments in subsidiaries	2,449		347		—		(2,796		)	—
Other non-current assets, net	—		27		152		—			179
Total assets	$	3,358	$	2,679	$	14,471	$	(2,972	)	$	17,536
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	1	$	5	$	7	$	—		$	13
Accrued liabilities	44		20		439		—			503
Due to affiliates	—		132		52		(131		)	53
Deferred revenue	—		24		95		—			119
Deferred revenue—affiliate	—		21		—		(21		)	—
Derivative liabilities	—		—		6		—			6
Total current liabilities	45		202		599		(152		)	694
Long-term debt, net	2,565		—		13,494		—			16,059
Non-current derivative liabilities	—		—		2		—			2
Other non-current liabilities	—		5		5		—			10
Other non-current liabilities—affiliate	—		23		—		—			23
Partners’ equity	748		2,449		371		(2,820		)	748
Total liabilities and partners’ equity	$	3,358	$	2,679	$	14,471	$	(2,972	)	$	17,536

Condensed Consolidating Balance Sheet
December 31, 2017
(in millions)
	Parent Issuer		Guarantors			Non-Guarantors			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—		$	—		$	—		$	—
Restricted cash	1,033		12			544			—			1,589
Accounts and other receivables	—		2			189			—			191
Accounts receivable—affiliate	—		36			163			(36		)	163
Advances to affiliate	—		20			26			(10		)	36
Inventory	—		10			85			—			95
Other current assets	8		3			54			—			65
Other current assets—affiliate	—		—			21			(21		)	—
Total current assets	1,041		83			1,082			(67		)	2,139
Property, plant and equipment, net	80		2,164			12,920			(25		)	15,139
Debt issuance costs, net	20		—			18			—			38
Non-current derivative assets	14		—			17			—			31
Investments in subsidiaries	2,076		(63		)	—			(2,013		)	—
Other non-current assets, net	—		37			169			—			206
Total assets	$	3,231	$	2,221		$	14,206		$	(2,105	)	$	17,553
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4		$	8		$	—		$	12
Accrued liabilities	23		8			606			—			637
Due to affiliates	—		47			66			(45		)	68
Deferred revenue	—		27			84			—			111
Deferred revenue—affiliate	—		22			—			(21		)	1
Other current liabilities—affiliate	—		1			—			(1		)	—
Total current liabilities	23		109			764			(67		)	829
Long-term debt, net	2,569		—			13,477			—			16,046
Non-current derivative liabilities	—		—			3			—			3
Other non-current liabilities	—		11			—			—			11
Other non-current liabilities—affiliate	—		25			—			—			25
Partners’ equity (deficit)	639		2,076			(38		)	(2,038		)	639
Total liabilities and partners’ equity (deficit)	$	3,231	$	2,221		$	14,206		$	(2,105	)	$	17,553

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,249		$	—		$	1,249
LNG revenues—affiliate	—			—			205			—			205
Regasification revenues	—			66			—			—			66
Regasification revenues—affiliate	—			64			—			(64		)	—
Other revenues	—			9			—			—			9
Other revenues—affiliate	—			48			—			(48		)	—
Total revenues	—			187			1,454			(112		)	1,529
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			758			(2		)	756
Cost of sales—affiliate	—			—			8			(8		)	—
Operating and maintenance expense	—			17			96			—			113
Operating and maintenance expense—affiliate	—			39			107			(115		)	31
Development expense	—			1			—			—			1
General and administrative expense	1			1			1			—			3
General and administrative expense—affiliate	3			6			12			(3		)	18
Depreciation and amortization expense	1			19			88			(1		)	107
Impairment expense and loss on disposal of assets	—			8			—			—			8
Total operating costs and expenses	5			91			1,070			(129		)	1,037
Income (loss) from operations	(5		)	96			384			17			492
Other income (expense)
Interest expense, net of capitalized interest	(36		)	(1		)	(146		)	—			(183		)
Loss on modification or extinguishment of debt	(12		)	—			—			—			(12		)
Derivative gain, net	2			—			—			—			2
Equity earnings of subsidiaries	354			243			—			(597		)	—
Other income (expense)	4			(1		)	5			—			8
Total other income (expense)	312			241			(141		)	(597		)	(185		)
Net income	$	307		$	337		$	243		$	(580	)	$	307

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	723		$	—		$	723
LNG revenues—affiliate	—			—			111			—			111
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			48			—			(48		)	—
Other revenues	—			3			—			—			3
Other revenues—affiliate	—			51			—			(50		)	1
Total revenues	—			167			834			(98		)	903
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	—			(1		)	488			3			490
Cost of sales—affiliate	—			—			5			(5		)	—
Operating and maintenance expense	1			7			65			—			73
Operating and maintenance expense—affiliate	6			33			82			(90		)	31
Development expense	—			—			1			—			1
General and administrative expense	1			1			3			—			5
General and administrative expense—affiliate	3			6			12			(3		)	18
Depreciation and amortization expense	1			17			69			—			87
Other	—			1			—			—			1
Total operating costs and expenses	12			64			725			(95		)	706
Income (loss) from operations	(12		)	103			109			(3		)	197
Other income (expense)
Interest expense, net of capitalized interest	(29		)	—			(124		)	—			(153		)
Loss on modification or extinguishment of debt	(25		)	—			—			—			(25		)
Derivative gain, net	1			—			—			—			1
Equity earnings (losses) of subsidiaries	88			(12		)	—			(76		)	—
Other income	—			—			3			—			3
Total other income (expense)	35			(12		)	(121		)	(76		)	(174		)
Net income (loss)	$	23		$	91		$	(12	)	$	(79	)	$	23

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	3,419		$	—		$	3,419
LNG revenues—affiliate	—			—			886			—			886
Regasification revenues	—			196			—			—			196
Regasification revenues—affiliate	—			194			—			(194		)	—
Other revenues	—			28			—			—			28
Other revenues—affiliate	—			183			—			(183		)	—
Total revenues	—			601			4,305			(377		)	4,529
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			2			2,291			(2		)	2,291
Cost of sales—affiliate	—			—			23			(23		)	—
Operating and maintenance expense	—			48			258			—			306
Operating and maintenance expense—affiliate	—			113			317			(343		)	87
Development expense	—			1			1			—			2
General and administrative expense	3			2			4			—			9
General and administrative expense—affiliate	9			17			36			(9		)	53
Depreciation and amortization expense	2			56			261			(1		)	318
Impairment expense and loss on disposal of assets	—			8			—			—			8
Total operating costs and expenses	14			247			3,191			(378		)	3,074
Income (loss) from operations	(14		)	354			1,114			1			1,455
Other income (expense)
Interest expense, net of capitalized interest	(104		)	(3		)	(445		)	—			(552		)
Loss on modification or extinguishment of debt	(12		)	—			—			—			(12		)
Derivative gain, net	13			—			—			—			13
Equity earnings of subsidiaries	1,030			678			—			(1,708		)	—
Other income	10			—			9			—			19
Total other income (expense)	937			675			(436		)	(1,708		)	(532		)
Net income	$	923		$	1,029		$	678		$	(1,707	)	$	923

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,718		$	—		$	1,718
LNG revenues—affiliate	—			—			864			—			864
Regasification revenues	—			195			—			—			195
Regasification revenues—affiliate	—			128			—			(128		)	—
Other revenues	—			7			—			—			7
Other revenues—affiliate	—			162			—			(160		)	2
Total revenues	—			492			2,582			(288		)	2,786
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			1			1,576			3			1,580
Cost of sales—affiliate	—			—			15			(15		)	—
Operating and maintenance expense	4			29			172			—			205
Operating and maintenance expense—affiliate	6			96			224			(256		)	70
Development expense	—			—			2			—			2
General and administrative expense	3			2			5			—			10
General and administrative expense—affiliate	9			19			46			(11		)	63
Depreciation and amortization expense	1			55			183			—			239
Other	—			1			—			—			1
Total operating costs and expenses	23			203			2,223			(279		)	2,170
Income (loss) from operations	(23		)	289			359			(9		)	616
Other income (expense)
Interest expense, net of capitalized interest	(81		)	—			(356		)	—			(437		)
Loss on modification or extinguishment of debt	(25		)	—			(42		)	—			(67		)
Derivative loss, net	—			—			(2		)	—			(2		)
Equity earnings (losses) of subsidiaries	244			(36		)	—			(208		)	—
Other income	1			—			5			—			6
Total other income (expense)	139			(36		)	(395		)	(208		)	(500		)
Net income (loss)	$	116		$	253		$	(36	)	$	(217	)	$	116

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by operating activities	$	339		$	408		$	928		$	(411	)	$	1,264
Cash flows from investing activities
Property, plant and equipment, net	—			(24		)	(554		)	—			(578		)
Investments in subsidiaries	(202		)	(81		)	—			283			—
Distributions received from affiliates, net	447			350			—			(797		)	—
Net cash provided by (used in) investing activities	245			245			(554		)	(514		)	(578		)
Cash flows from financing activities
Proceeds from issuances of debt	1,100			—			—			—			1,100
Repayments of debt	(1,090		)	—			—			—			(1,090		)
Debt issuance and deferred financing costs	(8		)	—			—			—			(8		)
Debt extinguishment costs	(6		)	—			—			—			(6		)
Distributions to parent	—			(858		)	(350		)	1,208			—
Contributions from parent	—			202			81			(283		)	—
Distributions to owners	(814		)	—			—			—			(814		)
Net cash used in financing activities	(818		)	(656		)	(269		)	925			(818		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(234		)	(3		)	105			—			(132		)
Cash, cash equivalents and restricted cash—beginning of period	1,033			12			544			—			1,589
Cash, cash equivalents and restricted cash—end of period	$	799		$	9		$	649		$	—		$	1,457

Balances per Condensed Consolidating Balance Sheet:

	September 30, 2018
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Restricted cash	799		9		649		—		1,457
Total cash, cash equivalents and restricted cash	$	799	$	9	$	649	$	—	$	1,457

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(89	)	$	293		$	317		$	(8	)	$	513
Cash flows from investing activities
Property, plant and equipment, net	—			(16		)	(1,187		)	8			(1,195		)
Investments in subsidiaries	(216		)	(7		)	—			223			—
Distributions received from affiliates, net	929			450			—			(1,379		)	—
Net cash provided by (used in) investing activities	713			427			(1,187		)	(1,148		)	(1,195		)
Cash flows from financing activities
Proceeds from issuances of debt	1,500			—			2,314			—			3,814
Repayments of debt	(1,470		)	—			(703		)	—			(2,173		)
Debt issuance and deferred financing costs	(18		)	—			(29		)	—			(47		)
Distributions to parent	—			(929		)	(450		)	1,379			—
Contributions from parent	—			216			7			(223		)	—
Distributions to owners	(74		)	—			—			—			(74		)
Net cash provided by (used in) financing activities	(62		)	(713		)	1,139			1,156			1,520
Net increase in cash, cash equivalents and restricted cash	562			7			269			—			838
Cash, cash equivalents and restricted cash—beginning of period	234			13			358			—			605
Cash, cash equivalents and restricted cash—end of period	$	796		$	20		$	627		$	—		$	1,443

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Nature of Operations and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

Basis of Presentation

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

Income Taxes, Policy

We are not subject to either federal or state income tax, as our partners are taxed individually on their allocable share of our taxable income.

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Restricted Cash (Tables)

9 Months Ended

Sep. 30, 2018

Restricted Cash [Abstract]

Schedule of Restricted Cash

As of September 30, 2018 and December 31, 2017, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	649	$	544
Cash held by us and our guarantor subsidiaries	808		1,045
Total current restricted cash	$	1,457	$	1,589

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Accounts and Other Receivables (Tables)

9 Months Ended

Sep. 30, 2018

Receivables [Abstract]

Schedule of Accounts and Other Receivables

As of September 30, 2018 and December 31, 2017, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
SPL trade receivable	$	213	$	185
Other accounts receivable	11		6
Total accounts and other receivables	$	224	$	191

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Inventory (Tables)

9 Months Ended

Sep. 30, 2018

Inventory Disclosure [Abstract]

Schedule of Inventory

As of September 30, 2018 and December 31, 2017, inventory consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Natural gas	$	9	$	17
LNG	21		26
Materials and other	58		52
Total inventory	$	88	$	95

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

As of September 30, 2018 and December 31, 2017, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	12,706		$	12,703
LNG terminal construction-in-process	3,757			3,310
Accumulated depreciation	(1,187		)	(880		)
Total LNG terminal costs, net	15,276			15,133
Fixed assets
Fixed assets	26			23
Accumulated depreciation	(20		)	(17		)
Total fixed assets, net	6			6
Property, plant and equipment, net	$	15,282		$	15,139

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 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 September 30, 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 Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2018									December 31, 2017
	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
CQP Interest Rate Derivatives asset	$	—		$	28	$	—	$	28	$	—	$	21	$	—	$	21
Liquefaction Supply Derivatives asset (liability)	(1		)	1		19		19		2		10		43		55

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2018:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$19	Market approach incorporating present value techniques	Basis Spread	$(0.448) - $0.079

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 and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Balance, beginning of period	$	11		$	40		$	43		$	79
Realized and mark-to-market gains (losses):
Included in cost of sales	4			(8		)	(5		)	(43		)
Purchases and settlements:
Purchases	4			(1		)	8			1
Settlements	1			(2		)	(27		)	(8		)
Transfers out of Level 3 (1)	(1		)	—			—			—
Balance, end of period	$	19		$	29		$	19		$	29
Change in unrealized gains relating to instruments still held at end of period	$	4		$	(8	)	$	(5	)	$	(43	)

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

Derivative Net Presentation on Consolidated 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 Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2018
CQP Interest Rate Derivatives	$	28		$	—		$	28
Liquefaction Supply Derivatives	31			(4		)	27
Liquefaction Supply Derivatives	(13		)	5			(8		)
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of September 30, 2018, we had the following Interest Rate Derivatives outstanding:

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
CQP Interest Rate Derivatives	$225 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR

Fair Value of Derivative Instruments by Balance Sheet Location

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

	September 30,		December 31,
Consolidated Balance Sheet Location	2018		2017
Other current assets	$	19	$	7
Non-current derivative assets	9		14
Total derivative assets	$	28	$	21

Derivative Instruments, Gain (Loss)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Income during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
CQP Interest Rate Derivatives gain	$	2	$	1	$	13	$	—
SPL 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 Consolidated Balance Sheets (in millions):

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	September 30, 2018			December 31, 2017
Other current assets	$	11		$	41
Non-current derivative assets	16			17
Total derivative assets	27			58
Derivative liabilities	(6		)	—
Non-current derivative liabilities	(2		)	(3		)
Total derivative liabilities	(8		)	(3		)
Derivative asset, net	$	19		$	55

(1) Does not include collateral calls of $2 million and $1 million as of September 30, 2018 and December 31, 2017, respectively, for such contracts, which are included in other current assets in our Consolidated Balance Sheets.

Derivative Instruments, Gain (Loss)

The following table shows the changes in the fair value and settlements of our Liquefaction Supply Derivatives recorded in cost of sales on our Consolidated Statements of Income during the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018			2017
Liquefaction Supply Derivatives gain (loss) (1)	$	10	$	(11	)	$	(42	)	$	(51	)

(1) Does not include the realized value associated with derivative instruments that settle through physical delivery. 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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Other Non-Current Assets (Tables)

9 Months Ended

Sep. 30, 2018

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

As of September 30, 2018 and December 31, 2017, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	15	$	26
Advances made to municipalities for water system enhancements	90		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	17		25
Information technology service assets	20		24
Other	8		8
Total other non-current assets, net	$	179	$	206

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Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2018

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

As of September 30, 2018 and December 31, 2017, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2018		2017
Interest costs and related debt fees	$	186	$	253
Accrued natural gas purchases	249		298
LNG terminal and related pipeline costs	59		86
Other accrued liabilities	9		—
Total accrued liabilities	$	503	$	637

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Debt (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Schedule of Debt Instruments

As of September 30, 2018 and December 31, 2017, our debt consisted of the following (in millions):

	September 30,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			—
CQP Credit Facilities	—			1,090
Unamortized premium, discount and debt issuance costs, net	(191		)	(194		)
Total long-term debt, net	16,059			16,046
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	16,059		$	16,046

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2018 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		2,685
Letters of credit issued	494		—
Available commitment	$	706	$	115
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020

(1) There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

Schedule of Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Total interest cost	$	235		$	227		$	701		$	662
Capitalized interest	(52		)	(74		)	(149		)	(225		)
Total interest expense, net	$	183		$	153		$	552		$	437

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	September 30, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	15,268	$	16,098	$	14,166	$	15,485
2037 SPL Senior Notes (2)	791		831		790		871
Credit facilities (3)	—		—		1,090		1,090

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

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

(3) Includes SPL Working Capital Facility and CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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Revenues from Contracts with Customers (Tables)

9 Months Ended

Sep. 30, 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 and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
LNG revenues	$	1,185	$	717	$	3,302	$	1,695
LNG revenues—affiliate	205		111		886		864
Regasification revenues	66		65		196		195
Other revenues	9		3		28		7
Other revenues—affiliate	—		1		—		2
Total revenues from customers	1,465		897		4,412		2,763
Gains from derivative instruments (1)	64		6		117		23
Total revenues	$	1,529	$	903	$	4,529	$	2,786

(1) Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

Contract Balances Reconciliation

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

	Nine Months Ended September 30, 2018
Deferred revenues, beginning of period	$	111
Cash received but not yet recognized	119
Revenue recognized from prior period deferral	(111		)
Deferred revenues, end of period	$	119

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 September 30, 2018:

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	54.2	10.2
Regasification revenues	2.7		5.8
Total revenues	$	56.9

(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)

9 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	205	$	111	$	886	$	864
Other revenues—affiliate
Terminal Marine Services Agreement	—		1		—		2
Operating and maintenance expense—affiliate
Services Agreements	31		25		87		64
Other agreements	—		6		—		6
Total operating and maintenance expense—affiliate	31		31		87		70
General and administrative expense—affiliate
Services Agreements	18		18		53		63

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Net Income (Loss) per Common Unit (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Schedule of Net Income (Loss) per Common Unit

The following table provides a reconciliation of net income and the allocation of net income to the common units, the subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income (loss) per unit (in millions, except per unit data).

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner Units			IDR
Three Months Ended September 30, 2018
Net income	$	307
Declared distributions	297			202			—		79			5			11
Assumed allocation of undistributed net income (1)	$	10		7			—		3			—			—
Assumed allocation of net income				$	209		$	—	$	82		$	5		$	11
Weighted average units outstanding				348.6			—		135.4
Basic and diluted net income per unit (2)				$	0.60				$	0.60
Three Months Ended September 30, 2017
Net income	$	23
Declared distributions	217			153			—		60			4			—
Amortization of beneficial conversion feature of Class B units	—			(288		)	974		(686		)	—			—
Assumed allocation of undistributed net loss	$	(194	)	(137		)	—		(53		)	(4		)	—
Assumed allocation of net income				$	(272	)	$	974	$	(679	)	$	—		$	—
Weighted average units outstanding				247.2			50.6		135.4
Basic and diluted net loss per unit (2)				$	(1.10	)			$	(5.02	)
Nine Months Ended September 30, 2018
Net income	$	923
Declared distributions	859			589			—		229			17			24
Assumed allocation of undistributed net income (1)	$	64		45			—		18			1			—
Assumed allocation of net income				$	634		$	—	$	247		$	18		$	24
Weighted average units outstanding				348.6			—		135.4
Basic and diluted net income per unit				$	1.82				$	1.82
Nine Months Ended September 30, 2017
Net income	$	116
Declared distributions	267			202			—		60			5			—
Amortization of beneficial conversion feature of Class B units	—			(594		)	2,004		(1,410		)	—			—
Assumed allocation of undistributed net loss	$	(151	)	(107		)	—		(41		)	(3		)	—
Assumed allocation of net income				$	(499	)	$	2,004	$	(1,391	)	$	2		$	—
Weighted average units outstanding				121.2			113.4		135.4
Basic and diluted net loss per unit (2)				$	(4.12	)			$	(10.28	)

(1) Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss).

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

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Customer Concentration (Tables)

9 Months Ended

Sep. 30, 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 September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2018	2017	2018	2017	2018	2017
Customer A	24%	31%	27%	42%	28%	39%
Customer B	21%	24%	22%	26%	26%	32%
Customer C	21%	35%	23%	18%	22%	26%
Customer D	24%	—%	18%	—%	19%	—%

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2018

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Nine Months Ended September 30,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	586	$	459

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Recent Accounting Standards (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2018:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	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 may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated 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 anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We anticipate electing the optional transition method to initially apply the standard at the January 1, 2019 adoption date. 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 also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. 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 Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 11—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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Supplemental Guarantor Information (Tables)

9 Months Ended

Sep. 30, 2018

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheet
September 30, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	799		9		649		—			1,457
Accounts and other receivables	1		1		222		—			224
Accounts receivable—affiliate	1		46		21		(46		)	22
Advances to affiliate	—		100		174		(85		)	189
Inventory	—		12		76		—			88
Other current assets	19		1		35		—			55
Other current assets—affiliate	—		—		21		(21		)	—
Total current assets	820		169		1,198		(152		)	2,035
Property, plant and equipment, net	79		2,136		13,091		(24		)	15,282
Debt issuance costs, net	1		—		14		—			15
Non-current derivative assets	9		—		16		—			25
Investments in subsidiaries	2,449		347		—		(2,796		)	—
Other non-current assets, net	—		27		152		—			179
Total assets	$	3,358	$	2,679	$	14,471	$	(2,972	)	$	17,536
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	1	$	5	$	7	$	—		$	13
Accrued liabilities	44		20		439		—			503
Due to affiliates	—		132		52		(131		)	53
Deferred revenue	—		24		95		—			119
Deferred revenue—affiliate	—		21		—		(21		)	—
Derivative liabilities	—		—		6		—			6
Total current liabilities	45		202		599		(152		)	694
Long-term debt, net	2,565		—		13,494		—			16,059
Non-current derivative liabilities	—		—		2		—			2
Other non-current liabilities	—		5		5		—			10
Other non-current liabilities—affiliate	—		23		—		—			23
Partners’ equity	748		2,449		371		(2,820		)	748
Total liabilities and partners’ equity	$	3,358	$	2,679	$	14,471	$	(2,972	)	$	17,536

Condensed Consolidating Balance Sheet
December 31, 2017
(in millions)
	Parent Issuer		Guarantors			Non-Guarantors			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—		$	—		$	—		$	—
Restricted cash	1,033		12			544			—			1,589
Accounts and other receivables	—		2			189			—			191
Accounts receivable—affiliate	—		36			163			(36		)	163
Advances to affiliate	—		20			26			(10		)	36
Inventory	—		10			85			—			95
Other current assets	8		3			54			—			65
Other current assets—affiliate	—		—			21			(21		)	—
Total current assets	1,041		83			1,082			(67		)	2,139
Property, plant and equipment, net	80		2,164			12,920			(25		)	15,139
Debt issuance costs, net	20		—			18			—			38
Non-current derivative assets	14		—			17			—			31
Investments in subsidiaries	2,076		(63		)	—			(2,013		)	—
Other non-current assets, net	—		37			169			—			206
Total assets	$	3,231	$	2,221		$	14,206		$	(2,105	)	$	17,553
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4		$	8		$	—		$	12
Accrued liabilities	23		8			606			—			637
Due to affiliates	—		47			66			(45		)	68
Deferred revenue	—		27			84			—			111
Deferred revenue—affiliate	—		22			—			(21		)	1
Other current liabilities—affiliate	—		1			—			(1		)	—
Total current liabilities	23		109			764			(67		)	829
Long-term debt, net	2,569		—			13,477			—			16,046
Non-current derivative liabilities	—		—			3			—			3
Other non-current liabilities	—		11			—			—			11
Other non-current liabilities—affiliate	—		25			—			—			25
Partners’ equity (deficit)	639		2,076			(38		)	(2,038		)	639
Total liabilities and partners’ equity (deficit)	$	3,231	$	2,221		$	14,206		$	(2,105	)	$	17,553

Condensed Consolidating Statements of Operations

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,249		$	—		$	1,249
LNG revenues—affiliate	—			—			205			—			205
Regasification revenues	—			66			—			—			66
Regasification revenues—affiliate	—			64			—			(64		)	—
Other revenues	—			9			—			—			9
Other revenues—affiliate	—			48			—			(48		)	—
Total revenues	—			187			1,454			(112		)	1,529
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			758			(2		)	756
Cost of sales—affiliate	—			—			8			(8		)	—
Operating and maintenance expense	—			17			96			—			113
Operating and maintenance expense—affiliate	—			39			107			(115		)	31
Development expense	—			1			—			—			1
General and administrative expense	1			1			1			—			3
General and administrative expense—affiliate	3			6			12			(3		)	18
Depreciation and amortization expense	1			19			88			(1		)	107
Impairment expense and loss on disposal of assets	—			8			—			—			8
Total operating costs and expenses	5			91			1,070			(129		)	1,037
Income (loss) from operations	(5		)	96			384			17			492
Other income (expense)
Interest expense, net of capitalized interest	(36		)	(1		)	(146		)	—			(183		)
Loss on modification or extinguishment of debt	(12		)	—			—			—			(12		)
Derivative gain, net	2			—			—			—			2
Equity earnings of subsidiaries	354			243			—			(597		)	—
Other income (expense)	4			(1		)	5			—			8
Total other income (expense)	312			241			(141		)	(597		)	(185		)
Net income	$	307		$	337		$	243		$	(580	)	$	307

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	723		$	—		$	723
LNG revenues—affiliate	—			—			111			—			111
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			48			—			(48		)	—
Other revenues	—			3			—			—			3
Other revenues—affiliate	—			51			—			(50		)	1
Total revenues	—			167			834			(98		)	903
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	—			(1		)	488			3			490
Cost of sales—affiliate	—			—			5			(5		)	—
Operating and maintenance expense	1			7			65			—			73
Operating and maintenance expense—affiliate	6			33			82			(90		)	31
Development expense	—			—			1			—			1
General and administrative expense	1			1			3			—			5
General and administrative expense—affiliate	3			6			12			(3		)	18
Depreciation and amortization expense	1			17			69			—			87
Other	—			1			—			—			1
Total operating costs and expenses	12			64			725			(95		)	706
Income (loss) from operations	(12		)	103			109			(3		)	197
Other income (expense)
Interest expense, net of capitalized interest	(29		)	—			(124		)	—			(153		)
Loss on modification or extinguishment of debt	(25		)	—			—			—			(25		)
Derivative gain, net	1			—			—			—			1
Equity earnings (losses) of subsidiaries	88			(12		)	—			(76		)	—
Other income	—			—			3			—			3
Total other income (expense)	35			(12		)	(121		)	(76		)	(174		)
Net income (loss)	$	23		$	91		$	(12	)	$	(79	)	$	23

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	3,419		$	—		$	3,419
LNG revenues—affiliate	—			—			886			—			886
Regasification revenues	—			196			—			—			196
Regasification revenues—affiliate	—			194			—			(194		)	—
Other revenues	—			28			—			—			28
Other revenues—affiliate	—			183			—			(183		)	—
Total revenues	—			601			4,305			(377		)	4,529
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			2			2,291			(2		)	2,291
Cost of sales—affiliate	—			—			23			(23		)	—
Operating and maintenance expense	—			48			258			—			306
Operating and maintenance expense—affiliate	—			113			317			(343		)	87
Development expense	—			1			1			—			2
General and administrative expense	3			2			4			—			9
General and administrative expense—affiliate	9			17			36			(9		)	53
Depreciation and amortization expense	2			56			261			(1		)	318
Impairment expense and loss on disposal of assets	—			8			—			—			8
Total operating costs and expenses	14			247			3,191			(378		)	3,074
Income (loss) from operations	(14		)	354			1,114			1			1,455
Other income (expense)
Interest expense, net of capitalized interest	(104		)	(3		)	(445		)	—			(552		)
Loss on modification or extinguishment of debt	(12		)	—			—			—			(12		)
Derivative gain, net	13			—			—			—			13
Equity earnings of subsidiaries	1,030			678			—			(1,708		)	—
Other income	10			—			9			—			19
Total other income (expense)	937			675			(436		)	(1,708		)	(532		)
Net income	$	923		$	1,029		$	678		$	(1,707	)	$	923

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,718		$	—		$	1,718
LNG revenues—affiliate	—			—			864			—			864
Regasification revenues	—			195			—			—			195
Regasification revenues—affiliate	—			128			—			(128		)	—
Other revenues	—			7			—			—			7
Other revenues—affiliate	—			162			—			(160		)	2
Total revenues	—			492			2,582			(288		)	2,786
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			1			1,576			3			1,580
Cost of sales—affiliate	—			—			15			(15		)	—
Operating and maintenance expense	4			29			172			—			205
Operating and maintenance expense—affiliate	6			96			224			(256		)	70
Development expense	—			—			2			—			2
General and administrative expense	3			2			5			—			10
General and administrative expense—affiliate	9			19			46			(11		)	63
Depreciation and amortization expense	1			55			183			—			239
Other	—			1			—			—			1
Total operating costs and expenses	23			203			2,223			(279		)	2,170
Income (loss) from operations	(23		)	289			359			(9		)	616
Other income (expense)
Interest expense, net of capitalized interest	(81		)	—			(356		)	—			(437		)
Loss on modification or extinguishment of debt	(25		)	—			(42		)	—			(67		)
Derivative loss, net	—			—			(2		)	—			(2		)
Equity earnings (losses) of subsidiaries	244			(36		)	—			(208		)	—
Other income	1			—			5			—			6
Total other income (expense)	139			(36		)	(395		)	(208		)	(500		)
Net income (loss)	$	116		$	253		$	(36	)	$	(217	)	$	116

Condensed Consolidating Statements of Cash Flows

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by operating activities	$	339		$	408		$	928		$	(411	)	$	1,264
Cash flows from investing activities
Property, plant and equipment, net	—			(24		)	(554		)	—			(578		)
Investments in subsidiaries	(202		)	(81		)	—			283			—
Distributions received from affiliates, net	447			350			—			(797		)	—
Net cash provided by (used in) investing activities	245			245			(554		)	(514		)	(578		)
Cash flows from financing activities
Proceeds from issuances of debt	1,100			—			—			—			1,100
Repayments of debt	(1,090		)	—			—			—			(1,090		)
Debt issuance and deferred financing costs	(8		)	—			—			—			(8		)
Debt extinguishment costs	(6		)	—			—			—			(6		)
Distributions to parent	—			(858		)	(350		)	1,208			—
Contributions from parent	—			202			81			(283		)	—
Distributions to owners	(814		)	—			—			—			(814		)
Net cash used in financing activities	(818		)	(656		)	(269		)	925			(818		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(234		)	(3		)	105			—			(132		)
Cash, cash equivalents and restricted cash—beginning of period	1,033			12			544			—			1,589
Cash, cash equivalents and restricted cash—end of period	$	799		$	9		$	649		$	—		$	1,457

Balances per Condensed Consolidating Balance Sheet:

	September 30, 2018
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Restricted cash	799		9		649		—		1,457
Total cash, cash equivalents and restricted cash	$	799	$	9	$	649	$	—	$	1,457

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(89	)	$	293		$	317		$	(8	)	$	513
Cash flows from investing activities
Property, plant and equipment, net	—			(16		)	(1,187		)	8			(1,195		)
Investments in subsidiaries	(216		)	(7		)	—			223			—
Distributions received from affiliates, net	929			450			—			(1,379		)	—
Net cash provided by (used in) investing activities	713			427			(1,187		)	(1,148		)	(1,195		)
Cash flows from financing activities
Proceeds from issuances of debt	1,500			—			2,314			—			3,814
Repayments of debt	(1,470		)	—			(703		)	—			(2,173		)
Debt issuance and deferred financing costs	(18		)	—			(29		)	—			(47		)
Distributions to parent	—			(929		)	(450		)	1,379			—
Contributions from parent	—			216			7			(223		)	—
Distributions to owners	(74		)	—			—			—			(74		)
Net cash provided by (used in) financing activities	(62		)	(713		)	1,139			1,156			1,520
Net increase in cash, cash equivalents and restricted cash	562			7			269			—			838
Cash, cash equivalents and restricted cash—beginning of period	234			13			358			—			605
Cash, cash equivalents and restricted cash—end of period	$	796		$	20		$	627		$	—		$	1,443

XML

Nature of Operations and Basis of Presentation (Details)	9 Months Ended
	Sep. 30, 2018 mi trains
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	6
CTPL [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length Of Natural Gas Pipeline | mi	94

XML

Unitholders' Equity (Details)	9 Months Ended
	Sep. 30, 2018 $ / shares
Maximum [Member]
Other Ownership Interests [Line Items]
Number of days after quarter end distribution is paid	45 days
Common Units [Member]
Other Ownership Interests [Line Items]
Distributions Per Limited Partnership Unit Outstanding, Basic	$ 0.425
General Partner [Member] | Minimum [Member]
Other Ownership Interests [Line Items]
Distributions entitled by General Partner, Percentage	2.00%
Incentive Distribution, Quarterly Distribution Additional Target Percentage	15.00%
General Partner [Member] | Maximum [Member]
Other Ownership Interests [Line Items]
Incentive Distribution, Quarterly Distribution Additional Target Percentage	50.00%
Cheniere [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	48.60%
Blackstone [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	40.30%
Public [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	9.10%

XML

Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 1,457	$ 1,589
Liquefaction Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	649	544
Cash held by us and our guarantor subsidiaries [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 808	$ 1,045

XML

Accounts and Other Receivables (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Receivables [Abstract]
SPL trade receivable	$ 213	$ 185
Other accounts receivable	11	6
Total accounts and other receivables	$ 224	$ 191

XML

Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Inventory [Line Items]
Inventory	$ 88	$ 95
Natural gas [Member]
Inventory [Line Items]
Inventory	9	17
LNG [Member]
Inventory [Line Items]
Inventory	21	26
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 58	$ 52

XML

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 15,282	$ 15,139
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(1,187)	(880)
Property, plant and equipment, net	15,276	15,133
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	12,706	12,703
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	3,757	3,310
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	26	23
Accumulated depreciation	(20)	(17)
Property, plant and equipment, net	$ 6	$ 6

XML

Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Property, Plant and Equipment [Abstract]
Depreciation	$ 104	$ 85	$ 310	$ 233
Offsets to LNG terminal costs	$ 0	$ 79	$ 0	$ 242

XML

Derivative Instruments - Narrative (Details) $ in Millions	1 Months Ended			9 Months Ended
	Oct. 31, 2018 USD ($)	Sep. 30, 2018 USD ($) tbtu	Mar. 31, 2017 USD ($)	Sep. 30, 2018 tbtu	Dec. 31, 2017 tbtu
CQP Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease		$ 1,200
CQP Interest Rate Derivatives [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Gain (Loss), Net	$ 28
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract				6 years
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount | tbtu		2,206		2,206	1,520
SPL [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Energy Units Secured Through Natural Gas Supply Contracts | tbtu		2,755		2,755	2,214
SPL [Member] | SPL Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease			$ 1,600
SPL [Member] | SPL Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Gain (Loss), Net			$ (7)

XML

Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
CQP Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 28	$ 21
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	28	21
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	19	55
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(1)	2
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	1	10
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 19	$ 43

XML

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	9 Months Ended
	Sep. 30, 2018 USD ($)
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset	$ 19,000,000
Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	(0.448)
Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	$ 0.079

XML

Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ 11	$ 40	$ 43	$ 79
Realized and mark-to-market gains (losses):
Included in cost of sales		4	(8)	(5)	(43)
Purchases and settlements:
Purchases		4	(1)	8	1
Settlements		1	(2)	(27)	(8)
Transfers out of Level 3	[1]	(1)	0	0	0
Balance, end of period		19	29	19	29
Change in unrealized gains relating to instruments still held at end of period		$ 4	$ (8)	$ (5)	$ (43)

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

XML

Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - CQP Interest Rate Derivatives [Member] $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Derivative [Line Items]
Notional Amount	$ 225
Effective Date	Mar. 22, 2016
Maturity Date	Feb. 29, 2020
Weighted Average Fixed Interest Rate Paid	1.19%
Variable Interest Rate Received	One-month LIBOR
Maximum [Member]
Derivative [Line Items]
Notional Amount	$ 1,300

XML

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Non-current derivative assets		$ 25	$ 31
Derivative liabilities		(6)	0
Non-current derivative liabilities		(2)	(3)
CQP Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		28	21
CQP Interest Rate Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		19	7
CQP Interest Rate Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		9	14
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[1]	27	58
Total derivative liabilities	[1]	(8)	(3)
Derivative asset, net	[1]	19	55
Derivative, collateral call		2	1
Liquefaction Supply Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	11	41
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[1]	16	17
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(6)	0
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[1]	$ (2)	$ (3)

[1] Does not include collateral calls of $2 million and $1 million as of September 30, 2018 and December 31, 2017, respectively, for such contracts, which are included in other current assets in our Consolidated Balance Sheets.

XML

Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
CQP Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 2	$ 1	$ 13	$ 0
SPL Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		0	0	0	(2)
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 10	$ (11)	$ (42)	$ (51)

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

XML

Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
CQP Interest Rate Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 28	$ 21
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Derivative Assets (Liabilities), at Fair Value, Net	28	21
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	31	64
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(4)	(6)
Derivative Assets (Liabilities), at Fair Value, Net	27	58
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(13)	(3)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	5	0
Derivative Assets (Liabilities), at Fair Value, Net	$ (8)	$ (3)

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Other Non-Current Assets (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Other Assets, Noncurrent [Abstract]
Advances made under EPC and non-EPC contracts	$ 15	$ 26
Advances made to municipalities for water system enhancements	90	93
Advances and other asset conveyances to third parties to support LNG terminals	29	30
Tax-related payments and receivables	17	25
Information technology service assets	20	24
Other	8	8
Other non-current assets, net	$ 179	$ 206

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Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 186	$ 253
Accrued natural gas purchases	249	298
LNG terminal and related pipeline costs	59	86
Other accrued liabilities	9	0
Total accrued liabilities	$ 503	$ 637

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Debt - Schedule of Debt Instruments (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net	$ (191,000,000)	$ (194,000,000)
Long-term Debt, Net	16,059,000,000	16,046,000,000
Current Debt, Working Capital Facility	0	0
Total Debt, Net	16,059,000,000	16,046,000,000
2021 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2022 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,000,000,000	1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.25%
2023 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%
2025 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,350,000,000	1,350,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.20%
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 800,000,000	800,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2025 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.25%
2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,100,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	5.625%
CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	1,090,000,000
SPL 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 - Debt Issuances and Redemptions - CQP 2026 Senior Notes (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Debt Instrument [Line Items]
Loss on modification or extinguishment of debt		$ 12	$ 25	$ 12	$ 67
2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 1,100	1,100		1,100
Proceeds from Debt, Net of Issuance Costs	$ 1,100
Loss on modification or extinguishment of debt		$ 12		$ 12
Debt Instrument, Interest Rate, Stated Percentage	5.625%	5.625%		5.625%
Debt Instrument, Redemption Price, Percentage				100.00%
Debt Instrument, Redemption Price, Percentage Price For Amount Which May Be Redeemed With Cash Proceeds From Certain Equity Offerings				105.625%
Debt Instrument Registration Period				360 days
2026 CQP Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Amount, Percentage of Principal Amount Which May Be Redeemed With Cash Proceeds From Certain Equity Offerings				35.00%
CQP Credit Facilities - Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Available commitment	$ 115	$ 115		$ 115
CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Monetary Amount	$ 1,500	$ 1,500		$ 1,500
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Percentage of Net Tangible Assets				10.00%

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Debt - Credit Facilities Table (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Outstanding balance, current		$ 0	$ 0
SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size		1,200
Outstanding balance, current		0	0
Commitments prepaid or terminated		0
Letters of credit issued		494
Available commitment		$ 706
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
SPL 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%
SPL Working Capital Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 2,800
Outstanding balance		0	$ 1,090
Commitments prepaid or terminated		2,685
Letters of credit issued		0
Available commitment		$ 115
Debt Instrument, Description of Variable Rate Basis	[1]	LIBOR or base rate
Debt Instrument, Maturity Date, Description		February 25, 2020
CQP Credit Facilities [Member] | February 25, 2019 [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase		0.50%
CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]	2.25%
CQP Credit Facilities [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]	1.25%

[1] There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Debt Disclosure [Abstract]
Total interest cost	$ 235	$ 227	$ 701	$ 662
Capitalized interest	(52)	(74)	(149)	(225)
Total interest expense, net	$ 183	$ 153	$ 552	$ 437

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 16,059	$ 16,046
Senior notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	15,268	14,166
Senior notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	16,098	15,485
2037 SPL Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	791	790
2037 SPL Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	831	871
Credit facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[3]	0	1,090
Credit facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facilities, Estimated Fair Value	[3]	$ 0	$ 1,090

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

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

[3] Includes SPL Working Capital Facility and CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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Revenues from Contracts with Customers (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) bcf / d item	Sep. 30, 2017 USD ($)
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
Regasification Capacity | bcf / d			4.0
Operating and maintenance expense | $	$ 113.0	$ 73.0	$ 306.0	$ 205.0
TUA Customers [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d			2.0
Number Of Fixed Price Contracts | item			2
TUA Customer 1 [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d			1.0
Revenue, Performance Obligation, Fixed Consideration | $			$ 125.0
Long-term Purchase Commitment, Period			20 years
TUA Customer 2 [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d			1.0
Revenue, Performance Obligation, Fixed Consideration | $			$ 125.0
Long-term Purchase Commitment, Period			20 years
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	55.00%		55.00%
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	100.00%		100.00%
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	3.00%		3.00%
Partial TUA Regasification Capacity [Member]
Disaggregation of Revenue [Line Items]
Operating and maintenance expense | $	$ 7.5	$ 7.5	$ 23.0	$ 15.0

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Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		$ 1,465	$ 897	$ 4,412	$ 2,763
Total revenues		1,529	903	4,529	2,786
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		1,185	717	3,302	1,695
Total revenues		1,249	723	3,419	1,718
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		205	111	886	864
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		66	65	196	195
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		9	3	28	7
Other—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers		0	1	0	2
Derivative Instruments [Member]
Disaggregation of Revenue [Line Items]
Total revenues	[1]	$ 64	$ 6	$ 117	$ 23

[1] Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.

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Revenues from Contracts with Customers - Schedule of Deferred Revenue Reconciliation (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	$ 111
Cash received but not yet recognized	119
Revenue recognized from prior period deferral	(111)
Deferred revenues, end of period	$ 119

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Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) $ in Billions	Sep. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 56.9
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 54.2
Weighted Average Recognition Timing	10 years 73 days	[1]
Regasification [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 2.7
Weighted Average Recognition Timing	5 years 299 days	[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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	$ 31	$ 31	$ 87	$ 70
General and administrative expense—affiliate	18	18	53	63
Cheniere Marketing SPA and Cheniere Marketing Master SPA [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	205	111	886	864
Terminal Marine Services Agreement [Member]
Related Party Transaction [Line Items]
Other revenues—affiliate	0	1	0	2
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	31	25	87	64
General and administrative expense—affiliate	18	18	53	63
Other Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	$ 0	$ 6	$ 0	$ 6

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Related Party Transactions - LNG Terminal Capacity Agreements (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) bcf / d $ / MMBTU	Sep. 30, 2017 USD ($)
Related Party Transaction [Line Items]
Regasification Capacity | bcf / d			4.0
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
Terminal Use Agreement [Member] | SPLNG [Member] | SPL [Member]
Related Party Transaction [Line Items]
Regasification Capacity | bcf / d			2.0
Related Party Transaction, Committed Annual Fee | $			$ 250,000,000
Amended and Restated Variable Capacity Rights Agreement [Member] | Cheniere Marketing [Member] | Cheniere Investments [Member]
Related Party Transaction [Line Items]
Proceeds (Payments) of Gross Margin Earned, Percentage			80.00%
LNG revenues—affiliate | $	$ 0	$ 0	$ 0	$ 0
LNG Sale and Purchase Agreement [Member] | Cheniere Marketing [Member] | SPL [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
LNG Volume, Purchase Price Per MMBtu | $ / MMBTU			3.00

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Related Party Transactions - Service Agreements (Details) - USD ($)	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 189,000,000	$ 36,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	189,000,000	$ 36,000,000
Cheniere Partners Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Quarterly non-accountable overhead reimbursement charge	$ 3,000,000
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | SPL [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
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 130,000
Related Party Transaction, Bonus Percentage of Salary Entitled Upon Meeting Certain Criteria	50.00%
Management Services Agreement [Member] | Cheniere Terminals [Member] | SPL [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
Management Services Agreement [Member] | Cheniere Terminals [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 520,000

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Related Party Transactions - Other Agreements (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Due to affiliates	$ 53,000,000		$ 53,000,000		$ 68,000,000
Other non-current liabilities—affiliate	23,000,000		$ 23,000,000		25,000,000
Cooperative Endeavor Agreements [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Tax Initiative Agreement Term			10 years
Aggregate commitment under the Agreement	25,000,000		$ 25,000,000
Cooperative Endeavor Agreements [Member] | Cheniere Marketing [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Due to affiliates	2,000,000		2,000,000
Other non-current liabilities—affiliate	23,000,000		23,000,000		$ 25,000,000
Terminal Marine Services Agreement [Member] | Wholly owned subsidiary of Cheniere [Member] | Tug Services [Member]
Related Party Transaction [Line Items]
General Partner Distributions			4,000,000
LNG Terminal Export Agreement [Member] | Cheniere Marketing [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 0	$ 0	0	$ 0
Tax Sharing Agreement [Member] | Cheniere [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			0
Tax Sharing Agreement [Member] | Cheniere [Member] | SPL [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			0
Tax Sharing Agreement [Member] | Cheniere [Member] | CTPL [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			$ 0

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Net Income (Loss) per Common Unit - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions		9 Months Ended
	Oct. 26, 2018	Sep. 30, 2018
Class B Units [Member]
Distribution Made to Limited Partner [Line Items]
Discount upon issuance of Class B units representing beneficial conversion feature		$ 2,130
Cheniere Holdings [Member] | Class B Units [Member] | Effective Yield Method [Member]
Distribution Made to Limited Partner [Line Items]
Amortization of Beneficial Conversion Feature of Class B Units		888.70%
Blackstone [Member] | Class B Units [Member] | Effective Yield Method [Member]
Distribution Made to Limited Partner [Line Items]
Amortization of Beneficial Conversion Feature of Class B Units		966.10%
Subsequent Event [Member] | Common Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.58
Subsequent Event [Member] | Subordinated Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.58

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Net Income (Loss) per Common Unit - Schedule of Net Income (Loss) per Unit and Allocation of Distribution (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2018		Sep. 30, 2017		Sep. 30, 2018		Sep. 30, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income	$ 307		$ 23		$ 923		$ 116
Declared distributions	297		217		859		267
Amortization of beneficial conversion feature of Class B units			0				0
Assumed allocation of undistributed net income	$ 10	[1]	$ (194)		$ 64	[1]	$ (151)
Weighted average units outstanding	348.6		247.2		348.6		121.2
Basic and diluted net income (loss) per unit	$ 0.60		$ (1.10)		$ 1.82		$ (4.12)
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income					$ 651
Declared distributions	$ 202		$ 153		589		$ 202
Amortization of beneficial conversion feature of Class B units			(288)				(594)
Assumed allocation of undistributed net income	7	[1]	(137)		45	[1]	(107)
Assumed allocation of net income	$ 209		$ (272)		$ 634		$ (499)
Weighted average units outstanding	348.6		247.2		348.6		121.2
Basic and diluted net income (loss) per unit	$ 0.60	[2]	$ (1.10)	[2]	$ 1.82		$ (4.12)	[2]
Class B Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions	$ 0		$ 0		$ 0		$ 0
Amortization of beneficial conversion feature of Class B units			974				2,004
Assumed allocation of undistributed net income	0	[1]	0		0	[1]	0
Assumed allocation of net income	$ 0		$ 974		$ 0		$ 2,004
Weighted average units outstanding	0.0		50.6		0.0		113.4
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income					$ 253
Declared distributions	$ 79		$ 60		229		$ 60
Amortization of beneficial conversion feature of Class B units			(686)				(1,410)
Assumed allocation of undistributed net income	3	[1]	(53)		18	[1]	(41)
Assumed allocation of net income	$ 82		$ (679)		$ 247		$ (1,391)
Weighted average units outstanding	135.4		135.4		135.4		135.4
Basic and diluted net income (loss) per unit	$ 0.60	[2]	$ (5.02)	[2]	$ 1.82		$ (10.28)	[2]
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income					$ 19
Declared distributions	$ 5		$ 4		17		$ 5
Amortization of beneficial conversion feature of Class B units			0				0
Assumed allocation of undistributed net income	0	[1]	(4)		1	[1]	(3)
Assumed allocation of net income	5		0		18		2
IDR [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions	11		0		24		0
Amortization of beneficial conversion feature of Class B units			0				0
Assumed allocation of undistributed net income	0	[1]	0		0	[1]	0
Assumed allocation of net income	$ 11		$ 0		$ 24		$ 0

[1] Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss).

[2] Earnings per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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Customer Concentration (Details)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Customer A [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	24.00%	31.00%	27.00%	42.00%
Customer A [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			28.00%		39.00%
Customer B [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	21.00%	24.00%	22.00%	26.00%
Customer B [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			26.00%		32.00%
Customer C [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	21.00%	35.00%	23.00%	18.00%
Customer C [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			22.00%		26.00%
Customer D [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	24.00%	0.00%	18.00%	0.00%
Customer D [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			19.00%		0.00%

XML

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 586	$ 459
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 204	$ 247

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Supplemental Guarantor Information - Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 0	$ 0
Restricted cash	1,457	1,589
Accounts and other receivables	224	191
Accounts receivable—affiliate	22	163
Advances to affiliate	189	36
Inventory	88	95
Other current assets	55	65
Other current assets—affiliate	0	0
Total current assets	2,035	2,139
Property, plant and equipment, net	15,282	15,139
Debt issuance costs, net	15	38
Non-current derivative assets	25	31
Investments in subsidiaries	0	0
Other non-current assets, net	179	206
Total assets	17,536	17,553
Current liabilities
Accounts payable	13	12
Accrued liabilities	503	637
Due to affiliates	53	68
Deferred revenue	119	111
Deferred revenue—affiliate	0	1
Derivative liabilities	6	0
Other current liabilities—affiliate		0
Total current liabilities	694	829
Long-term debt, net	16,059	16,046
Non-current derivative liabilities	2	3
Other non-current liabilities	10	11
Other non-current liabilities—affiliate	23	25
Partners’ equity (deficit)	748	639
Total liabilities and partners’ equity (deficit)	17,536	17,553
Parent Issuer [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	799	1,033
Accounts and other receivables	1	0
Accounts receivable—affiliate	1	0
Advances to affiliate	0	0
Inventory	0	0
Other current assets	19	8
Other current assets—affiliate	0	0
Total current assets	820	1,041
Property, plant and equipment, net	79	80
Debt issuance costs, net	1	20
Non-current derivative assets	9	14
Investments in subsidiaries	2,449	2,076
Other non-current assets, net	0	0
Total assets	3,358	3,231
Current liabilities
Accounts payable	1	0
Accrued liabilities	44	23
Due to affiliates	0	0
Deferred revenue	0	0
Deferred revenue—affiliate	0	0
Derivative liabilities	0
Other current liabilities—affiliate		0
Total current liabilities	45	23
Long-term debt, net	2,565	2,569
Non-current derivative liabilities	0	0
Other non-current liabilities	0	0
Other non-current liabilities—affiliate	0	0
Partners’ equity (deficit)	748	639
Total liabilities and partners’ equity (deficit)	3,358	3,231
Guarantors [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	9	12
Accounts and other receivables	1	2
Accounts receivable—affiliate	46	36
Advances to affiliate	100	20
Inventory	12	10
Other current assets	1	3
Other current assets—affiliate	0	0
Total current assets	169	83
Property, plant and equipment, net	2,136	2,164
Debt issuance costs, net	0	0
Non-current derivative assets	0	0
Investments in subsidiaries	347	(63)
Other non-current assets, net	27	37
Total assets	2,679	2,221
Current liabilities
Accounts payable	5	4
Accrued liabilities	20	8
Due to affiliates	132	47
Deferred revenue	24	27
Deferred revenue—affiliate	21	22
Derivative liabilities	0
Other current liabilities—affiliate		1
Total current liabilities	202	109
Long-term debt, net	0	0
Non-current derivative liabilities	0	0
Other non-current liabilities	5	11
Other non-current liabilities—affiliate	23	25
Partners’ equity (deficit)	2,449	2,076
Total liabilities and partners’ equity (deficit)	2,679	2,221
Non-Guarantors [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	649	544
Accounts and other receivables	222	189
Accounts receivable—affiliate	21	163
Advances to affiliate	174	26
Inventory	76	85
Other current assets	35	54
Other current assets—affiliate	21	21
Total current assets	1,198	1,082
Property, plant and equipment, net	13,091	12,920
Debt issuance costs, net	14	18
Non-current derivative assets	16	17
Investments in subsidiaries	0	0
Other non-current assets, net	152	169
Total assets	14,471	14,206
Current liabilities
Accounts payable	7	8
Accrued liabilities	439	606
Due to affiliates	52	66
Deferred revenue	95	84
Deferred revenue—affiliate	0	0
Derivative liabilities	6
Other current liabilities—affiliate		0
Total current liabilities	599	764
Long-term debt, net	13,494	13,477
Non-current derivative liabilities	2	3
Other non-current liabilities	5	0
Other non-current liabilities—affiliate	0	0
Partners’ equity (deficit)	371	(38)
Total liabilities and partners’ equity (deficit)	14,471	14,206
Eliminations [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	0	0
Accounts and other receivables	0	0
Accounts receivable—affiliate	(46)	(36)
Advances to affiliate	(85)	(10)
Inventory	0	0
Other current assets	0	0
Other current assets—affiliate	(21)	(21)
Total current assets	(152)	(67)
Property, plant and equipment, net	(24)	(25)
Debt issuance costs, net	0	0
Non-current derivative assets	0	0
Investments in subsidiaries	(2,796)	(2,013)
Other non-current assets, net	0	0
Total assets	(2,972)	(2,105)
Current liabilities
Accounts payable	0	0
Accrued liabilities	0	0
Due to affiliates	(131)	(45)
Deferred revenue	0	0
Deferred revenue—affiliate	(21)	(21)
Derivative liabilities	0
Other current liabilities—affiliate		(1)
Total current liabilities	(152)	(67)
Long-term debt, net	0	0
Non-current derivative liabilities	0	0
Other non-current liabilities	0	0
Other non-current liabilities—affiliate	0	0
Partners’ equity (deficit)	(2,820)	(2,038)
Total liabilities and partners’ equity (deficit)	$ (2,972)	$ (2,105)

XML

Supplemental Guarantor Information - Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues
Revenue earned from contracts with customers	$ 1,465	$ 897	$ 4,412	$ 2,763
Revenues	1,529	903	4,529	2,786
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	756	490	2,291	1,580
Cost of sales—affiliate	0	0	0	0
Operating and maintenance expense	113	73	306	205
Operating and maintenance expense—affiliate	31	31	87	70
Development expense	1	1	2	2
General and administrative expense	3	5	9	10
General and administrative expense—affiliate	18	18	53	63
Depreciation and amortization expense	107	87	318	239
Other	0	1	0	1
Impairment expense and loss on disposal of assets	8	0	8	0
Total operating costs and expenses	1,037	706	3,074	2,170
Income (loss) from operations	492	197	1,455	616
Other income (expense)
Interest expense, net of capitalized interest	(183)	(153)	(552)	(437)
Loss on modification or extinguishment of debt	(12)	(25)	(12)	(67)
Derivative gain (loss), net	2	1	13	(2)
Equity earnings (losses) of subsidiaries	0	0	0	0
Other income	8	3	19	6
Total other income (expense)	(185)	(174)	(532)	(500)
Net income (loss)	307	23	923	116
LNG [Member]
Revenues
Revenue earned from contracts with customers	1,185	717	3,302	1,695
Revenues	1,249	723	3,419	1,718
LNG—affiliate [Member]
Revenues
Revenue earned from contracts with customers	205	111	886	864
Regasification [Member]
Revenues
Revenue earned from contracts with customers	66	65	196	195
Regasification—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Other [Member]
Revenues
Revenue earned from contracts with customers	9	3	28	7
Other—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	1	0	2
Parent Issuer [Member]
Revenues
Revenues	0	0	0	0
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	0	0	0	0
Cost of sales—affiliate	0	0	0	0
Operating and maintenance expense	0	1	0	4
Operating and maintenance expense—affiliate	0	6	0	6
Development expense	0	0	0	0
General and administrative expense	1	1	3	3
General and administrative expense—affiliate	3	3	9	9
Depreciation and amortization expense	1	1	2	1
Other		0		0
Impairment expense and loss on disposal of assets	0		0
Total operating costs and expenses	5	12	14	23
Income (loss) from operations	(5)	(12)	(14)	(23)
Other income (expense)
Interest expense, net of capitalized interest	(36)	(29)	(104)	(81)
Loss on modification or extinguishment of debt	(12)	(25)	(12)	(25)
Derivative gain (loss), net	2	1	13	0
Equity earnings (losses) of subsidiaries	354	88	1,030	244
Other income	4	0	10	1
Total other income (expense)	312	35	937	139
Net income (loss)	307	23	923	116
Parent Issuer [Member] | LNG [Member]
Revenues
Revenues	0	0	0	0
Parent Issuer [Member] | LNG—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Parent Issuer [Member] | Regasification [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Parent Issuer [Member] | Regasification—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Parent Issuer [Member] | Other [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Parent Issuer [Member] | Other—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Guarantors [Member]
Revenues
Revenues	187	167	601	492
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	0	(1)	2	1
Cost of sales—affiliate	0	0	0	0
Operating and maintenance expense	17	7	48	29
Operating and maintenance expense—affiliate	39	33	113	96
Development expense	1	0	1	0
General and administrative expense	1	1	2	2
General and administrative expense—affiliate	6	6	17	19
Depreciation and amortization expense	19	17	56	55
Other		1		1
Impairment expense and loss on disposal of assets	8		8
Total operating costs and expenses	91	64	247	203
Income (loss) from operations	96	103	354	289
Other income (expense)
Interest expense, net of capitalized interest	(1)	0	(3)	0
Loss on modification or extinguishment of debt	0	0	0	0
Derivative gain (loss), net	0	0	0	0
Equity earnings (losses) of subsidiaries	243	(12)	678	(36)
Other income	(1)	0	0	0
Total other income (expense)	241	(12)	675	(36)
Net income (loss)	337	91	1,029	253
Guarantors [Member] | LNG [Member]
Revenues
Revenues	0	0	0	0
Guarantors [Member] | LNG—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Guarantors [Member] | Regasification [Member]
Revenues
Revenue earned from contracts with customers	66	65	196	195
Guarantors [Member] | Regasification—affiliate [Member]
Revenues
Revenue earned from contracts with customers	64	48	194	128
Guarantors [Member] | Other [Member]
Revenues
Revenue earned from contracts with customers	9	3	28	7
Guarantors [Member] | Other—affiliate [Member]
Revenues
Revenue earned from contracts with customers	48	51	183	162
Non-Guarantors [Member]
Revenues
Revenues	1,454	834	4,305	2,582
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	758	488	2,291	1,576
Cost of sales—affiliate	8	5	23	15
Operating and maintenance expense	96	65	258	172
Operating and maintenance expense—affiliate	107	82	317	224
Development expense	0	1	1	2
General and administrative expense	1	3	4	5
General and administrative expense—affiliate	12	12	36	46
Depreciation and amortization expense	88	69	261	183
Other		0		0
Impairment expense and loss on disposal of assets	0		0
Total operating costs and expenses	1,070	725	3,191	2,223
Income (loss) from operations	384	109	1,114	359
Other income (expense)
Interest expense, net of capitalized interest	(146)	(124)	(445)	(356)
Loss on modification or extinguishment of debt	0	0	0	(42)
Derivative gain (loss), net	0	0	0	(2)
Equity earnings (losses) of subsidiaries	0	0	0	0
Other income	5	3	9	5
Total other income (expense)	(141)	(121)	(436)	(395)
Net income (loss)	243	(12)	678	(36)
Non-Guarantors [Member] | LNG [Member]
Revenues
Revenues	1,249	723	3,419	1,718
Non-Guarantors [Member] | LNG—affiliate [Member]
Revenues
Revenue earned from contracts with customers	205	111	886	864
Non-Guarantors [Member] | Regasification [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Non-Guarantors [Member] | Regasification—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Non-Guarantors [Member] | Other [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Non-Guarantors [Member] | Other—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Eliminations [Member]
Revenues
Revenues	(112)	(98)	(377)	(288)
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	(2)	3	(2)	3
Cost of sales—affiliate	(8)	(5)	(23)	(15)
Operating and maintenance expense	0	0	0	0
Operating and maintenance expense—affiliate	(115)	(90)	(343)	(256)
Development expense	0	0	0	0
General and administrative expense	0	0	0	0
General and administrative expense—affiliate	(3)	(3)	(9)	(11)
Depreciation and amortization expense	(1)	0	(1)	0
Other		0		0
Impairment expense and loss on disposal of assets	0		0
Total operating costs and expenses	(129)	(95)	(378)	(279)
Income (loss) from operations	17	(3)	1	(9)
Other income (expense)
Interest expense, net of capitalized interest	0	0	0	0
Loss on modification or extinguishment of debt	0	0	0	0
Derivative gain (loss), net	0	0	0	0
Equity earnings (losses) of subsidiaries	(597)	(76)	(1,708)	(208)
Other income	0	0	0	0
Total other income (expense)	(597)	(76)	(1,708)	(208)
Net income (loss)	(580)	(79)	(1,707)	(217)
Eliminations [Member] | LNG [Member]
Revenues
Revenues	0	0	0	0
Eliminations [Member] | LNG—affiliate [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Eliminations [Member] | Regasification [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Eliminations [Member] | Regasification—affiliate [Member]
Revenues
Revenue earned from contracts with customers	(64)	(48)	(194)	(128)
Eliminations [Member] | Other [Member]
Revenues
Revenue earned from contracts with customers	0	0	0	0
Eliminations [Member] | Other—affiliate [Member]
Revenues
Revenue earned from contracts with customers	$ (48)	$ (50)	$ (183)	$ (160)

XML

Supplemental Guarantor Information - Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 1,264	$ 513
Cash flows from investing activities
Property, plant and equipment, net	(578)	(1,195)
Investments in subsidiaries	0	0
Distributions received from affiliates, net	0	0
Net cash provided by (used in) investing activities	(578)	(1,195)
Cash flows from financing activities
Proceeds from issuances of debt	1,100	3,814
Repayments of debt	(1,090)	(2,173)
Debt issuance and deferred financing costs	(8)	(47)
Debt extinguishment costs	(6)	0
Distributions to parent	0	0
Contributions from parent	0	0
Distributions to owners	(814)	(74)
Net cash provided by (used in) financing activities	(818)	1,520
Net increase (decrease) in cash, cash equivalents and restricted cash	(132)	838
Cash, cash equivalents and restricted cash—beginning of period	1,589	605
Cash, cash equivalents and restricted cash—end of period	1,457	1,443
Parent Issuer [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	339	(89)
Cash flows from investing activities
Property, plant and equipment, net	0	0
Investments in subsidiaries	(202)	(216)
Distributions received from affiliates, net	447	929
Net cash provided by (used in) investing activities	245	713
Cash flows from financing activities
Proceeds from issuances of debt	1,100	1,500
Repayments of debt	(1,090)	(1,470)
Debt issuance and deferred financing costs	(8)	(18)
Debt extinguishment costs	(6)
Distributions to parent	0	0
Contributions from parent	0	0
Distributions to owners	(814)	(74)
Net cash provided by (used in) financing activities	(818)	(62)
Net increase (decrease) in cash, cash equivalents and restricted cash	(234)	562
Cash, cash equivalents and restricted cash—beginning of period	1,033	234
Cash, cash equivalents and restricted cash—end of period	799	796
Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	408	293
Cash flows from investing activities
Property, plant and equipment, net	(24)	(16)
Investments in subsidiaries	(81)	(7)
Distributions received from affiliates, net	350	450
Net cash provided by (used in) investing activities	245	427
Cash flows from financing activities
Proceeds from issuances of debt	0	0
Repayments of debt	0	0
Debt issuance and deferred financing costs	0	0
Debt extinguishment costs	0
Distributions to parent	(858)	(929)
Contributions from parent	202	216
Distributions to owners	0	0
Net cash provided by (used in) financing activities	(656)	(713)
Net increase (decrease) in cash, cash equivalents and restricted cash	(3)	7
Cash, cash equivalents and restricted cash—beginning of period	12	13
Cash, cash equivalents and restricted cash—end of period	9	20
Non-Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	928	317
Cash flows from investing activities
Property, plant and equipment, net	(554)	(1,187)
Investments in subsidiaries	0	0
Distributions received from affiliates, net	0	0
Net cash provided by (used in) investing activities	(554)	(1,187)
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	(29)
Debt extinguishment costs	0
Distributions to parent	(350)	(450)
Contributions from parent	81	7
Distributions to owners	0	0
Net cash provided by (used in) financing activities	(269)	1,139
Net increase (decrease) in cash, cash equivalents and restricted cash	105	269
Cash, cash equivalents and restricted cash—beginning of period	544	358
Cash, cash equivalents and restricted cash—end of period	649	627
Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(411)	(8)
Cash flows from investing activities
Property, plant and equipment, net	0	8
Investments in subsidiaries	283	223
Distributions received from affiliates, net	(797)	(1,379)
Net cash provided by (used in) investing activities	(514)	(1,148)
Cash flows from financing activities
Proceeds from issuances of debt	0	0
Repayments of debt	0	0
Debt issuance and deferred financing costs	0	0
Debt extinguishment costs	0
Distributions to parent	1,208	1,379
Contributions from parent	(283)	(223)
Distributions to owners	0	0
Net cash provided by (used in) financing activities	925	1,156
Net increase (decrease) in cash, cash equivalents and restricted cash	0	0
Cash, cash equivalents and restricted cash—beginning of period	0	0
Cash, cash equivalents and restricted cash—end of period	$ 0	$ 0

XML

Supplemental Guarantor Information Supplemental Guarantor Information - Condensed Consolidating Cash Flows - Balances per Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	$ 0	$ 0
Restricted cash	1,457	1,589
Total cash, cash equivalents and restricted cash	1,457	1,589	$ 1,443	$ 605
Parent Issuer [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	799	1,033
Total cash, cash equivalents and restricted cash	799	1,033	796	234
Guarantors [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	9	12
Total cash, cash equivalents and restricted cash	9	12	20	13
Non-Guarantors [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	649	544
Total cash, cash equivalents and restricted cash	649	544	627	358
Eliminations [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	0	0
Total cash, cash equivalents and restricted cash	$ 0	$ 0	$ 0	$ 0