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 March 31, 2016

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

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

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

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

As of April 29, 2016, the issuer had 57,102,848 common units, 145,333,334 Class B 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 Operations	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	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36
Item 4.	Controls and Procedures	36
Part II. Other Information
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 5.	Other Information	37
Item 6.	Exhibits	39
	Signatures	40

i

DEFINITIONS

As commonly used in the liquefied natural gas industry, to the extent applicable and as used in this quarterly report, the terms listed below have the following meanings: 

Common Industry and Other Terms

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 consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure
MMBtu	million British thermal units, an energy unit
mtpa	million tonnes per annum
non-FTA countries	countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC	Securities and Exchange Commission
SPA	LNG sale and purchase agreement
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 Organizational Structure

The following diagram depicts our abbreviated organizational structure as of March 31, 2016, 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. (NYSE MKT: CQP) 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 thousands, except unit data)

	March 31,			December 31,
	2016			2015
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	9,815		$	146,221
Restricted cash	401,972			274,557
Accounts receivable—affiliate	14,544			1,271
Advances to affiliate	29,356			39,836
Inventory	28,543			16,667
Other current assets	17,986			14,923
Total current assets	502,216			493,475
Non-current restricted cash	13,650			13,650
Property, plant and equipment, net	12,713,379			11,931,602
Debt issuance costs, net	172,959			132,091
Non-current derivative assets	28,210			30,304
Other non-current assets	220,631			232,031
Total assets	$	13,651,045		$	12,833,153
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	17,131		$	16,407
Accrued liabilities	332,288			224,292
Current debt, net	1,785,318			1,673,379
Due to affiliates	78,159			115,123
Deferred revenue	26,669			26,669
Deferred revenue—affiliate	717			717
Derivative liabilities	11,818			6,430
Other current liabilities	93			—
Total current liabilities	2,252,193			2,063,017
Long-term debt, net	10,734,069			10,018,325
Non-current deferred revenue	8,500			9,500
Non-current derivative liabilities	16,210			2,884
Other non-current liabilities	172			175
Other non-current liabilities—affiliate	26,632			26,321
Partners’ equity
Common unitholders’ interest (57.1 million units issued and outstanding at March 31, 2016 and December 31, 2015)	259,168			305,747
Class B unitholders’ interest (145.3 million units issued and outstanding at March 31, 2016 and December 31, 2015)	(35,588		)	(37,429		)
Subordinated unitholders’ interest (135.4 million units issued and outstanding at March 31, 2016 and December 31, 2015)	375,104			428,035
General partner’s interest (2% interest with 6.9 million units issued and outstanding at March 31, 2016 and December 31, 2015)	14,585			16,578
Total partners’ equity	613,269			712,931
Total liabilities and partners’ equity	$	13,651,045		$	12,833,153

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

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(unaudited)

	Three Months Ended March 31,
	2016			2015
Revenues
Regasification revenues	$	65,384		$	66,718
Regasification revenues—affiliate	1,635			812
LNG revenues	—			—
Other revenues	28			—
Total revenues	67,047			67,530
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	3,904			693
Operating and maintenance expense	17,385			30,540
Operating and maintenance expense—affiliate	10,830			4,773
Development expense	66			1,151
Development expense—affiliate	129			204
General and administrative expense	2,610			3,515
General and administrative expense—affiliate	22,198			21,597
Depreciation and amortization expense	19,388			14,879
Total operating costs and expenses	76,510			77,352
Loss from operations	(9,463		)	(9,822		)
Other income (expense)
Interest expense, net of amounts capitalized	(43,452		)	(42,845		)
Loss on early extinguishment of debt	(1,457		)	(88,992		)
Derivative loss, net	(20,808		)	(37,138		)
Other income	274			121
Total other expense	(65,443		)	(168,854		)
Net loss	$	(74,906	)	$	(178,676	)
Basic and diluted net loss per common unit	$	(0.08	)	$	(0.61	)
Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	57,084			57,080

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 thousands)

(unaudited)

	Common Unitholders’ Interest				Class B Unitholders’ Interest				Subordinated Unitholder’s Interest				General Partner’s Interest				Total Partners’ Equity
	Units	Amount			Units	Amount			Units	Amount			Units	Amount
Balance at December 31, 2015	57,084	$	305,747		145,333	$	(37,429	)	135,384	$	428,035		6,894	$	16,578		$	712,931
Net loss	—	(21,772		)	—	—			—	(51,636		)	—	(1,498		)	(74,906		)
Distributions	—	(24,261		)	—	—			—	—			—	(495		)	(24,756		)
Amortization of beneficial conversion feature of Class B units	—	(546		)	—	1,841			—	(1,295		)	—	—			—
Balance at March 31, 2016	57,084	$	259,168		145,333	$	(35,588	)	135,384	$	375,104		6,894	$	14,585		$	613,269

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 thousands)

(unaudited)

	Three Months Ended March 31,
	2016			2015
Cash flows from operating activities
Net loss	$	(74,906	)	$	(178,676	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Non-cash LNG inventory write-downs	216			17,502
Depreciation and amortization expense	19,388			14,879
Amortization of debt issuance costs and discount	3,617			2,504
Loss on early extinguishment of debt	1,457			88,992
Total losses on derivatives, net	24,200			36,384
Net cash used for settlement of derivative instruments	(2,838		)	(37,015		)
Changes in restricted cash for certain operating activities	13,659			6,244
Changes in operating assets and liabilities:
Accounts and interest receivable	(26		)	(25,928		)
Accounts receivable—affiliate	904			(1,544		)
Advances to affiliate	(1,237		)	5,519
Inventory	(290		)	(29,676		)
Accounts payable and accrued liabilities	34,184			47,945
Due to affiliates	(7,669		)	(3,971		)
Deferred revenue	(1,000		)	(1,003		)
Other, net	(2,225		)	(5,542		)
Other, net—affiliate	(373		)	10,962
Net cash provided by (used in) operating activities	7,061			(52,424		)
Cash flows from investing activities
Property, plant and equipment, net	(714,616		)	(542,114		)
Use of restricted cash for the acquisition of property, plant and equipment	744,098			572,434
Other	(34,369		)	(30,508		)
Net cash used in investing activities	(4,887		)	(188		)
Cash flows from financing activities
Proceeds from issuances of debt	1,235,000			2,000,000
Repayments of debt	(415,000		)	—
Debt issuance and deferred financing costs	(48,652		)	(50,662		)
Investment in restricted cash	(885,172		)	(1,949,338		)
Distributions to owners	(24,756		)	(24,754		)
Net cash used in financing activities	(138,580		)	(24,754		)
Net decrease in cash and cash equivalents	(136,406		)	(77,366		)
Cash and cash equivalents—beginning of period	146,221			248,830
Cash and cash equivalents—end of period	$	9,815		$	171,464

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

In 2016, we started production at our natural gas liquefaction facilities at the Sabine Pass LNG terminal (the “Liquefaction Project”). As a result, we introduced a new line item entitled “Cost of sales” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made in the prior period into this new line item. Cost of sales includes costs incurred directly for the production of LNG from the Liquefaction Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the Liquefaction Project, and other related costs to convert natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense, which now includes costs associated with operating and maintaining the Liquefaction Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs.

Additionally, we distinguished and reclassified our historical “revenues” line item into “regasification revenues” and “LNG revenues.” Regasification revenues include LNG regasification capacity reservation fees that are received pursuant to our TUAs and tug services fees that are received by Sabine Pass Tug Services, LLC, a wholly owned subsidiary of SPLNG. LNG revenues include fees that will be received pursuant to our SPAs and related LNG marketing activities.

Results of operations for the three months ended March 31, 2016 are not necessarily indicative of the operating results that will be realized for the year ending December 31, 2016.

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.

For further information, refer to the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2015.

NOTE 2—UNITHOLDERS’ EQUITY

The common units, Class B 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, which allow the general partner to receive a higher percentage of quarterly distributions of available

7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met. The higher percentages range from 15% to 50%.

During 2012, Blackstone CQP Holdco and Cheniere completed their purchases of a new class of equity interests representing limited partner interests in us (“Class B units”) for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds from the financings were used to fund a portion of the costs of developing, constructing and placing into service the first twoTrains of the natural gas liquefaction facilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities (the “Liquefaction Project”). In May 2013, Cheniere purchased an additional 12.0 millionClass B units for consideration of $180.0 million in connection with our acquisition of CTPL and Cheniere Pipeline GP Interests, LLC.  In 2013, Cheniere formed Cheniere Holdings to hold its limited partner interests in us. The Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Class B units are not entitled to cash distributions except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. On a quarterly basis beginning on the date of the initial purchase date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco was 1.68 and 1.65, respectively, as of March 31, 2016. We expect the Class B units to mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the Liquefaction Project, which we currently expect to occur before April 30, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

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. Restricted cash consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Current restricted cash
SPLNG debt service and interest payment	$	115,469	$	77,415
Liquefaction project	177,609		189,260
CTPL construction and interest payment	—		7,882
CQP and cash held by guarantor subsidiaries	108,894		—
Total current restricted cash	$	401,972	$	274,557
Non-current restricted cash
SPLNG debt service	$	13,650	$	13,650

Under the indentures governing the senior notes issued by SPLNG (the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until certain conditions are satisfied, including: (1) there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and (2) there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the SPLNG Indentures. During the three months ended March 31, 2016 and 2015, SPLNG made distributions of $63.4 million and $70.8 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

In February 2016, we entered into a $2.8 billion credit facility (the “2016 CQP Credit Facilities”). Under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to us, we, and Cheniere Investments and CTPL as our guarantor subsidiaries, are subject to limitations on the use of cash. Specifically, we, Cheniere Investments and CTPL may only withdraw funds from collateral accounts held at a designated depositary bank on a monthly basis and for specific purposes, including for the payment of operating expenses. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions.

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 4—INVENTORY

As of March 31, 2016 and December 31, 2015, inventory consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Natural gas	$	3,333	$	5,724
LNG	2,847		3,690
Materials and other	22,363		7,253
Total inventory	$	28,543	$	16,667

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2016			2015
LNG terminal costs
LNG terminal	$	2,736,918		$	2,478,036
LNG terminal construction-in-process (1)	10,399,834			9,859,836
LNG site and related costs, net	133			135
Accumulated depreciation	(429,060		)	(411,907		)
Total LNG terminal costs, net	12,707,825			11,926,100
Fixed assets
Computer and office equipment	1,126			1,126
Furniture and fixtures	1,475			1,375
Computer software	4,198			4,238
Vehicles	2,484			2,081
Machinery and equipment	1,938			1,906
Other	95			93
Accumulated depreciation	(5,762		)	(5,317		)
Total fixed assets, net	5,554			5,502
Property, plant and equipment, net	$	12,713,379		$	11,931,602

(1) As of March 31, 2016, LNG terminal construction-in-process is presented net of amounts received from the sale of commissioning cargoes because the related costs were capitalized as testing costs for the construction of the Liquefaction Project.

NOTE 6—DERIVATIVE INSTRUMENTS

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

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

• commodity derivatives consisting of natural gas purchase agreements for the commissioning and operation of the Liquefaction Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives”, and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”); and

• commodity derivatives to hedge the exposure to price risk attributable to future: (1) sales of our LNG inventory and (2) purchases of natural gas to operate the Sabine Pass LNG terminal (“Natural Gas Derivatives”).

None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations.

SPLNG has elected to account for a portion of the Natural Gas Derivatives as normal purchase normal sale transactions, exempt from fair value accounting. Gains and losses for these physical hedges are not reflected on our Consolidated Statements

9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

of Operations until the period of delivery. SPLNG had not posted collateral for such forward contracts as of March 31, 2016 and December 31, 2015.

The following table (in thousands) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015, which are classified as other current assets, non-current derivative assets, derivative liabilities or other non-current derivative liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	March 31, 2016										December 31, 2015
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
SPL Interest Rate Derivatives liability	$	—	$	(18,009	)	$	—	$	(18,009	)	$	—	$	(8,740	)	$	—	$	(8,740	)
CQP Interest Rate Derivatives liability	—		(9,490		)	—		(9,490		)	—		—			—		—
Liquefaction Supply Derivatives asset (liability)	—		(151		)	30,054		29,903			—		(25		)	32,492		32,467
Natural Gas Derivatives asset	—		—			—		—			—		39			—		39

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

The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a particular Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair value models include conditions precedent to the respective long-term natural gas purchase agreements. As of March 31, 2016 and December 31, 2015, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow. In the absence of infrastructure to accommodate marketable physical gas flow, our internal fair value models are based on a market price that equates to our own contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. 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 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 purchase agreements as of the reporting date.

There were no transfers into or out of Level 3 Physical Liquefaction Supply Derivatives for the three months ended March 31, 2016 and 2015. As all of our Physical Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2016:

10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

	Net Fair Value Asset (in thousands)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$30,054	Income Approach	Basis Spread	$ (0.350) - $0.020

The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31,
	2016			2015
Balance, beginning of period	$	32,492		$	342
Realized and mark-to-market losses:
Included in cost of sales (1)	(2,653		)	—
Purchases and settlements:
Purchases	215			—
Settlements (1)	—			—
Balance, end of period	$	30,054		$	342
Change in unrealized gains relating to instruments still held at end of period	$	(2,194	)	$	—

(1) Does not include the decrease in fair value of $0.5 million related to the realized gains capitalized during the three months ended March 31, 2016.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position.  

Interest Rate Derivatives

SPL Interest Rate Derivatives

SPL has 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 $4.6 billion credit facilities (the “2015 SPL Credit Facilities”). The SPL Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities.

In March 2015, SPL settled a portion of the SPL Interest Rate Derivatives and recognized a derivative loss of $34.7 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments under the previous credit facilities.

CQP Interest Rate Derivatives

In March 2016, we entered into interest rate swaps (“CQP Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2016 CQP Credit Facilities. The CQP Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities.

As of March 31, 2016, 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
SPL Interest Rate Derivatives	$20.0 million	$628.8 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
CQP Interest Rate Derivatives	$225.0 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR

11

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	March 31, 2016									December 31, 2015
	SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			Total			SPL Interest Rate Derivatives			CQP Interest Rate Derivatives		Total
Balance Sheet Location
Derivative liabilities	$	(6,759	)	$	(4,530	)	$	(11,289	)	$	(5,940	)	$	—	$	(5,940	)
Non-current derivative liabilities	(11,250		)	(4,960		)	(16,210		)	(2,800		)	—		(2,800		)
Total derivative liabilities	(18,009		)	(9,490		)	(27,499		)	(8,740		)	—		(8,740		)
Derivative liability, net	$	(18,009	)	$	(9,490	)	$	(27,499	)	$	(8,740	)	$	—	$	(8,740	)

The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Consolidated Statements of Operations during the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31,
	2016			2015
SPL Interest Rates Derivatives loss	$	(11,278	)	$	(37,138	)
CQP Interest Rate Derivatives loss	(9,530		)	—

Commodity Derivatives

We recognize all commodity derivative instruments that qualify for derivative accounting treatment, including our Liquefaction Supply Derivatives and our Natural Gas Derivatives(collectively, “Commodity Derivatives”), as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Commodity Derivatives are reported in earnings.

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

	March 31, 2016								December 31, 2015
	Liquefaction Supply Derivatives (1)			Natural Gas Derivatives		Total			Liquefaction Supply Derivatives			Natural Gas Derivatives (2)		Total
Balance Sheet Location
Other current assets	$	2,222		$	—	$	2,222		$	2,737		$	39	$	2,776
Non-current derivative assets	28,210			—		28,210			30,304			—		30,304
Total derivative assets	30,432			—		30,432			33,041			39		33,080
Derivative liabilities	(529		)	—		(529		)	(490		)	—		(490		)
Non-current derivative liabilities	—			—		—			(84		)	—		(84		)
Total derivative liabilities	(529		)	—		(529		)	(574		)	—		(574		)
Derivative asset, net	$	29,903		$	—	$	29,903		$	32,467		$	39	$	32,506

(1) Does not include collateral of $1.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of March 31, 2016.

(2) Does not include collateral of $0.4 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table (in thousands) shows the changes in the fair value and settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three months ended March 31, 2016 and 2015:

		Three Months Ended March 31,
	Statement of Operations Location	2016			2015
Liquefaction Supply Derivatives gain	Revenues	$	28		$	—
Liquefaction Supply Derivatives loss (1)	Cost of sales	(3,594		)	—
Natural Gas Derivatives gain	Operating and maintenance expense	174			754

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

The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our Commodity Derivatives are in an asset position.

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 primarily range from approximately one to seven years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified Trains of the Liquefaction Project. We recognize our Physical Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Physical Liquefaction Supply Derivatives are reported in earnings. As of March 31, 2016, SPL has secured up to approximately 2,047.9 millionMMBtu of natural gas feedstock through natural gas purchase agreements. The notional natural gas position of our Physical Liquefaction Supply Derivatives was approximately 1,134.9 millionMMBtu as of March 31, 2016.

Our Financial Liquefaction Supply Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our Financial Liquefaction Supply Derivatives activities.

Natural Gas Derivatives

Our Natural Gas Derivatives were executed through over-the-counter contracts which were subject to nominal credit risk as these transactions settled on a daily margin basis with investment grade financial institutions. We were required by these financial institutions to use margin deposits as credit support for our Natural Gas Derivatives activities. As of March 31, 2016, we did not have any open Natural Gas Derivatives positions or margin deposits at financial institutions.

Balance Sheet Presentation

Our Interest Rate Derivatives and Commodity Derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross and net basis:

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2016
SPL Interest Rate Derivatives	$	(18,009	)	$	—		$	(18,009	)
CQP Interest Rate Derivatives	(9,490		)	—			(9,490		)
Liquefaction Supply Derivatives	30,618			(186		)	30,432
Liquefaction Supply Derivatives	(1,668		)	1,139			(529		)
As of December 31, 2015
SPL Interest Rate Derivatives	$	(8,740	)	$	—		$	(8,740	)
Liquefaction Supply Derivatives	33,636			(595		)	33,041
Liquefaction Supply Derivatives	(574		)	—			(574		)
Natural Gas Derivatives	188			(149		)	39

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 7—OTHER NON-CURRENT ASSETS

As of March 31, 2016 and December 31, 2015, other non-current assets consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Advances made under EPC and non-EPC contracts	$	19,766	$	32,049
Advances made to municipalities for water system enhancements	88,151		89,953
Tax-related payments and receivables	25,197		27,615
Information technology service assets	30,156		30,371
Other	57,361		52,043
Total other non-current assets	$	220,631	$	232,031

NOTE 8—ACCRUED LIABILITIES

As of March 31, 2016 and December 31, 2015, accrued liabilities consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Interest expense and related debt fees	$	167,400	$	150,336
Liquefaction Project costs	158,264		66,223
LNG terminal costs	4,230		3,918
Other accrued liabilities	2,394		3,815
Total accrued liabilities	$	332,288	$	224,292

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—DEBT

As of March 31, 2016 and December 31, 2015, our debt consisted of the following (in thousands):

	March 31,			December 31,
	2016			2015
Long-term debt
SPLNG
6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) (1)	$	420,000		$	420,000
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $8,341 and $8,718	2,008,341			2,008,718
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000,000			1,000,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $6,212 and $6,392	1,506,212			1,506,392
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000,000			2,000,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000,000			2,000,000
2015 SPL Credit Facilities	1,505,000			845,000
CTPL
$400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429	—			398,571
Cheniere Partners
2016 CQP Credit Facilities	450,000			—
Unamortized debt issuance costs (2)	(155,484		)	(160,356		)
Total long-term debt, net	10,734,069			10,018,325
Current debt
7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of $3,130 and $4,303 (3)	1,662,370			1,661,197
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	125,000			15,000
Unamortized debt issuance costs (2)	(2,052		)	(2,818		)
Total current debt, net	1,785,318			1,673,379
Total debt, net	$	12,519,387		$	11,691,704

(1) Must be redeemed or repaid concurrently with the 2016 Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities.

(2) Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $160.4 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.

(3) Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities.

2016 Debt Issuances and Redemptions

2016 CQP Credit Facilities

In February 2016, we entered into the $2.8 billion2016 CQP Credit Facilities, which consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 millionCTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities ), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

We incurred $48.7 million of debt issuance costs during the three months ended March 31, 2016, and will incur an additional $21.5 million of debt issuance costs when the SPLNG tranche is funded. The prepayment of the CTPL Term Loan resulted in a write-off of unamortized discount and debt issuance costs of $1.5 million during the three months ended March 31, 2016. We pay a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit our ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the terms of the 2016 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 2016 CQP Credit Facilities are unconditionally guaranteed by each of our subsidiaries other than: (1) SPL, (2) SPLNG until funding of its tranche term loan and (3) certain of our subsidiaries owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2016 (in thousands):

	2015 SPL Credit Facilities		SPL Working Capital Facility		2016 CQP Credit Facilities
Total facility size	$	4,600,000	$	1,200,000	$	2,800,000
Outstanding balance	1,505,000		125,000		450,000
Letters of credit issued	—		236,459		7,500
Available commitment	$	3,095,000	$	838,541	$	2,342,500
Interest rate	LIBOR plus 1.30% - 1.75% or base rate plus 1.75%		LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date		December 31, 2020, with various terms for underlying loans		February 25, 2020, with principals due quarterly commencing on February 19, 2019

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

Interest Expense

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

	Three Months Ended March 31,
	2016			2015
Total interest cost	$	192,620		$	160,086
Capitalized interest	(149,168		)	(117,241		)
Total interest expense, net	$	43,452		$	42,845

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

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

	March 31, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior Notes, net of premium or discount (1)	$	10,596,923	$	10,299,660	$	10,596,307	$	9,525,809
CTPL Term Loan, net of discount (2)	—		—		398,571		400,000
Credit facilities (2) (3)	2,080,000		2,080,000		860,000		860,000

(1) Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes and 2025 SPL Senior Notes(collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of our Senior Notes and other similar instruments.

(2) 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. 

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities.

NOTE 10—RELATED PARTY TRANSACTIONS

LNG Terminal Capacity Agreements

Terminal Use Agreement

SPL obtained approximately 2.0Bcf/d of regasification capacity 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, continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project.

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. During the three months ended March 31, 2016 and 2015, we recorded $0.3 million and $17.8 million, respectively, as operating and maintenance expense related to this obligation. 

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments has the right to use SPL’s reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to SPLNG. However, the revenue earned by SPLNG from the capacity payments made under the TUA and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our 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. We recorded no revenues—affiliate from Cheniere Marketing during the three months ended March 31, 2016 and 2015, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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 at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

17

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Commissioning Agreement

In May 2015, SPL entered into an agreement with Cheniere Marketing that obligates Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. has control of, and is commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

In May 2015, SPL entered into an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC.

Services Agreements

As of March 31, 2016 and December 31, 2015, we had $29.4 million and $39.8 million of advances to affiliates, respectively, under the services agreements described below. During the three months ended March 31, 2016 and 2015, we recorded general and administrative expense—affiliate of $22.2 million and $21.6 million, respectively, and operating and maintenance expense—affiliate of $10.8 million and $4.8 million, respectively, under the services agreements described below.

Cheniere Partners Services Agreement

We have entered into 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 $2.8 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 entered into 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 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 entered into 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 incurs 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 incurs costs 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 entered into 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 incurs a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPL O&M Agreement

SPL has entered into 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 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 the Liquefaction Project is operational, the services include all necessary services required to operate and maintain the Liquefaction Project. Before the Liquefaction Project is operational, 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 Liquefaction Project 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 such 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 entered into 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 our behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Under the SPL MSA, 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 entered into 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 the counterparty 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.

CTPL MSA

CTPL has entered into a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the modification and operation of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations and providing contract administration services for all contracts associated with the pipeline facilities. Under the CTPL MSA, CTPL pays a monthly fee equal to 3.0% of the capital expenditures to enable bi-directional natural gas flow on the Creole Trail Pipeline incurred in the previous month.

LNG Lease Agreement

In September 2011, Cheniere Investments entered into an agreement in the form of a lease (the “LNG Lease Agreement”) with Cheniere Marketing that enables Cheniere Investments to supply the Sabine Pass LNG terminal with LNG to maintain proper LNG inventory levels and temperature. The LNG Lease Agreement also enables Cheniere Investments to hedge the exposure to variability in expected future cash flows of the LNG inventory. Under the terms of the LNG Lease Agreement, Cheniere Marketing funds all activities related to the purchase and hedging of the LNG, and Cheniere Investments reimburses Cheniere Marketing for all costs and assumes full price risk associated with these activities. As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, any LNG inventory purchased by Cheniere Marketing under this arrangement is

19

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

classified as inventory—affiliate on our Consolidated Balance Sheets. As of March 31, 2016 and December 31, 2015, we had no LNG inventory—affiliate recorded on our Consolidated Balance Sheets under the LNG Lease Agreement.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”)

SPLNG has executed 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 up to $25.0 million in order to aid in their reconstruction efforts following Hurricane Rita. As of March 31, 2016, SPLNG has fulfilled its aggregate commitment obligations to the various Cameron Parish, Louisiana taxing authorities. 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, and in the year the Cameron Parish dollar-for-dollar credit is applied against, ad valorem tax levied on our LNG terminal.

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 March 31, 2016 and December 31, 2015, we had $24.5 million and $22.1 million, respectively, of both other non-current assets resulting from SPLNG’s ad valorem tax payments and 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. As a result, SPLNG records the purchases of natural gas and LNG from Cheniere Marketing to be utilized as fuel to operate the Sabine Pass LNG terminal as operating and maintenance expense.

SPLNG recorded operating and maintenance expense—affiliate of $0.7 million and $1.6 million in the three months ended March 31, 2016 and 2015, respectively, for natural gas purchased from Cheniere Marketing under these agreements. SPLNG recorded regasification revenues—affiliate of $0.9 million and $1.3 million in the three months ended March 31, 2016 and 2015, respectively, for natural gas sold to Cheniere Marketing under these agreements.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of SPLNG, entered into a tug sharing 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. Tug Services recorded revenues—affiliate of $0.6 million and $0.7 million pursuant to this agreement in each of the three months ended March 31, 2016 and 2015, respectively.

LNG Terminal Export Agreement

In January 2010, SPLNG and Cheniere Marketing entered into 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 months ended March 31, 2016 and 2015.

State Tax Sharing Agreements

In November 2006, SPLNG entered into 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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

computed 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.

In August 2012, SPL entered into 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.

In May 2013, CTPL entered into 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.

NOTE 11—NET 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 April 22, 2016, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on May 13, 2016 to unitholders of record as of May 2, 2016 for the period from January 1, 2016 to March 31, 2016.

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. Historical income (loss) attributable to a company that was purchased from an entity under common control is allocated to the predecessor owner in accordance with the terms 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 were issued at a discount to the market price of the common units into which they are convertible.  This discount totaling $2,130.0 million represents a beneficial conversion feature and is 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 is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortize the beneficial conversion feature assuming a conversion date of June 2017 and August 2017 for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively, although actual conversion may occur prior to or after these assumed dates. We are amortizing using the effective yield method with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature is also included in earnings per unit for the three months ended March 31, 2016 and 2015.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following is a schedule by years, based on the capital structure as of March 31, 2016, of the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature (in thousands):

	Common Units			Class B Units		Subordinated Units
2016	$	(29,565	)	$	99,685	$	(70,119	)
2017	(594,426		)	2,004,209		(1,409,783		)

Under our partnership agreement, the incentive distribution rights (“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). We did not allocate earnings or losses to IDR holders for the purpose of the two-class method earnings per unit calculation for any of the periods presented. The following table (in thousands, except per unit data) provides a reconciliation of net loss and the allocation of net loss to the common units, the subordinated units and the general partner units for purposes of computing net loss per unit.

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner Units
Three Months Ended March 31, 2016
Net loss	$	(74,906	)
Declared distributions	24,756			24,261			—		—			495
Assumed allocation of undistributed net loss	$	(99,662	)	(28,967		)	—		(68,702		)	(1,993		)
Assumed allocation of net loss				$	(4,706	)	$	—	$	(68,702	)	$	(1,498	)
Weighted average units outstanding				57,084			145,333		135,384
Net loss per unit				$	(0.08	)	$	—	$	(0.51	)
Three Months Ended March 31, 2015
Net loss	$	(178,676	)
Declared distributions	24,754			24,259			—		—			495
Assumed allocation of undistributed net loss	$	(203,430	)	(59,125		)	—		(140,236		)	(4,070		)
Assumed allocation of net loss				$	(34,866	)	$	—	$	(140,236	)	$	(3,575	)
Weighted average units outstanding				57,080			145,333		135,384
Net loss per unit				$	(0.61	)	$	—	$	(1.04	)

NOTE 12—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2016		2015
Cash paid during the period for interest, net of amounts capitalized and deferred	$	23,903	$	—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $307.3 million and $147.5 million, as of March 31, 2016 and 2015, respectively.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by the Partnership as of March 31, 2016:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard amends 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. This guidance may be early adopted beginning January 1, 2017, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	This standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted.	December 31, 2016	The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

23

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 the Partnership during the reporting period:

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	These amendments primarily affect asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2016	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.
ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	These standards require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 9—Debt for required disclosures for a change in accounting principle.
ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions	This standard requires a master limited partnership to allocate net income (losses) of a transferred business entirely to the general partner when computing earnings per unit for periods before the dropdown transaction occurred. This guidance also requires a master limited partnership to disclose the effects of the dropdown transaction on net income (losses) per unit for the periods before and after the dropdown transaction occurred. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All statements, other than statements of historical facts, 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 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 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 EPC or other contractor, and anticipated costs related thereto;

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

• statements regarding counterparties to our commercial contracts, construction contracts and other contracts;

• statements regarding our planned development and construction of additional Trains, 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 and capital expenditures, 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 fact, 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 due to factors described in this quarterly report and in the other reports and other information that we file with the SEC. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

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Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed under “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2015. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

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. Through our wholly owned subsidiary, SPLNG, we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine-Neches Waterway less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two marine berths that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We are developing and constructing natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through our wholly owned subsidiary, SPL. We plan to construct up to six Trains, which are in various stages of development. Trains 1 and 2 are undergoing commissioning, Trains 3 through 5 are under construction and Train 6 is fully permitted. Each Train is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. We also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through our wholly owned subsidiary, CTPL.

Overview of Significant Events

Our significant accomplishments since January 1, 2016 and through the filing date of this Form 10-Q include the following:  

• In February 2016, we entered into a Credit and Guaranty Agreement for the incurrence of debt of up to an aggregate amount of approximately $2.8 billion (the “2016 CQP Credit Facilities”). The 2016 CQP Credit Facilities consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 millionCTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 7.50% Senior Secured Notes due 2016 issued by SPLNG (the “2016 SPLNG Senior Notes”) and the 6.50% Senior Secured Notes due 2020 issued by SPLNG (the “2020 SPLNG Senior Notes” and collectively with the 2016 SPLNG Senior Notes, the “SPLNG Senior Notes”) (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities ), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes.

• In February 2016, SPL commenced production and shipment of LNG commissioning cargoes from Train 1 of the Liquefaction Project.

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Liquidity and Capital Resources

Cash and Cash Equivalents

As of March 31, 2016, we had $9.8 million of cash and cash equivalents and $415.6 million of current and non-current restricted cash (which included current and non-current restricted cash available to us and our subsidiaries) designated for the following purposes: $108.9 million for the 2016 CQP Credit Facilities, $177.6 million for the Liquefaction Project and $129.1 million for interest payments related to the SPLNG Senior Notes.

Sabine Pass LNG Terminal

Regasification Facilities

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

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project. SPL entered into a partial TUA assignment agreement with Total, whereby SPL will progressively gain access to Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement will provide SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Trains 5 and 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3 and permit SPL to more flexibly manage its LNG storage capacity with the commencement of Train 1. 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.

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

Liquefaction Facilities

The Liquefaction Project is being developed and constructed 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 commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In June 2015, we commenced construction of Train 5 and the related facilities.

The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal (1) to FTA countries for a 30-year term and (2) to non-FTA countries for a 20-year term with a 3-year makeup period for LNG volumes SPL was unable to export during the initial 20-year export period, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas). The DOE further issued an order authorizing SPL to export domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year term and non-FTA countries for a 20-year term up to the equivalent of approximately 203 Bcf/yr of natural gas. Additionally, the DOE issued orders authorizing SPL to export domestically produced LNG from the Sabine Pass LNG terminal to FTA countries and non-FTA countries for a 20-year term up to a combined total of 503.3 Bcf/yr of natural gas. A party to the proceedings requested rehearings of the orders above related to the export of 203 Bcf/yr and 503.3 Bcf/yr to non-FTA countries and the DOE has not yet issued a final ruling on the rehearing requests. 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 5 to 10 years from the date the order was issued. Furthermore, the DOE issued an order authorizing SPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing on January 15, 2016 up to 600 Bcf in total of natural gas.

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As of March 31, 2016, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project were approximately 98.3% and 83.8%, respectively.  As of March 31, 2016, the overall project completion percentage for Train 5 of the Liquefaction Project was approximately 28.8% with engineering, procurement, subcontract work and Bechtel direct hire construction approximately 59.1%, 45.1%, 24.2% and 0.4% complete, respectively.  As of March 31, 2016, the overall project completion of each of our Trains was ahead of the contractual schedule.  We produced our first LNG from Train 1 of the Liquefaction Project in February 2016. Based on our current construction schedule, we anticipate that Train 2 will produce LNG as early as mid-2016 and Trains 3 through 5 are expected to commence operations on a staggered basis thereafter.

Customers

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

In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion annually for Trains 1 through 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.

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 agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. For SPL’s natural gas storage requirements, SPL has entered into firm storage services agreements with third parties. The storage services agreements assist SPL in managing volatility in natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and natural gas purchase agreements with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of March 31, 2016, SPL has secured up to approximately 2,047.9 million MMBtu of natural gas feedstock through natural gas purchase agreements.

Construction

SPL entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 5, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract prices of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC Contract for Train 5 of the Liquefaction Project are approximately $4.1 billion, $3.8 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through March 31, 2016. 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 $17.0 billion and $18.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

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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 the Train.

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 one or more of the following: borrowings, equity contributions from us and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the 2015 SPL Credit Facilities, available commitments under the SPL Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. SPL will begin generating cash flow from operations through the sale of LNG cargoes in 2016.

Senior Secured Notes

As of March 31, 2016, our subsidiaries had seven series of senior secured notes outstanding (collectively, the “Senior Notes”):

• $1.7 billion of 2016 SPLNG Senior Notes;

• $0.4 billion of 2020 SPLNG Senior Notes;

• $2.0 billion of 5.625% Senior Secured Notes due 2021 issued by SPL (the “2021 SPL Senior Notes”);

• $1.0 billion of 6.25% Senior Secured Notes due 2022 issued by SPL (the “2022 SPL Senior Notes”);

• $1.5 billion of 5.625% Senior Secured Notes due 2023 issued by SPL (the “2023 SPL Senior Notes”);

• $2.0 billion of 5.75% Senior Secured Notes due 2024 issued by SPL (the “2024 SPL Senior Notes”); and

• $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes” and collectively with the 2021 SPL Senior Notes, the 2022 SPL Senior Notes, the 2023 SPL Senior Notes and the 2024 SPL Senior Notes, the “SPL Senior Notes”).

Interest on the SPL Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the SPLNG Senior Notes are secured on a pari passu first-priority basis by a security interest in all of SPLNG’s equity interests and substantially all of SPLNG’s operating assets. The SPL Senior Notes are secured on a first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets.

SPLNG may redeem all or part of its 2016 SPLNG Senior Notes at any time at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:

• 1.0% of the principal amount of the 2016 SPLNG Senior Notes; or

• the excess of: (1) the present value at such redemption date of (a) the redemption price of the 2016 SPLNG Senior Notes plus (b) all required interest payments due on the 2016 SPLNG Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis points; over (2) the principal amount of the 2016 SPLNG Senior Notes, if greater.

SPLNG may redeem all or part of the 2020 SPLNG Senior Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPLNG may also, at its option, redeem all or part of the 2020 SPLNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes, SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price set forth in the common indenture governing the SPL Senior Notes(the “SPL Indenture”), plus accrued and unpaid interest, if any, to the date of

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redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes, 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.

Under the indentures governing the SPLNG Senior Notes(the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a fixed charge coverage ratio test of 2:1 is satisfied. Under the SPL Indenture, SPL may not make any distributions until, among other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. During the three months ended March 31, 2016 and 2015, SPLNG made distributions of $63.4 million and $70.8 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

The SPL Indenture includes 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, the 2015 SPL Credit Facilities and the SPL Working Capital Facility.

2015 SPL Credit Facilities

In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion. The 2015 SPL Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project. Borrowings under the 2015 SPL Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. As of March 31, 2016, SPL had $3.1 billion of available commitments and $1.5 billion of outstanding borrowings under the 2015 SPL Credit Facilities.

Loans under the 2015 SPL Credit Facilities accrue interest at a variable rate per annum equal to, at SPL’s election, LIBOR or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.30% to 1.75%, depending on the applicable 2015 SPL Credit Facility, and the applicable margin for base rate loans is 1.75%. Interest on LIBOR loans is due and payable at the end of each LIBOR period and interest on base rate loans is due and payable at the end of each quarter. In addition, SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 SPL Credit Facilities. The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee calculated at a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility. The principal of the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2015 SPL Credit Facilities.

The 2015 SPL Credit Facilities contain conditions precedent for borrowings, as well as customary affirmative and negative covenants. The obligations of SPL under the 2015 SPL Credit Facilities 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 and SPL Working Capital Facility.

Under the terms of the 2015 SPL Credit Facilities, SPL is required to hedge not less than 65% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. Additionally, SPL may not make any distributions until substantial completion of Trains 1 and 2 of the Liquefaction Project has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is satisfied.

2013 SPL Credit Facilities

 In May 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 SPL Credit Facilities”) to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project. In June 2015, the 2013 SPL Credit Facilities were replaced with the 2015 SPL Credit Facilities.

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In March 2015, in conjunction with SPL’s issuance of the 2025 SPL Senior Notes, SPL terminated approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities. This termination resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 SPL Credit Facilities of $89.0 million for the three months ended March 31, 2015.

CTPL Term Loan

In May 2013, CTPL entered into a $400.0 million term loan facility (the “CTPL Term Loan”), which was used to fund modifications to the Creole Trail Pipeline and for general business purposes. In February 2016, CTPL prepaid the full amount of $400.0 million outstanding under the CTPL Term Loan with capital contributions from us, which we funded with borrowings under the 2016 CQP Credit Facilities. This prepayment resulted in a write-off of unamortized discount and debt issuance costs of $1.5 million during the three months ended March 31, 2016.

2016 CQP Credit Facilities

In February 2016, we entered into the 2016 CQP Credit Facilities. The 2016 CQP Credit Facilities consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 millionCTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities ), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes. As of March 31, 2016, we had $2.3 billion of available commitments, $7.5 million aggregate amount of issued letters of credit and outstanding borrowings of $450.0 million under the 2016 CQP Credit Facilities.

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

We incurred $48.7 million of debt issuance costs during the three months ended March 31, 2016 and will incur an additional $21.5 million of debt issuance costs when the SPLNG tranche is funded. We pay a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit our ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the terms of the 2016 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 2016 CQP Credit Facilities are unconditionally guaranteed by each of our subsidiaries other than: (1) SPL, (2) SPLNG until funding of its tranche term loan and (3) certain of our subsidiaries owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

SPL Working Capital Facility

In September 2015, SPL entered into a $1.2 billion Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “SPL Working Capital Facility”), which replaced the $325.0 million Senior Letter of Credit and Reimbursement Agreement that was entered into in April 2014 (the “SPL LC Agreement”). The SPL Working Capital

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Facility is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit, 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 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 March 31, 2016, SPL had $838.5 million of available commitments, $236.5 million aggregate amount of issued letters of credit and $125.0 million outstanding under the SPL Working Capital Facility. As of December 31, 2015, SPL had $1.1 billion of available commitments, $135.2 million aggregate amount of issued letters of credit and $15.0 million outstanding under the SPL Working Capital Facility.

The SPL Working Capital Facility accrues interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR loans under the SPL Working Capital Facility is 1.75% per annum, and the applicable margin for base rate loans under the SPL Working Capital Facility is 0.75% per annum. Interest on Swing Line Loans and loans deemed made in connection with a draw upon a letter of credit (“LC Loans”) is due and payable on the date the loan becomes due. Interest on LIBOR Working Capital Loans is due and payable at the end of each applicable LIBOR period, and interest on base rate Working Capital Loans is due and payable at the end of each fiscal quarter. However, if such base rate Working Capital Loan is converted into a LIBOR Working Capital Loan, interest is due and payable on that date. Additionally, if the loans become due prior to such periods, the interest also becomes due on that date.

SPL pays (1) a commitment fee equal to an annual rate of 0.70% on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding Swing Line Loans and (2) a letter of credit fee equal to an annual rate of 1.75% of the undrawn portion of all letters of credit issued under the SPL Working Capital Facility. If draws are made upon a letter of credit issued under the SPL Working Capital Facility and SPL does not elect for such draw (an “LC Draw”) to be deemed an LC Loan, SPL is required to pay the full amount of the LC Draw on or prior to the business day following the notice of the LC Draw. An LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of March 31, 2016, no LC Draws had been made upon any letters of credit issued under the SPL Working Capital Facility.

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. LC Loans 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 and the 2015 SPL Credit Facilities.

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Sources and Uses of Cash

The following table (in thousands) summarizes the sources and uses of our cash and cash equivalents for the three months ended March 31, 2016 and 2015. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.

	Three Months Ended March 31,
	2016			2015
Sources of cash and cash equivalents
Proceeds from issuances of debt	$	1,235,000		$	2,000,000
Use of restricted cash for the acquisition of property, plant and equipment	744,098			572,434
Operating cash flow	7,061			—
Total sources of cash and cash equivalents	1,986,159			2,572,434
Uses of cash and cash equivalents
Investment in restricted cash	(885,172		)	(1,949,338		)
Repayments of debt	(415,000		)	—
Property, plant and equipment, net	(714,616		)	(542,114		)
Debt issuance and deferred financing costs	(48,652		)	(50,662		)
Distributions to owners	(24,756		)	(24,754		)
Operating cash flow	—			(52,424		)
Other	(34,369		)	(30,508		)
Total uses of cash and cash equivalents	(2,122,565		)	(2,649,800		)
Net decrease in cash and cash equivalents	(136,406		)	(77,366		)
Cash and cash equivalents—beginning of period	146,221			248,830
Cash and cash equivalents—end of period	$	9,815		$	171,464

Proceeds from Issuances of Debt, Debt Issuance and Deferred Financing Costs and Repayments of Debt

In February 2016, we entered into the 2016 CQP Credit Facilities and borrowed $450.0 million to prepay the $400.0 million CTPL Term Loan. Additionally, during the three months ended March 31, 2016, we borrowed $660.0 million under the 2015 SPL Credit Facilities and $125.0 million under the SPL Working Capital Facility, offset by a $15.0 million repayment of borrowings under the SPL Working Capital Facility. In March 2015, SPL issued an aggregate principal amount of $2.0 billion of the 2025 SPL Senior Notes. Debt issuance and deferred financing costs in the three months ended March 31, 2016 primarily related to the up-front fees paid upon the closing of the 2016 CQP Credit Facilities and in the three months ended March 31, 2015 related to the issuance of the 2025 SPL Senior Notes.

Use of Restricted Cash for the Acquisition of Property, Plant and Equipment and Property, Plant and Equipment, net

During the three months ended March 31, 2016 and 2015, we used $744.1 million and $572.4 million, respectively, of restricted cash for investing activities to fund $714.6 million and $542.1 million, respectively, of construction costs for Trains 1 through 5 of the Liquefaction Project, which are capitalized as construction-in-process.

Operating Cash Flow

During the three months ended March 31, 2015, we used $52.4 million of cash in operating activities, compared to $7.1 million of cash provided by operating activities during the three months ended March 31, 2016. The higher operating cash outflows in the three months ended March 31, 2015 primarily related to additional cash paid to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which was not repeated in the three months ended March 31, 2016, and the timing of receivables due from third parties.

Investment in Restricted Cash

In the three months ended March 31, 2016, we invested $885.2 million in restricted cash primarily related to the borrowings under the 2016 CQP Credit Facilities, 2015 SPL Credit Facilities and SPL Working Capital Facility, net of deferred financing costs

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and repayment of the CTPL Term Loan. In the three months ended March 31, 2015, we invested $1,949.3 million in restricted cash primarily related to the net proceeds from the 2025 SPL Senior Notes, partially offset by the use of restricted cash related to the payment of commitment fees for the 2013 SPL Credit Facilities.

Other

During the three months ended March 31, 2016, we used $34.4 million of cash for other activities, which primarily related to payments made pursuant to the information technology services agreement for capital assets purchased on our behalf. During the three months ended March 31, 2015, we used $30.5 millionof cash in other activities primarily as a result of payments made to a municipal water district for water system enhancements that will increase potable water supply to our Sabine Pass LNG terminal.

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 three months ended March 31, 2016 and 2015:

					Total Distribution (in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit	Common Units		Class B Units	Subordinated Units	General Partner Units
February 12, 2016	October 1 - December 31, 2015	$	0.425	—	$	24,259	—	—	$	495
February 13, 2015	October 1 - December 31, 2014	0.425		—	24,259		—	—	495

On April 22, 2016, we declared a $0.425 distribution per common unit and the related distribution to our general partner will be paid on May 13, 2016 to owners of record as of May 2, 2016 for the period from January 1, 2016 to March 31, 2016.

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.

In 2012 and 2013, we issued a new class of equity interests representing limited partner interests in us (“Class B units”), in connection with the development of the Liquefaction Project. The Class B units are not entitled to cash distributions, except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere and Blackstone CQP Holdco was 1.68 and 1.65, respectively, as of March 31, 2016. We expect the Class B units to mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the Liquefaction Project, which we currently expect to occur before April 30, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time. The holders of Class B units have a preference over the holders of the subordinated units in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets.

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Results of Operations

Three Months Ended March 31, 2016 vs. Three Months Ended March 31, 2015

Our consolidated net loss decreased $103.8 million, from $178.7 million in the three months ended March 31, 2015, to $74.9 million in the three months ended March 31, 2016. The decrease in consolidated net loss was primarily a result of decreased loss on early extinguishment of debt, decreased derivative loss, net and decreased operating and maintenance expense.

Loss on early extinguishment of debt decreased $87.5 million, from $89.0 million in the three months ended March 31, 2015, to $1.5 million in the three months ended March 31, 2016. Loss on early extinguishment of debt during the three months ended March 31, 2016 was attributable to the write-off of debt issuance costs and unamortized discount in connection with the prepayment of the CTPL Term Loan in February 2016. Loss on early extinguishment of debt during the three months ended March 31, 2015 was attributable to the write-off of debt issuance costs and deferred commitment fees related to the termination of approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities in March 2015.

Derivative loss, net decreased $16.3 million, from $37.1 million in the three months ended March 31, 2015, to $20.8 million in the three months ended March 31, 2016. The derivative loss recognized during the three months ended March 31, 2016 was attributable to a decrease in the forward LIBOR curve during that period. The $37.1 million derivative loss recognized during the three months ended March 31, 2015 was primarily attributable to the loss recognized in March 2015 upon the termination of interest rate swaps associated with the 2013 SPL Credit Facilities.

Operating and maintenance expense decreased $13.1 million in the three months ended March 31, 2016, from $30.5 million in the three months ended March 31, 2015, to $17.4 million in the three months ended March 31, 2016. This decrease was due to expenses incurred during the three months ended March 31, 2015 to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which we did not incur during the three months ended March 31, 2016.

There was no significant change to interest expense, net of amounts capitalized in the three months ended March 31, 2016, as compared to the three months ended March 31, 2015, primarily as a result of our capitalization of interest costs incurred which were directly related to the construction of the first five Trains of the Liquefaction Project. For the three months ended March 31, 2016 and 2015, we incurred $192.6 million and $160.1 million of total interest cost, respectively, of which we capitalized and deferred $149.2 million and $117.2 million, respectively.

During the three months ended March 31, 2016, we did not have any LNG revenues related to amounts received from the sale of commissioning cargoes because amounts received were offset against LNG terminal construction-in-process. Amounts received relating to the commissioning cargoes, and the related costs incurred, are capitalized as testing costs for the construction of the Liquefaction Project.

Off-Balance Sheet Arrangements

As of March 31, 2016, 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, 2015.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 13—Recent Accounting Standards of our Notes to Consolidated Financial Statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Cash Investments

We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets.

Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas purchase agreements to secure natural gas feedstock for the Liquefaction Project(“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the basis price for natural gas for each delivery location. As of March 31, 2016, we estimated the fair value of the Liquefaction Supply Derivatives to be $29.9 million. Based on actual derivative contractual volumes, a 10% increase or decrease in the underlying basis price would have resulted in a change in the fair value of the Liquefaction Supply Derivatives of $6.1 million as of March 31, 2016, compared to $0.9 million as of December 31, 2015. See Note 6—Derivative Instruments for additional details about our derivative instruments.

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 2015 SPL Credit Facilities(“Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining term of the Interest Rate Derivatives. As of March 31, 2016, we estimated the fair value of the SPL Interest Rate Derivatives to be $18.0 million. This 10% change in interest rates would have resulted in a change in the fair value of our Interest Rate Derivatives of $1.9 million as of March 31, 2016, compared to $3.1 million as of December 31, 2015. The decrease in the effect of change in interest rates was due to a decrease in the forward 1-month LIBOR curve during the three months ended March 31, 2016.

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2016 CQP Credit Facilities(“CQP Interest Rate Derivatives”). 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 term of the CQP Interest Rate Derivatives. As of March 31, 2016, we estimated the fair value of the CQP Interest Rate Derivatives to be $9.5 million. This 10% change in interest rates would have resulted in a change in the fair value of the CQP Interest Rate Derivatives of $4.2 million as of March 31, 2016.

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.

LDEQ Matter

SPLNG, SPL and Sabine Pass Liquefaction Expansion, LLC (“SPLE”), are in discussions with the Louisiana Department of Environmental Quality (“LDEQ”) to resolve self-reported deviations arising from operation of the Sabine Pass LNG terminal and the commissioning of the natural gas liquefaction facilities at such terminal and relating to certain requirements under its operating permit issued under Title V of the Clean Air Act Title V permit conditions. The matter involves deviations self-reported to LDEQ pursuant to the Title V permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, SPLNG, SPL and SPLE received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. SPLNG, SPL and SPLE continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.

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, 2015.

ITEM 5. OTHER INFORMATION

On May 4, 2016, Cheniere entered into a letter agreement (the “Letter Agreement”) with Mr. Teague, its Executive Vice President, Asset Group and President and Chief Operating Officer of our general partner. Pursuant to the terms of the Letter Agreement, unless terminated earlier by either party, Mr. Teague’s employment with Cheniere will continue through the date that is seven days after the date of substantial completion of Train 2 of our liquefaction project under construction and development at the Sabine Pass LNG terminal in Louisiana (the “Continuation Period”), which we expect to be achieved in September 2016, based on the current construction schedule. Upon any termination of Mr. Teague’s employment with Cheniere, he has agreed to resign from any position he holds with our general partner. Mr. Teague has agreed in the Letter Agreement not to use or disclose any of Cheniere’s or its affiliates’ confidential or proprietary information.

The foregoing description of the Letter Agreement is qualified in its entirety by reference to such agreement, which is filed as Exhibit 10.6 hereto and incorporated herein by reference.

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the quarter ended March 31, 2016, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our quarterly report on Form 10-Q as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”). During the quarter ended March 31, 2016, we did not engage in any transactions with Iran or with persons or entities related to Iran.

Blackstone CQP Holdco, an affiliate of Blackstone Group, is a holder of more than 29% of our outstanding equity interests and has three representatives on the board of directors of Cheniere Partners GP. Accordingly, Blackstone Group may be deemed our “affiliate,” as that term is defined in Exchange Act Rule 12b-2. We have received notice from Blackstone Group that it may include in its quarterly report on Form 10-Q for the quarterly period ended March 31, 2016 disclosures pursuant to ITRA regarding two of its portfolio companies that may be deemed to be affiliates of Blackstone Group. Because of the broad definition of “affiliate” in Exchange Act Rule 12b-2, these portfolio companies of Blackstone Group, through Blackstone Group’s ownership of Cheniere Partners, may also be deemed to be affiliates of ours. We have not independently verified the disclosure described in the following paragraphs.

37

We have received notice from Blackstone Group that Travelport Worldwide Limited (“Travelport”) has engaged in the following activities: as part of its global business in the travel industry, Travelport provides certain passenger travel related Travel Commerce Platform and Technology Services to Iran Air. Travelport also provides certain airline Technology Services to Iran Air Tours. The gross revenues and net profits attributable to such activities by Travelport during the quarter ended March 31, 2016 have not been reported by Travelport. Blackstone Group informed us that Travelport intends to continue these business activities with Iran Air and Iran Air Tours as such activities are either exempt from applicable sanctions prohibitions or specifically licensed by the Office of Foreign Assets Control (the “OFAC”).

We have received notice from Blackstone Group that NCR Corporation (“NCR”) has engaged in the following activities: NCR has reported that during the period from January 1, 2016 through March 31, 2016, NCR maintained a bank account and guarantees at the Commercial Bank of Syria (“CBS”), which was designated as a Specially Designated National pursuant to Executive Order 13382 (“EO 13382”) on August 10, 2011.  This bank account and the guarantees at CBS were maintained in the normal course of business prior to the listing of CBS pursuant to EO 13382.  NCR reported that the last known account balance as of March 31, 2016, was approximately $3,468.  The bank account did not generate interest from January 1, 2016 through March 31, 2016, and the guarantees did not generate any revenue or profits for NCR. Pursuant to a license granted to NCR by the OFAC on January 3, 2013, and subsequent licenses granted on April 29, 2013, July 12, 2013, February 28, 2014, November 12, 2014, and October 24, 2015, NCR has been winding down its past operations in Syria. NCR’s current license expired on April 30, 2016. NCR has also received licenses from OFAC to close the CBS account and terminate any guarantees.  NCR’s application to renew the license to transact business with CBS, which was submitted to OFAC on May 18, 2015, remains pending. Following the termination of guarantees and the closure of the account, NCR does not intend to engage in any further business activities with CBS.

38

ITEM 6. EXHIBITS

Exhibit No.	Description
10.1	Credit and Guaranty Agreement, dated as of February 25, 2016, among the Partnership, as Borrower, certain subsidiaries of the Partnership, as Subsidiary Guarantors, the lenders from time to time party thereto, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank, Administrative Agent and Coordinating Lead Arranger, and certain arrangers and other participants (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 2, 2016)
10.2	Depositary Agreement, dated as of February 25, 2016, among the Partnership, certain subsidiaries of the Partnership, as Subsidiary Guarantors, MUFG Union Bank, N.A., as Collateral Agent and MUFG Union Bank, N.A., as Depositary Bank (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 2, 2016)
10.3	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00044 Potable Water Bypass Line and Pipeline Installation Tie-In at 135-A Metering Station, dated December 17, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 5, 2016)
10.4	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00020 Milestone Payment Adjustments, dated January 12, 2016 (Incorporated by reference to Exhibit 10.2 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 5, 2016)
10.5	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00004 DOE Regulation Change Impacts, RECON Schedule Change, Addition of Dry Flare Connection, Fuel Gas Supply Transfer to Train 5 & East Meter Fuel Gas, dated February 18, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.3 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 5, 2016)
10.6†	Letter agreement between R. Keith Teague and Cheniere Energy, Inc., dated May 4, 2016 (Incorporated by reference to Exhibit 10.7 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 5, 2016)
10.7*	Administrative Amendment, dated December 31, 2015, to the Second Amended and Restated Common Terms Agreement dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC and Société Générale, as the Common Security Trustee and Intercreditor Agent
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.
†	Management contract or compensatory plan or arrangement

39

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:	May 5, 2016	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Senior Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	May 5, 2016	By:	/s/ Leonard Travis
			Leonard Travis
			Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

40

EX-10.7

Exhibit 10.7

Execution Version

December 31, 2015

Sabine Pass Liquefaction, LLC

700 Milam St., Suite 800

Houston, Texas 77002

Attention: Treasurer

Telephone: 713-375-5290

Fax: 713-375-6000

Email: lisa.cohen@cheniere.com

Société Générale,

as the Commercial Banks Facility Agent

Attention: Ellen Turkel

The Korea Development Bank, New York Branch as the KSURE Covered Facility Agent

Attention: Tim Lee and Jun Il Kim

Shinhan Bank New York Branch as the KEXIM Facility Agent Attention: Jongkoo Lee

Re: Administrative Amendment to the Common Terms Agreement

Ladies and Gentlemen:

Reference is made to (i) the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015 (the “Common Terms Agreement”), among Sabine Pass Liquefaction, LLC, the Secured Debt Holder Group Representatives, the· Secured Hedge Representatives, and the Secured Gas Hedge Representatives that are parties thereto from time to time, Société Générale, as the Common Security Trustee (the “Common Security Trustee”), and Société Générale, as the Intercreditor Agent (the “lntercreditor Agent”) and (ii) the Second Amended and Restated Intercreditor Agreement, dated as of June 30, 2015 (the “Intercreditor Agreement”), among the Secured Debt Holder Group Representatives, the Secured Hedge Representatives, and the Secured Gas Hedge Representatives that are parties thereto from time to time, the Common Security Trustee and the Intercreditor Agent. Capitalized terms used but not defined herein have the meanings assigned to them in the Common Terms Agreement.

1. Consent to Amend Section 7.10 of the Common Terms Agreement. Pursuant to Section 10.0 of the Common Terms Agreement and Section 4.3 of the Intercreditor Agreement, the Common Security Trustee and Intercreditor Agent hereby consent to the following Administrative Decision (as defined in the Intercreditor Agreement):

The words “Monthly S.ales Charges” in Section 7.10 (Terminal Use Agreements) of the Common Terms Agreement are deleted and replaced with “monthly sales charges or comparable payments under the BG FOB Sale and Purchase Agreement or the GN FOB Sale and Purchase Agreement”.

2. Effectiveness. The consent set forth herein shall be effective only in the specific instance described herein and for the specific purpose for which it was given, and nothing herein shall be construed to limit or bar any rights or remedies of any Secured Party. For the avoidance of doubt and without limiting the generality of the foregoing, no other change, amendment, consent or waiver with respect to the terms and provisions of any other Financing Document, Material Project Document or Additional Material Project Document is intended or contemplated hereby (which terms and provisions remain unchanged and in full force and effect). Nothing herein shall be construed as or deemed to be (a) a waiver or consent by the Majority Secured Debt Participants of any past, present or future breach or non-compliance with any terms or provisions contained in any Financing Document, Material Project Document or Additional Material Project Document or (b) a guide to, or an intent or indication of, future actions or decisions by any Secured Party.

3. Governing Law. This consent letter shall for all purposes 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).

[Signature Page Follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this consent letter to be executed by their respective authorized officers as of the day and year first above written.

SOCIÉTÉ GÉNÉRALE,
as the Common Security Trustee and Intercreditor Agent
By:	/s/ Edward J. Grimm
Name:	Edward J. Grimm
Title:	Director

SIGNATURE PAGE TO ADMINISTRATIVE DECISION (CTA AMENDMENT)

ACKNOWLEDGED AND ACCEPTED that the amendment to Section 7.10 of the Common Terms Agreement effected pursuant to Section I of this Administrative Amendment is hereby agreed to as of the date first written above.

Sabine Pass Liquefaction, LLC,
as the Borrower
By:	/s/ Lisa C. Cohen
Name:	Lisa C. Cohen
Title:	Treasurer

SIGNATURE PAGE TO ADMINISTRATIVE DECISION (CTA 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, Neal A. Shear, 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: May 5, 2016

/s/ Neal A. Shear

Neal A. Shear

Interim 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: May 5, 2016

/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 March 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Neal A. Shear, Interim 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: May 5, 2016

/s/ Neal A. Shear

Neal A. Shear

Interim 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 March 31, 2016, 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: May 5, 2016

/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	3 Months Ended
	Mar. 31, 2016	Apr. 29, 2016
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	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Amendment Flag	false
Common Units [Member]
Entity Information [Line Items]
Entity Units, Units Outstanding		57,102,848
Class B Units [Member]
Entity Information [Line Items]
Entity Units, Units Outstanding		145,333,334
Subordinated Units [Member]
Entity Information [Line Items]
Entity Units, Units Outstanding		135,383,831

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 9,815	$ 146,221
Restricted cash	401,972	274,557
Accounts receivable—affiliate	14,544	1,271
Advances to affiliate	29,356	39,836
Inventory	28,543	16,667
Other current assets	17,986	14,923
Total current assets	502,216	493,475
Non-current restricted cash	13,650	13,650
Property, plant and equipment, net	12,713,379	11,931,602
Debt issuance costs, net	172,959	132,091
Non-current derivative assets	28,210	30,304
Other non-current assets	220,631	232,031
Total assets	13,651,045	12,833,153
Current liabilities
Accounts payable	17,131	16,407
Accrued liabilities	332,288	224,292
Current debt, net	1,785,318	1,673,379
Due to affiliates	78,159	115,123
Deferred revenue	26,669	26,669
Deferred revenue—affiliate	717	717
Derivative liabilities	11,818	6,430
Other current liabilities	93	0
Total current liabilities	2,252,193	2,063,017
Long-term debt, net	10,734,069	10,018,325
Non-current deferred revenue	8,500	9,500
Non-current derivative liabilities	16,210	2,884
Other non-current liabilities	172	175
Other non-current liabilities—affiliate	26,632	26,321
Partners’ equity
Common unitholders’ interest (57.1 million units issued and outstanding at March 31, 2016 and December 31, 2015)	259,168	305,747
Class B unitholders’ interest (145.3 million units issued and outstanding at March 31, 2016 and December 31, 2015)	(35,588)	(37,429)
Subordinated unitholders’ interest (135.4 million units issued and outstanding at March 31, 2016 and December 31, 2015)	375,104	428,035
General partner’s interest (2% interest with 6.9 million units issued and outstanding at March 31, 2016 and December 31, 2015)	14,585	16,578
Total partners’ equity	613,269	712,931
Total liabilities and partners’ equity	$ 13,651,045	$ 12,833,153

XML

Consolidated Balance Sheets Parentheticals - shares shares in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
General Partner Ownership Interest Percentage	2.00%	2.00%
General Partners' Capital Account, Units Issued	6,894		6,894
General partner units outstanding	6,894		6,894
Common Units [Member]
Limited Partners' Capital Account, Units Issued	57,084		57,084
Partnership unitholders units outstanding	57,084		57,084
Class B Units [Member]
Limited Partners' Capital Account, Units Issued	145,333		145,333
Partnership unitholders units outstanding	145,333		145,333
Subordinated Units [Member]
Limited Partners' Capital Account, Units Issued	135,384		135,384
Partnership unitholders units outstanding	135,384		135,384

XML

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenues
Regasification revenues	$ 65,384	$ 66,718
Regasification revenues—affiliate	1,635	812
LNG revenues	0	0
Other revenues	28	0
Total revenues	67,047	67,530
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	3,904	693
Operating and maintenance expense	17,385	30,540
Operating and maintenance expense—affiliate	10,830	4,773
Development expense	66	1,151
Development expense—affiliate	129	204
General and administrative expense	2,610	3,515
General and administrative expense—affiliate	22,198	21,597
Depreciation and amortization expense	19,388	14,879
Total operating costs and expenses	76,510	77,352
Loss from operations	(9,463)	(9,822)
Other income (expense)
Interest expense, net of amounts capitalized	(43,452)	(42,845)
Loss on early extinguishment of debt	(1,457)	(88,992)
Derivative loss, net	(20,808)	(37,138)
Other income	274	121
Total other expense	(65,443)	(168,854)
Net loss	$ (74,906)	$ (178,676)
Basic and diluted net loss per common unit	$ (0.08)	$ (0.61)
Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	57,084	57,080

XML

Consolidated Statement of Partners' Equity - 3 months ended Mar. 31, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Common Units [Member]	Class B Units [Member]	Subordinated Units [Member]	General Partner [Member]
Units, Outstanding, beginning of period at Dec. 31, 2015		57,084	145,333	135,384
Partners' equity, beginning of period at Dec. 31, 2015	$ 712,931	$ 305,747	$ (37,429)	$ 428,035	$ 16,578
General partner units, Outstanding, beginning of period at Dec. 31, 2015	6,894				6,894
Increase (Decrease) in Partners' Capital [Roll Forward]
Net loss	$ (74,906)	(21,772)	0	(51,636)	$ (1,498)
Distributions	(24,756)	(24,261)	0	0	(495)
Amortization of beneficial conversion feature of Class B units, Dollars	0	$ (546)	$ 1,841	$ (1,295)	0
Units, Outstanding, end of period at Mar. 31, 2016		57,084	145,333	135,384
Partners' equity, end of period at Mar. 31, 2016	$ 613,269	$ 259,168	$ (35,588)	$ 375,104	$ 14,585
General partner units, Outstanding, end of period at Mar. 31, 2016	6,894				6,894

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash flows from operating activities
Net loss	$ (74,906)	$ (178,676)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Non-cash LNG inventory write-downs	216	17,502
Depreciation and amortization expense	19,388	14,879
Amortization of debt issuance costs and discount	3,617	2,504
Loss on early extinguishment of debt	1,457	88,992
Total losses on derivatives, net	24,200	36,384
Net cash used for settlement of derivative instruments	(2,838)	(37,015)
Changes in restricted cash for certain operating activities	13,659	6,244
Changes in operating assets and liabilities:
Accounts and interest receivable	(26)	(25,928)
Accounts receivable—affiliate	904	(1,544)
Advances to affiliate	(1,237)	5,519
Inventory	(290)	(29,676)
Accounts payable and accrued liabilities	34,184	47,945
Due to affiliates	(7,669)	(3,971)
Deferred revenue	(1,000)	(1,003)
Other, net	(2,225)	(5,542)
Other, net—affiliate	(373)	10,962
Net cash provided by (used in) operating activities	7,061	(52,424)
Cash flows from investing activities
Property, plant and equipment, net	(714,616)	(542,114)
Use of restricted cash for the acquisition of property, plant and equipment	744,098	572,434
Other	(34,369)	(30,508)
Other—affiliate	0	0
Net cash used in investing activities	(4,887)	(188)
Cash flows from financing activities
Proceeds from issuances of debt	1,235,000	2,000,000
Repayments of debt	(415,000)	0
Debt issuance and deferred financing costs	(48,652)	(50,662)
Investment in restricted cash	(885,172)	(1,949,338)
Distributions to owners	(24,756)	(24,754)
Net cash used in financing activities	(138,580)	(24,754)
Net decrease in cash and cash equivalents	(136,406)	(77,366)
Cash and cash equivalents—beginning of period	146,221	248,830
Cash and cash equivalents—end of period	$ 9,815	$ 171,464

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Basis of Presentation

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

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

In 2016, we started production at our natural gas liquefaction facilities at the Sabine Pass LNG terminal (the “Liquefaction Project”). As a result, we introduced a new line item entitled “Cost of sales” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made in the prior period into this new line item. Cost of sales includes costs incurred directly for the production of LNG from the Liquefaction Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the Liquefaction Project, and other related costs to convert natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense, which now includes costs associated with operating and maintaining the Liquefaction Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs.

Additionally, we distinguished and reclassified our historical “revenues” line item into “regasification revenues” and “LNG revenues.” Regasification revenues include LNG regasification capacity reservation fees that are received pursuant to our TUAs and tug services fees that are received by Sabine Pass Tug Services, LLC, a wholly owned subsidiary of SPLNG. LNG revenues include fees that will be received pursuant to our SPAs and related LNG marketing activities.

Results of operations for the three months ended March 31, 2016 are not necessarily indicative of the operating results that will be realized for the year ending December 31, 2016.

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.

For further information, refer to the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2015.

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Unitholders' Equity

3 Months Ended

Mar. 31, 2016

Partners' Capital Notes [Abstract]

Unitholders' Equity

UNITHOLDERS’ EQUITY

The common units, Class B 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, 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. The higher percentages range from 15% to 50%.

During 2012, Blackstone CQP Holdco and Cheniere completed their purchases of a new class of equity interests representing limited partner interests in us (“Class B units”) for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds from the financings were used to fund a portion of the costs of developing, constructing and placing into service the first twoTrains of the natural gas liquefaction facilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities (the “Liquefaction Project”). In May 2013, Cheniere purchased an additional 12.0 millionClass B units for consideration of $180.0 million in connection with our acquisition of CTPL and Cheniere Pipeline GP Interests, LLC.  In 2013, Cheniere formed Cheniere Holdings to hold its limited partner interests in us. The Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Class B units are not entitled to cash distributions except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. On a quarterly basis beginning on the date of the initial purchase date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco was 1.68 and 1.65, respectively, as of March 31, 2016. We expect the Class B units to mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the Liquefaction Project, which we currently expect to occur before April 30, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

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Restricted Cash

3 Months Ended

Mar. 31, 2016

Cash and Cash Equivalents [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. Restricted cash consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Current restricted cash
SPLNG debt service and interest payment	$	115,469	$	77,415
Liquefaction project	177,609		189,260
CTPL construction and interest payment	—		7,882
CQP and cash held by guarantor subsidiaries	108,894		—
Total current restricted cash	$	401,972	$	274,557
Non-current restricted cash
SPLNG debt service	$	13,650	$	13,650

Under the indentures governing the senior notes issued by SPLNG (the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until certain conditions are satisfied, including: (1) there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and (2) there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the SPLNG Indentures. During the three months ended March 31, 2016 and 2015, SPLNG made distributions of $63.4 million and $70.8 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

In February 2016, we entered into a $2.8 billion credit facility (the “2016 CQP Credit Facilities”). Under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to us, we, and Cheniere Investments and CTPL as our guarantor subsidiaries, are subject to limitations on the use of cash. Specifically, we, Cheniere Investments and CTPL may only withdraw funds from collateral accounts held at a designated depositary bank on a monthly basis and for specific purposes, including for the payment of operating expenses. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions.

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Inventory

3 Months Ended

Mar. 31, 2016

Inventory Disclosure [Abstract]

Inventory

INVENTORY

As of March 31, 2016 and December 31, 2015, inventory consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Natural gas	$	3,333	$	5,724
LNG	2,847		3,690
Materials and other	22,363		7,253
Total inventory	$	28,543	$	16,667

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2016			2015
LNG terminal costs
LNG terminal	$	2,736,918		$	2,478,036
LNG terminal construction-in-process (1)	10,399,834			9,859,836
LNG site and related costs, net	133			135
Accumulated depreciation	(429,060		)	(411,907		)
Total LNG terminal costs, net	12,707,825			11,926,100
Fixed assets
Computer and office equipment	1,126			1,126
Furniture and fixtures	1,475			1,375
Computer software	4,198			4,238
Vehicles	2,484			2,081
Machinery and equipment	1,938			1,906
Other	95			93
Accumulated depreciation	(5,762		)	(5,317		)
Total fixed assets, net	5,554			5,502
Property, plant and equipment, net	$	12,713,379		$	11,931,602

(1) As of March 31, 2016, LNG terminal construction-in-process is presented net of amounts received from the sale of commissioning cargoes because the related costs were capitalized as testing costs for the construction of the Liquefaction Project.

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Derivative Instruments

3 Months Ended

Mar. 31, 2016

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 of our credit facilities (“Interest Rate Derivatives”);

• commodity derivatives consisting of natural gas purchase agreements for the commissioning and operation of the Liquefaction Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives”, and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”); and

• commodity derivatives to hedge the exposure to price risk attributable to future: (1) sales of our LNG inventory and (2) purchases of natural gas to operate the Sabine Pass LNG terminal (“Natural Gas Derivatives”).

None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations.

SPLNG has elected to account for a portion of the Natural Gas Derivatives as normal purchase normal sale transactions, exempt from fair value accounting. Gains and losses for these physical hedges are not reflected on our Consolidated Statements of Operations until the period of delivery. SPLNG had not posted collateral for such forward contracts as of March 31, 2016 and December 31, 2015.

The following table (in thousands) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015, which are classified as other current assets, non-current derivative assets, derivative liabilities or other non-current derivative liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	March 31, 2016										December 31, 2015
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
SPL Interest Rate Derivatives liability	$	—	$	(18,009	)	$	—	$	(18,009	)	$	—	$	(8,740	)	$	—	$	(8,740	)
CQP Interest Rate Derivatives liability	—		(9,490		)	—		(9,490		)	—		—			—		—
Liquefaction Supply Derivatives asset (liability)	—		(151		)	30,054		29,903			—		(25		)	32,492		32,467
Natural Gas Derivatives asset	—		—			—		—			—		39			—		39

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

The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a particular Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair value models include conditions precedent to the respective long-term natural gas purchase agreements. As of March 31, 2016 and December 31, 2015, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow. In the absence of infrastructure to accommodate marketable physical gas flow, our internal fair value models are based on a market price that equates to our own contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. 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 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 purchase agreements as of the reporting date.

There were no transfers into or out of Level 3 Physical Liquefaction Supply Derivatives for the three months ended March 31, 2016 and 2015. As all of our Physical Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2016:

	Net Fair Value Asset (in thousands)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$30,054	Income Approach	Basis Spread	$ (0.350) - $0.020

The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31,
	2016			2015
Balance, beginning of period	$	32,492		$	342
Realized and mark-to-market losses:
Included in cost of sales (1)	(2,653		)	—
Purchases and settlements:
Purchases	215			—
Settlements (1)	—			—
Balance, end of period	$	30,054		$	342
Change in unrealized gains relating to instruments still held at end of period	$	(2,194	)	$	—

(1) Does not include the decrease in fair value of $0.5 million related to the realized gains capitalized during the three months ended March 31, 2016.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position.  

Interest Rate Derivatives

SPL Interest Rate Derivatives

SPL has 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 $4.6 billion credit facilities (the “2015 SPL Credit Facilities”). The SPL Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities.

In March 2015, SPL settled a portion of the SPL Interest Rate Derivatives and recognized a derivative loss of $34.7 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments under the previous credit facilities.

CQP Interest Rate Derivatives

In March 2016, we entered into interest rate swaps (“CQP Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2016 CQP Credit Facilities. The CQP Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities.

As of March 31, 2016, 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
SPL Interest Rate Derivatives	$20.0 million	$628.8 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
CQP Interest Rate Derivatives	$225.0 million	$1.3 billion	March 22, 2016	February 29, 2020	1.19%	One-month LIBOR

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

	March 31, 2016									December 31, 2015
	SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			Total			SPL Interest Rate Derivatives			CQP Interest Rate Derivatives		Total
Balance Sheet Location
Derivative liabilities	$	(6,759	)	$	(4,530	)	$	(11,289	)	$	(5,940	)	$	—	$	(5,940	)
Non-current derivative liabilities	(11,250		)	(4,960		)	(16,210		)	(2,800		)	—		(2,800		)
Total derivative liabilities	(18,009		)	(9,490		)	(27,499		)	(8,740		)	—		(8,740		)
Derivative liability, net	$	(18,009	)	$	(9,490	)	$	(27,499	)	$	(8,740	)	$	—	$	(8,740	)

The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Consolidated Statements of Operations during the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31,
	2016			2015
SPL Interest Rates Derivatives loss	$	(11,278	)	$	(37,138	)
CQP Interest Rate Derivatives loss	(9,530		)	—

Commodity Derivatives

We recognize all commodity derivative instruments that qualify for derivative accounting treatment, including our Liquefaction Supply Derivatives and our Natural Gas Derivatives(collectively, “Commodity Derivatives”), as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Commodity Derivatives are reported in earnings.

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

	March 31, 2016								December 31, 2015
	Liquefaction Supply Derivatives (1)			Natural Gas Derivatives		Total			Liquefaction Supply Derivatives			Natural Gas Derivatives (2)		Total
Balance Sheet Location
Other current assets	$	2,222		$	—	$	2,222		$	2,737		$	39	$	2,776
Non-current derivative assets	28,210			—		28,210			30,304			—		30,304
Total derivative assets	30,432			—		30,432			33,041			39		33,080
Derivative liabilities	(529		)	—		(529		)	(490		)	—		(490		)
Non-current derivative liabilities	—			—		—			(84		)	—		(84		)
Total derivative liabilities	(529		)	—		(529		)	(574		)	—		(574		)
Derivative asset, net	$	29,903		$	—	$	29,903		$	32,467		$	39	$	32,506

(1) Does not include collateral of $1.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of March 31, 2016.

(2) Does not include collateral of $0.4 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

The following table (in thousands) shows the changes in the fair value and settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three months ended March 31, 2016 and 2015:

		Three Months Ended March 31,
	Statement of Operations Location	2016			2015
Liquefaction Supply Derivatives gain	Revenues	$	28		$	—
Liquefaction Supply Derivatives loss (1)	Cost of sales	(3,594		)	—
Natural Gas Derivatives gain	Operating and maintenance expense	174			754

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

The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our Commodity Derivatives are in an asset position.

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 primarily range from approximately one to seven years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified Trains of the Liquefaction Project. We recognize our Physical Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Physical Liquefaction Supply Derivatives are reported in earnings. As of March 31, 2016, SPL has secured up to approximately 2,047.9 millionMMBtu of natural gas feedstock through natural gas purchase agreements. The notional natural gas position of our Physical Liquefaction Supply Derivatives was approximately 1,134.9 millionMMBtu as of March 31, 2016.

Our Financial Liquefaction Supply Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our Financial Liquefaction Supply Derivatives activities.

Natural Gas Derivatives

Our Natural Gas Derivatives were executed through over-the-counter contracts which were subject to nominal credit risk as these transactions settled on a daily margin basis with investment grade financial institutions. We were required by these financial institutions to use margin deposits as credit support for our Natural Gas Derivatives activities. As of March 31, 2016, we did not have any open Natural Gas Derivatives positions or margin deposits at financial institutions.

Balance Sheet Presentation

Our Interest Rate Derivatives and Commodity Derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross and net basis:

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2016
SPL Interest Rate Derivatives	$	(18,009	)	$	—		$	(18,009	)
CQP Interest Rate Derivatives	(9,490		)	—			(9,490		)
Liquefaction Supply Derivatives	30,618			(186		)	30,432
Liquefaction Supply Derivatives	(1,668		)	1,139			(529		)
As of December 31, 2015
SPL Interest Rate Derivatives	$	(8,740	)	$	—		$	(8,740	)
Liquefaction Supply Derivatives	33,636			(595		)	33,041
Liquefaction Supply Derivatives	(574		)	—			(574		)
Natural Gas Derivatives	188			(149		)	39

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Other Non-Current Assets

3 Months Ended

Mar. 31, 2016

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

As of March 31, 2016 and December 31, 2015, other non-current assets consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Advances made under EPC and non-EPC contracts	$	19,766	$	32,049
Advances made to municipalities for water system enhancements	88,151		89,953
Tax-related payments and receivables	25,197		27,615
Information technology service assets	30,156		30,371
Other	57,361		52,043
Total other non-current assets	$	220,631	$	232,031

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Accrued Liabilities

3 Months Ended

Mar. 31, 2016

Accrued Liabilities [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

As of March 31, 2016 and December 31, 2015, accrued liabilities consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Interest expense and related debt fees	$	167,400	$	150,336
Liquefaction Project costs	158,264		66,223
LNG terminal costs	4,230		3,918
Other accrued liabilities	2,394		3,815
Total accrued liabilities	$	332,288	$	224,292

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Debt

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Debt

DEBT

As of March 31, 2016 and December 31, 2015, our debt consisted of the following (in thousands):

	March 31,			December 31,
	2016			2015
Long-term debt
SPLNG
6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) (1)	$	420,000		$	420,000
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $8,341 and $8,718	2,008,341			2,008,718
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000,000			1,000,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $6,212 and $6,392	1,506,212			1,506,392
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000,000			2,000,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000,000			2,000,000
2015 SPL Credit Facilities	1,505,000			845,000
CTPL
$400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429	—			398,571
Cheniere Partners
2016 CQP Credit Facilities	450,000			—
Unamortized debt issuance costs (2)	(155,484		)	(160,356		)
Total long-term debt, net	10,734,069			10,018,325
Current debt
7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of $3,130 and $4,303 (3)	1,662,370			1,661,197
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	125,000			15,000
Unamortized debt issuance costs (2)	(2,052		)	(2,818		)
Total current debt, net	1,785,318			1,673,379
Total debt, net	$	12,519,387		$	11,691,704

(1) Must be redeemed or repaid concurrently with the 2016 Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities.

(2) Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $160.4 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.

(3) Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities.

2016 Debt Issuances and Redemptions

2016 CQP Credit Facilities

In February 2016, we entered into the $2.8 billion2016 CQP Credit Facilities, which consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 millionCTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities ), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes.

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

We incurred $48.7 million of debt issuance costs during the three months ended March 31, 2016, and will incur an additional $21.5 million of debt issuance costs when the SPLNG tranche is funded. The prepayment of the CTPL Term Loan resulted in a write-off of unamortized discount and debt issuance costs of $1.5 million during the three months ended March 31, 2016. We pay a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit our ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the terms of the 2016 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 2016 CQP Credit Facilities are unconditionally guaranteed by each of our subsidiaries other than: (1) SPL, (2) SPLNG until funding of its tranche term loan and (3) certain of our subsidiaries owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2016 (in thousands):

	2015 SPL Credit Facilities		SPL Working Capital Facility		2016 CQP Credit Facilities
Total facility size	$	4,600,000	$	1,200,000	$	2,800,000
Outstanding balance	1,505,000		125,000		450,000
Letters of credit issued	—		236,459		7,500
Available commitment	$	3,095,000	$	838,541	$	2,342,500
Interest rate	LIBOR plus 1.30% - 1.75% or base rate plus 1.75%		LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date		December 31, 2020, with various terms for underlying loans		February 25, 2020, with principals due quarterly commencing on February 19, 2019

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

Interest Expense

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

	Three Months Ended March 31,
	2016			2015
Total interest cost	$	192,620		$	160,086
Capitalized interest	(149,168		)	(117,241		)
Total interest expense, net	$	43,452		$	42,845

Fair Value Disclosures

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

	March 31, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior Notes, net of premium or discount (1)	$	10,596,923	$	10,299,660	$	10,596,307	$	9,525,809
CTPL Term Loan, net of discount (2)	—		—		398,571		400,000
Credit facilities (2) (3)	2,080,000		2,080,000		860,000		860,000

(1) Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes and 2025 SPL Senior Notes(collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of our Senior Notes and other similar instruments.

(2) 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. 

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities.

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Related Party Transactions

3 Months Ended

Mar. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

LNG Terminal Capacity Agreements

Terminal Use Agreement

SPL obtained approximately 2.0Bcf/d of regasification capacity 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, continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project.

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. During the three months ended March 31, 2016 and 2015, we recorded $0.3 million and $17.8 million, respectively, as operating and maintenance expense related to this obligation. 

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments has the right to use SPL’s reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to SPLNG. However, the revenue earned by SPLNG from the capacity payments made under the TUA and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our 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. We recorded no revenues—affiliate from Cheniere Marketing during the three months ended March 31, 2016 and 2015, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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 at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Commissioning Agreement

In May 2015, SPL entered into an agreement with Cheniere Marketing that obligates Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. has control of, and is commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

In May 2015, SPL entered into an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC.

Services Agreements

As of March 31, 2016 and December 31, 2015, we had $29.4 million and $39.8 million of advances to affiliates, respectively, under the services agreements described below. During the three months ended March 31, 2016 and 2015, we recorded general and administrative expense—affiliate of $22.2 million and $21.6 million, respectively, and operating and maintenance expense—affiliate of $10.8 million and $4.8 million, respectively, under the services agreements described below.

Cheniere Partners Services Agreement

We have entered into 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 $2.8 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 entered into 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 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 entered into 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 incurs 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 incurs costs 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 entered into 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 incurs a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

SPL O&M Agreement

SPL has entered into 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 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 the Liquefaction Project is operational, the services include all necessary services required to operate and maintain the Liquefaction Project. Before the Liquefaction Project is operational, 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 Liquefaction Project 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 such 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 entered into 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 our behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Under the SPL MSA, 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 entered into 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 the counterparty 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.

CTPL MSA

CTPL has entered into a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the modification and operation of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations and providing contract administration services for all contracts associated with the pipeline facilities. Under the CTPL MSA, CTPL pays a monthly fee equal to 3.0% of the capital expenditures to enable bi-directional natural gas flow on the Creole Trail Pipeline incurred in the previous month.

LNG Lease Agreement

In September 2011, Cheniere Investments entered into an agreement in the form of a lease (the “LNG Lease Agreement”) with Cheniere Marketing that enables Cheniere Investments to supply the Sabine Pass LNG terminal with LNG to maintain proper LNG inventory levels and temperature. The LNG Lease Agreement also enables Cheniere Investments to hedge the exposure to variability in expected future cash flows of the LNG inventory. Under the terms of the LNG Lease Agreement, Cheniere Marketing funds all activities related to the purchase and hedging of the LNG, and Cheniere Investments reimburses Cheniere Marketing for all costs and assumes full price risk associated with these activities. As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, any LNG inventory purchased by Cheniere Marketing under this arrangement is classified as inventory—affiliate on our Consolidated Balance Sheets. As of March 31, 2016 and December 31, 2015, we had no LNG inventory—affiliate recorded on our Consolidated Balance Sheets under the LNG Lease Agreement.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”)

SPLNG has executed 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 up to $25.0 million in order to aid in their reconstruction efforts following Hurricane Rita. As of March 31, 2016, SPLNG has fulfilled its aggregate commitment obligations to the various Cameron Parish, Louisiana taxing authorities. 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, and in the year the Cameron Parish dollar-for-dollar credit is applied against, ad valorem tax levied on our LNG terminal.

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 March 31, 2016 and December 31, 2015, we had $24.5 million and $22.1 million, respectively, of both other non-current assets resulting from SPLNG’s ad valorem tax payments and 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. As a result, SPLNG records the purchases of natural gas and LNG from Cheniere Marketing to be utilized as fuel to operate the Sabine Pass LNG terminal as operating and maintenance expense.

SPLNG recorded operating and maintenance expense—affiliate of $0.7 million and $1.6 million in the three months ended March 31, 2016 and 2015, respectively, for natural gas purchased from Cheniere Marketing under these agreements. SPLNG recorded regasification revenues—affiliate of $0.9 million and $1.3 million in the three months ended March 31, 2016 and 2015, respectively, for natural gas sold to Cheniere Marketing under these agreements.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of SPLNG, entered into a tug sharing 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. Tug Services recorded revenues—affiliate of $0.6 million and $0.7 million pursuant to this agreement in each of the three months ended March 31, 2016 and 2015, respectively.

LNG Terminal Export Agreement

In January 2010, SPLNG and Cheniere Marketing entered into 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 months ended March 31, 2016 and 2015.

State Tax Sharing Agreements

In November 2006, SPLNG entered into 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 computed 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.

In August 2012, SPL entered into 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.

In May 2013, CTPL entered into 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 Loss per Common Unit

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Net Loss per Common Unit

NET 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 April 22, 2016, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on May 13, 2016 to unitholders of record as of May 2, 2016 for the period from January 1, 2016 to March 31, 2016.

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. Historical income (loss) attributable to a company that was purchased from an entity under common control is allocated to the predecessor owner in accordance with the terms 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 were issued at a discount to the market price of the common units into which they are convertible.  This discount totaling $2,130.0 million represents a beneficial conversion feature and is 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 is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortize the beneficial conversion feature assuming a conversion date of June 2017 and August 2017 for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively, although actual conversion may occur prior to or after these assumed dates. We are amortizing using the effective yield method with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature is also included in earnings per unit for the three months ended March 31, 2016 and 2015.

The following is a schedule by years, based on the capital structure as of March 31, 2016, of the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature (in thousands):

	Common Units			Class B Units		Subordinated Units
2016	$	(29,565	)	$	99,685	$	(70,119	)
2017	(594,426		)	2,004,209		(1,409,783		)

Under our partnership agreement, the incentive distribution rights (“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). We did not allocate earnings or losses to IDR holders for the purpose of the two-class method earnings per unit calculation for any of the periods presented. The following table (in thousands, except per unit data) provides a reconciliation of net loss and the allocation of net loss to the common units, the subordinated units and the general partner units for purposes of computing net loss per unit.

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner Units
Three Months Ended March 31, 2016
Net loss	$	(74,906	)
Declared distributions	24,756			24,261			—		—			495
Assumed allocation of undistributed net loss	$	(99,662	)	(28,967		)	—		(68,702		)	(1,993		)
Assumed allocation of net loss				$	(4,706	)	$	—	$	(68,702	)	$	(1,498	)
Weighted average units outstanding				57,084			145,333		135,384
Net loss per unit				$	(0.08	)	$	—	$	(0.51	)
Three Months Ended March 31, 2015
Net loss	$	(178,676	)
Declared distributions	24,754			24,259			—		—			495
Assumed allocation of undistributed net loss	$	(203,430	)	(59,125		)	—		(140,236		)	(4,070		)
Assumed allocation of net loss				$	(34,866	)	$	—	$	(140,236	)	$	(3,575	)
Weighted average units outstanding				57,080			145,333		135,384
Net loss per unit				$	(0.61	)	$	—	$	(1.04	)

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2016		2015
Cash paid during the period for interest, net of amounts capitalized and deferred	$	23,903	$	—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $307.3 million and $147.5 million, as of March 31, 2016 and 2015, respectively.

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Recent Accounting Standards

3 Months Ended

Mar. 31, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards

RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by the Partnership as of March 31, 2016:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard amends 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. This guidance may be early adopted beginning January 1, 2017, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	This standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted.	December 31, 2016	The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	These amendments primarily affect asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2016	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.
ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	These standards require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 9—Debt for required disclosures for a change in accounting principle.
ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions	This standard requires a master limited partnership to allocate net income (losses) of a transferred business entirely to the general partner when computing earnings per unit for periods before the dropdown transaction occurred. This guidance also requires a master limited partnership to disclose the effects of the dropdown transaction on net income (losses) per unit for the periods before and after the dropdown transaction occurred. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting, Policy

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

In 2016, we started production at our natural gas liquefaction facilities at the Sabine Pass LNG terminal (the “Liquefaction Project”). As a result, we introduced a new line item entitled “Cost of sales” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made in the prior period into this new line item. Cost of sales includes costs incurred directly for the production of LNG from the Liquefaction Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the Liquefaction Project, and other related costs to convert natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense, which now includes costs associated with operating and maintaining the Liquefaction Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs.

Additionally, we distinguished and reclassified our historical “revenues” line item into “regasification revenues” and “LNG revenues.” Regasification revenues include LNG regasification capacity reservation fees that are received pursuant to our TUAs and tug services fees that are received by Sabine Pass Tug Services, LLC, a wholly owned subsidiary of SPLNG. LNG revenues include fees that will be received pursuant to our SPAs and related LNG marketing activities.

Income Tax, 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)

3 Months Ended

Mar. 31, 2016

Cash and Cash Equivalents [Abstract]

Schedule of Restricted Cash

Restricted cash consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Current restricted cash
SPLNG debt service and interest payment	$	115,469	$	77,415
Liquefaction project	177,609		189,260
CTPL construction and interest payment	—		7,882
CQP and cash held by guarantor subsidiaries	108,894		—
Total current restricted cash	$	401,972	$	274,557
Non-current restricted cash
SPLNG debt service	$	13,650	$	13,650

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Inventory (Tables)

3 Months Ended

Mar. 31, 2016

Inventory Disclosure [Abstract]

Schedule of Inventory

As of March 31, 2016 and December 31, 2015, inventory consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Natural gas	$	3,333	$	5,724
LNG	2,847		3,690
Materials and other	22,363		7,253
Total inventory	$	28,543	$	16,667

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

	March 31,			December 31,
	2016			2015
LNG terminal costs
LNG terminal	$	2,736,918		$	2,478,036
LNG terminal construction-in-process (1)	10,399,834			9,859,836
LNG site and related costs, net	133			135
Accumulated depreciation	(429,060		)	(411,907		)
Total LNG terminal costs, net	12,707,825			11,926,100
Fixed assets
Computer and office equipment	1,126			1,126
Furniture and fixtures	1,475			1,375
Computer software	4,198			4,238
Vehicles	2,484			2,081
Machinery and equipment	1,938			1,906
Other	95			93
Accumulated depreciation	(5,762		)	(5,317		)
Total fixed assets, net	5,554			5,502
Property, plant and equipment, net	$	12,713,379		$	11,931,602

(1) As of March 31, 2016, LNG terminal construction-in-process is presented net of amounts received from the sale of commissioning cargoes because the related costs were capitalized as testing costs for the construction of the Liquefaction Project.

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

The following table (in thousands) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015, which are classified as other current assets, non-current derivative assets, derivative liabilities or other non-current derivative liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	March 31, 2016										December 31, 2015
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
SPL Interest Rate Derivatives liability	$	—	$	(18,009	)	$	—	$	(18,009	)	$	—	$	(8,740	)	$	—	$	(8,740	)
CQP Interest Rate Derivatives liability	—		(9,490		)	—		(9,490		)	—		—			—		—
Liquefaction Supply Derivatives asset (liability)	—		(151		)	30,054		29,903			—		(25		)	32,492		32,467
Natural Gas Derivatives asset	—		—			—		—			—		39			—		39

Fair Value Inputs, Assets, Quantitative Information

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2016:

	Net Fair Value Asset (in thousands)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$30,054	Income Approach	Basis Spread	$ (0.350) - $0.020

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

The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31,
	2016			2015
Balance, beginning of period	$	32,492		$	342
Realized and mark-to-market losses:
Included in cost of sales (1)	(2,653		)	—
Purchases and settlements:
Purchases	215			—
Settlements (1)	—			—
Balance, end of period	$	30,054		$	342
Change in unrealized gains relating to instruments still held at end of period	$	(2,194	)	$	—

(1) Does not include the decrease in fair value of $0.5 million related to the realized gains capitalized during the three months ended March 31, 2016.

Derivative Net Presentation on Consolidated Balance Sheets

The following table (in thousands) shows the fair value of our derivatives outstanding on a gross and net basis:

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2016
SPL Interest Rate Derivatives	$	(18,009	)	$	—		$	(18,009	)
CQP Interest Rate Derivatives	(9,490		)	—			(9,490		)
Liquefaction Supply Derivatives	30,618			(186		)	30,432
Liquefaction Supply Derivatives	(1,668		)	1,139			(529		)
As of December 31, 2015
SPL Interest Rate Derivatives	$	(8,740	)	$	—		$	(8,740	)
Liquefaction Supply Derivatives	33,636			(595		)	33,041
Liquefaction Supply Derivatives	(574		)	—			(574		)
Natural Gas Derivatives	188			(149		)	39

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

March 31, 2016, 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
SPL Interest Rate Derivatives	$20.0 million	$628.8 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
CQP Interest Rate Derivatives	$225.0 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 (in thousands) shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets:

	March 31, 2016									December 31, 2015
	SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			Total			SPL Interest Rate Derivatives			CQP Interest Rate Derivatives		Total
Balance Sheet Location
Derivative liabilities	$	(6,759	)	$	(4,530	)	$	(11,289	)	$	(5,940	)	$	—	$	(5,940	)
Non-current derivative liabilities	(11,250		)	(4,960		)	(16,210		)	(2,800		)	—		(2,800		)
Total derivative liabilities	(18,009		)	(9,490		)	(27,499		)	(8,740		)	—		(8,740		)
Derivative liability, net	$	(18,009	)	$	(9,490	)	$	(27,499	)	$	(8,740	)	$	—	$	(8,740	)

Derivative Instruments, Gain (Loss)

The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Consolidated Statements of Operations during the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31,
	2016			2015
SPL Interest Rates Derivatives loss	$	(11,278	)	$	(37,138	)
CQP Interest Rate Derivatives loss	(9,530		)	—

Commodity Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Instruments by Balance Sheet Location

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

	March 31, 2016								December 31, 2015
	Liquefaction Supply Derivatives (1)			Natural Gas Derivatives		Total			Liquefaction Supply Derivatives			Natural Gas Derivatives (2)		Total
Balance Sheet Location
Other current assets	$	2,222		$	—	$	2,222		$	2,737		$	39	$	2,776
Non-current derivative assets	28,210			—		28,210			30,304			—		30,304
Total derivative assets	30,432			—		30,432			33,041			39		33,080
Derivative liabilities	(529		)	—		(529		)	(490		)	—		(490		)
Non-current derivative liabilities	—			—		—			(84		)	—		(84		)
Total derivative liabilities	(529		)	—		(529		)	(574		)	—		(574		)
Derivative asset, net	$	29,903		$	—	$	29,903		$	32,467		$	39	$	32,506

(1) Does not include collateral of $1.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of March 31, 2016.

(2) Does not include collateral of $0.4 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

Derivative Instruments, Gain (Loss)

The following table (in thousands) shows the changes in the fair value and settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three months ended March 31, 2016 and 2015:

		Three Months Ended March 31,
	Statement of Operations Location	2016			2015
Liquefaction Supply Derivatives gain	Revenues	$	28		$	—
Liquefaction Supply Derivatives loss (1)	Cost of sales	(3,594		)	—
Natural Gas Derivatives gain	Operating and maintenance expense	174			754

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

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Other Non-Current Assets (Tables)

3 Months Ended

Mar. 31, 2016

Other Assets, Noncurrent [Abstract]

Schedule of Non-Current Assets

As of March 31, 2016 and December 31, 2015, other non-current assets consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Advances made under EPC and non-EPC contracts	$	19,766	$	32,049
Advances made to municipalities for water system enhancements	88,151		89,953
Tax-related payments and receivables	25,197		27,615
Information technology service assets	30,156		30,371
Other	57,361		52,043
Total other non-current assets	$	220,631	$	232,031

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Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2016

Accrued Liabilities [Abstract]

Schedule of Accrued Liabilities

As of March 31, 2016 and December 31, 2015, accrued liabilities consisted of the following (in thousands):

	March 31,		December 31,
	2016		2015
Interest expense and related debt fees	$	167,400	$	150,336
Liquefaction Project costs	158,264		66,223
LNG terminal costs	4,230		3,918
Other accrued liabilities	2,394		3,815
Total accrued liabilities	$	332,288	$	224,292

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Debt (Tables)

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Schedule of Debt Instruments

As of March 31, 2016 and December 31, 2015, our debt consisted of the following (in thousands):

	March 31,			December 31,
	2016			2015
Long-term debt
SPLNG
6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) (1)	$	420,000		$	420,000
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $8,341 and $8,718	2,008,341			2,008,718
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000,000			1,000,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $6,212 and $6,392	1,506,212			1,506,392
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000,000			2,000,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000,000			2,000,000
2015 SPL Credit Facilities	1,505,000			845,000
CTPL
$400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429	—			398,571
Cheniere Partners
2016 CQP Credit Facilities	450,000			—
Unamortized debt issuance costs (2)	(155,484		)	(160,356		)
Total long-term debt, net	10,734,069			10,018,325
Current debt
7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of $3,130 and $4,303 (3)	1,662,370			1,661,197
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	125,000			15,000
Unamortized debt issuance costs (2)	(2,052		)	(2,818		)
Total current debt, net	1,785,318			1,673,379
Total debt, net	$	12,519,387		$	11,691,704

(1) Must be redeemed or repaid concurrently with the 2016 Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities.

(2) Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $160.4 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.

(3) Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities.

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2016 (in thousands):

	2015 SPL Credit Facilities		SPL Working Capital Facility		2016 CQP Credit Facilities
Total facility size	$	4,600,000	$	1,200,000	$	2,800,000
Outstanding balance	1,505,000		125,000		450,000
Letters of credit issued	—		236,459		7,500
Available commitment	$	3,095,000	$	838,541	$	2,342,500
Interest rate	LIBOR plus 1.30% - 1.75% or base rate plus 1.75%		LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date		December 31, 2020, with various terms for underlying loans		February 25, 2020, with principals due quarterly commencing on February 19, 2019

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

Interest Income and Interest Expense Disclosure

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

	Three Months Ended March 31,
	2016			2015
Total interest cost	$	192,620		$	160,086
Capitalized interest	(149,168		)	(117,241		)
Total interest expense, net	$	43,452		$	42,845

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	March 31, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior Notes, net of premium or discount (1)	$	10,596,923	$	10,299,660	$	10,596,307	$	9,525,809
CTPL Term Loan, net of discount (2)	—		—		398,571		400,000
Credit facilities (2) (3)	2,080,000		2,080,000		860,000		860,000

(1) Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes and 2025 SPL Senior Notes(collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of our Senior Notes and other similar instruments.

(2) 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. 

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities.

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Net Loss per Common Unit (Tables)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts

The following is a schedule by years, based on the capital structure as of March 31, 2016, of the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature (in thousands):

	Common Units			Class B Units		Subordinated Units
2016	$	(29,565	)	$	99,685	$	(70,119	)
2017	(594,426		)	2,004,209		(1,409,783		)

Schedule of Net Loss per Common Unit

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

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner Units
Three Months Ended March 31, 2016
Net loss	$	(74,906	)
Declared distributions	24,756			24,261			—		—			495
Assumed allocation of undistributed net loss	$	(99,662	)	(28,967		)	—		(68,702		)	(1,993		)
Assumed allocation of net loss				$	(4,706	)	$	—	$	(68,702	)	$	(1,498	)
Weighted average units outstanding				57,084			145,333		135,384
Net loss per unit				$	(0.08	)	$	—	$	(0.51	)
Three Months Ended March 31, 2015
Net loss	$	(178,676	)
Declared distributions	24,754			24,259			—		—			495
Assumed allocation of undistributed net loss	$	(203,430	)	(59,125		)	—		(140,236		)	(4,070		)
Assumed allocation of net loss				$	(34,866	)	$	—	$	(140,236	)	$	(3,575	)
Weighted average units outstanding				57,080			145,333		135,384
Net loss per unit				$	(0.61	)	$	—	$	(1.04	)

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Three Months Ended March 31,
	2016		2015
Cash paid during the period for interest, net of amounts capitalized and deferred	$	23,903	$	—

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Recent Accounting Standards (Tables)

3 Months Ended

Mar. 31, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards, Not Yet Adopted

The following table provides a brief description of recent accounting standards that had not been adopted by the Partnership as of March 31, 2016:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard amends 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. This guidance may be early adopted beginning January 1, 2017, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern	This standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted.	December 31, 2016	The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

Recent Accounting Standards, Adopted

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis	These amendments primarily affect asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.	January 1, 2016	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.
ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements	These standards require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 9—Debt for required disclosures for a change in accounting principle.
ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions	This standard requires a master limited partnership to allocate net income (losses) of a transferred business entirely to the general partner when computing earnings per unit for periods before the dropdown transaction occurred. This guidance also requires a master limited partnership to disclose the effects of the dropdown transaction on net income (losses) per unit for the periods before and after the dropdown transaction occurred. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.	January 1, 2016	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

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Unitholders' Equity (Details) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	May. 31, 2013 USD ($) shares	Mar. 31, 2016 Rate item $ / shares	Dec. 31, 2012 USD ($)
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 | $ / shares		$ 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%
Class B Units [Member]
Other Ownership Interests [Line Items]
Partnership Units, Conversion Ratio, Quarterly Compounded Rate		0.035
Class B Units [Member] | Maximum [Member]
Other Ownership Interests [Line Items]
Expected conversion period of Class B units to common units after substantial completion date of Train 3		90 days
Class B Unit Financing [Member]
Other Ownership Interests [Line Items]
Number of Liquefaction LNG Trains | item		2
Blackstone [Member] | Class B Units [Member]
Other Ownership Interests [Line Items]
Proceeds from sale of partnership common and general partner units | $			$ 1,500.0
Partnership Units, Accreted Conversion Ratio | Rate		1.65
Cheniere [Member] | Class B Units [Member]
Other Ownership Interests [Line Items]
Proceeds from sale of partnership common and general partner units | $	$ 180.0		$ 500.0
Additional units purchased, shares | shares	12.0
Cheniere Holdings [Member] | Class B Units [Member]
Other Ownership Interests [Line Items]
Partnership Units, Accreted Conversion Ratio | Rate		1.68

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Restricted Cash (Details)	3 Months Ended
	Mar. 31, 2016 USD ($) Rate item	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 401,972,000		$ 274,557,000
Non-current restricted cash	13,650,000		13,650,000
Partners' Capital Account, Distributions	24,756,000
SPLNG Debt Service And Interest Payment [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	115,469,000		77,415,000
Liquefaction Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	177,609,000		189,260,000
CTPL Construction And Interest Payment [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	0		7,882,000
CQP And Cash Held By Guarantor Subsidiaries [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	108,894,000		0
SPLNG Debt Service [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Non-current restricted cash	$ 13,650,000		$ 13,650,000
2016 CQP Credit Facilities [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Debt Instrument, Fixed Charge, Coverage Ratio | Rate	1.15
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,800,000,000.0
SPLNG [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Partners' Capital Account, Distributions	$ 63,400,000	$ 70,800,000
SPLNG [Member] | SPLNG Senior Notes [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Debt Instrument, Number Of Months' Interest Required To Be On Deposit Per Months Elapsed Since Last Interest Payment For Distribution | item	1
Debt Instrument, Number of Semi-Annual Interest Payments Required To Be On Deposit In Permanent Debt Service FundFor Distribution | item	1
Debt Instrument, Fixed Charge, Coverage Ratio | Rate	2

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Inventory (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Inventory [Line Items]
Total inventory	$ 28,543	$ 16,667
Natural gas [Member]
Inventory [Line Items]
Total inventory	3,333	5,724
LNG [Member]
Inventory [Line Items]
Total inventory	2,847	3,690
Materials and other [Member]
Inventory [Line Items]
Total inventory	$ 22,363	$ 7,253

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Property, Plant and Equipment (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net		$ 12,713,379	$ 11,931,602
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation		(429,060)	(411,907)
Property, plant and equipment, net		12,707,825	11,926,100
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		2,736,918	2,478,036
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	[1]	10,399,834	9,859,836
LNG site and related costs, net [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		133	135
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation		(5,762)	(5,317)
Property, plant and equipment, net		5,554	5,502
Computer and office equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		1,126	1,126
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		1,475	1,375
Computer software [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		4,198	4,238
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		2,484	2,081
Machinery and equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		1,938	1,906
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 95	$ 93

[1] As of March 31, 2016, LNG terminal construction-in-process is presented net of amounts received from the sale of commissioning cargoes because the related costs were capitalized as testing costs for the construction of the Liquefaction Project.

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Derivative Instruments - Narrative (Details) MMBTU in Millions	1 Months Ended	3 Months Ended
	Mar. 31, 2015 USD ($)	Mar. 31, 2016 USD ($) MMBTU	Mar. 31, 2015 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Asset Transfers into Level 3		$ 0	$ 0
Asset Transfers out of Level 3		0	$ 0
2015 SPL Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 4,600,000,000
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount | MMBTU		1,134.9
Liquefaction Supply Derivatives [Member] | Minimum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract		1 year
Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract		7 years
Natural Gas Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount		0
Derivative, Collateral, Right to Reclaim Cash		$ 0
SPL [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Energy Units Secured Through Long-Term Purchase Agreements | MMBTU		2,047.9
SPL [Member] | 2015 SPL Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 4,600,000,000
SPL [Member] | SPL Previous Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease, Net	$ 1,800,000,000
SPL [Member] | SPL Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Loss, Net	$ 34,700,000

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
SPL Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (18,009)	$ (8,740)
SPL 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
SPL 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	(18,009)	(8,740)
SPL 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
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	(9,490)	0
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	(9,490)	0
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	29,903	32,467
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	0	0
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	(151)	(25)
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	30,054	32,492
Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	39
Natural Gas 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
Natural Gas 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	0	39
Natural Gas 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

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Liquefaction Supply Derivatives [Member] - USD ($)	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Net Fair Value Asset	$ 29,903,000	$ 32,467,000
Fair Value, Inputs, Level 3 [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Net Fair Value Asset	$ 30,054,000	$ 32,492,000
Valuation Techniques	Income Approach
Significant Unobservable Input	Basis Spread
Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Significant Unobservable Input Range	$ (0.350)
Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Significant Unobservable Input Range	$ 0.020

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Derivative Instruments - Schedule of Level 3 Activity (Details) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ 32,492	$ 342
Realized and mark-to-market losses:
Included in cost of sales	[1]	(2,653)	0
Purchases and settlements:
Purchases		215	0
Settlements	[1]	0	0
Balance, end of period		30,054	342
Change in unrealized gains relating to instruments still held at end of period		(2,194)	$ 0
Decrease in Fair Value Realized and Capitalized During Period		$ 500

[1] Does not include the decrease in fair value of $0.5 million related to the realized gains capitalized during the three months ended March 31, 2016.

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Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
SPL Interest Rate Derivatives [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 20.0
Effective Date	Aug. 14, 2012
Maturity Date	Jul. 31, 2019
Weighted Average Fixed Interest Rate Paid	1.98%
Variable Interest Rate Received	One-month LIBOR
SPL Interest Rate Derivatives [Member] | Maximum [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 628.8
CQP Interest Rate Derivatives [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 225.0
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
CQP Interest Rate Derivatives [Member] | Maximum [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 1,300.0

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($)	Mar. 31, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Non-current derivative assets	$ 28,210,000		$ 30,304,000
Derivative liabilities	(11,818,000)		(6,430,000)
Non-current derivative liabilities	(16,210,000)		(2,884,000)
Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities	(27,499,000)		(8,740,000)
Derivative asset (liability), net	(27,499,000)		(8,740,000)
Interest Rate Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(11,289,000)		(5,940,000)
Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	(16,210,000)		(2,800,000)
SPL Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities	(18,009,000)		(8,740,000)
Derivative asset (liability), net	(18,009,000)		(8,740,000)
SPL Interest Rate Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(6,759,000)		(5,940,000)
SPL Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	(11,250,000)		(2,800,000)
CQP Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities	(9,490,000)		0
Derivative asset (liability), net	(9,490,000)		0
CQP Interest Rate Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(4,530,000)		0
CQP Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	(4,960,000)		0
Commodity Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	30,432,000		33,080,000
Total derivative liabilities	(529,000)		(574,000)
Derivative asset (liability), net	29,903,000		32,506,000
Commodity Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets	2,222,000		2,776,000
Commodity Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	28,210,000		30,304,000
Commodity Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(529,000)		(490,000)
Commodity Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	0		(84,000)
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	30,432,000	[1]	33,041,000
Total derivative liabilities	(529,000)	[1]	(574,000)
Derivative asset (liability), net	29,903,000	[1]	32,467,000
Liquefaction Supply Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets	2,222,000	[1]	2,737,000
Derivative, Collateral, Right to Reclaim Cash	1,500,000
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	28,210,000	[1]	30,304,000
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(529,000)	[1]	(490,000)
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	0	[1]	(84,000)
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	0		39,000	[2]
Total derivative liabilities	0		0	[2]
Derivative asset (liability), net	0		39,000	[2]
Derivative, Collateral, Right to Reclaim Cash	0
Natural Gas Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets	0		39,000	[2]
Derivative, Collateral, Right to Reclaim Cash			400,000
Natural Gas Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	0		0	[2]
Natural Gas Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	0		0	[2]
Natural Gas Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	$ 0		$ 0	[2]

[1] Does not include collateral of $1.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of March 31, 2016.

[2] Does not include collateral of $0.4 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
SPL Interest Rate Derivatives [Member] | Derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ (11,278)	$ (37,138)
CQP Interest Rate Derivatives [Member] | Derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(9,530)	0
Liquefaction Supply Derivatives [Member] | Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		28	0
Liquefaction Supply Derivatives [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	[1]	(3,594)	0
Natural Gas Derivatives [Member] | Operating and maintenance expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 174	$ 754

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

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Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
SPL Interest Rate Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	$ (18,009)	$ (8,740)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Derivative Assets (Liabilities), at Fair Value, Net	(18,009)	(8,740)
CQP Interest Rate Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(9,490)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	0
Derivative Assets (Liabilities), at Fair Value, Net	(9,490)
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	30,618	33,636
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(186)	(595)
Derivative Assets (Liabilities), at Fair Value, Net	30,432	33,041
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(1,668)	(574)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	1,139	0
Derivative Assets (Liabilities), at Fair Value, Net	$ (529)	(574)
Natural Gas Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		188
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet		(149)
Derivative Assets (Liabilities), at Fair Value, Net		$ 39

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Other Non-Current Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Other Assets, Noncurrent [Abstract]
Advances made under EPC and non-EPC contracts	$ 19,766	$ 32,049
Advances made to municipalities for water system enhancements	88,151	89,953
Tax-related payments and receivables	25,197	27,615
Information Technology Service Assets	30,156	30,371
Other	57,361	52,043
Total other non-current assets	$ 220,631	$ 232,031

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Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Accrued Liabilities [Abstract]
Interest expense and related debt fees	$ 167,400	$ 150,336
Liquefaction Project costs	158,264	66,223
LNG terminal costs	4,230	3,918
Other accrued liabilities	2,394	3,815
Total accrued liabilities	$ 332,288	$ 224,292

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Debt - Schedule of Debt Instruments (Details) - USD ($)		Mar. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Net		$ 10,734,069,000	$ 10,018,325,000
Unamortized Debt Issuance Costs, Noncurrent	[1]	(155,484,000)	(160,356,000)
Current Debt, Net		1,785,318,000	1,673,379,000
Unamortized Debt Issuance Costs, Current	[1]	(2,052,000)	(2,818,000)
Total Debt, Net		12,519,387,000	11,691,704,000
2020 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	[2]	$ 420,000,000	420,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.50%
2021 Sabine Pass Liquefaction Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net		$ 2,008,341,000	2,008,718,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
Debt Instrument, Unamortized Premium		$ 8,341,000	8,718,000
2022 Sabine Pass Liquefaction Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net		$ 1,000,000,000	1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.25%
2023 Sabine Pass Liquefaction Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net		$ 1,506,212,000	1,506,392,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
Debt Instrument, Unamortized Premium		$ 6,212,000	6,392,000
2024 Sabine Pass Liquefaction Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net		$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.75%
2025 Sabine Pass Liquefaction Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net		$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
2015 SPL Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Net		$ 1,505,000,000	845,000,000
Line of Credit Facility, Maximum Borrowing Capacity		4,600,000,000
CTPL Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt, Net		0	398,571,000
Line of Credit Facility, Maximum Borrowing Capacity			400.0
Debt Instrument, Unamortized Discount		0	1,429,000
2016 CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Net		450,000,000	0
Line of Credit Facility, Maximum Borrowing Capacity		2,800,000,000.0
2016 Senior Notes [Member]
Debt Instrument [Line Items]
Current Debt, Net	[3]	$ 1,662,370,000	1,661,197,000
Debt Instrument, Interest Rate, Stated Percentage		7.50%
Debt Instrument, Unamortized Discount		$ 3,130,000	4,303,000
Working Capital Facility [Member]
Debt Instrument [Line Items]
Current Debt, Net		125,000,000	$ 15,000,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,200,000,000

[1] Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $160.4 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.

[2] Must be redeemed or repaid concurrently with the 2016 Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities.

[3] Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities.

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Debt - Debt Issuances and Redemptions (Details)		1 Months Ended	3 Months Ended
		Feb. 29, 2016 USD ($)	Mar. 31, 2016 USD ($) Rate	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Line of Credit Facility [Line Items]
Repayments of Long-term Debt			$ 415,000,000	$ 0
Debt Issuance Costs, Line of Credit Arrangements, Gross			172,959,000		$ 132,091,000
Loss on early extinguishment of debt			1,457,000	$ 88,992,000
2016 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 2,800,000,000.0
Debt Instrument, Balance Required in Reserve Account, Period of Debt Service			6 months
Debt Instrument, Description of Variable Rate Basis	[1]		LIBOR or base rate
Debt Instrument, Interest Rate, Increase			0.50%
Debt Issuance Costs, Line of Credit Arrangements, Gross			$ 48,700,000
Line of Credit Facility, Commitment Fee Percentage			40.00%
Debt Instrument, Fixed Charge, Coverage Ratio | Rate			1.15
2016 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%
2016 CQP Credit Facilities [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]		1.25%
2016 CQP Credit Facilities [Member] | Base Rate [Member] | Base Rate Determination Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.50%
2016 CQP Credit Facilities [Member] | Base Rate [Member] | Base Rate Determination LIBOR [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.00%
2016 CQP Credit Facilities [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives			50.00%
Debt Instrument, Fixed Charge, Coverage Ratio, Projected | Rate			1.55
2016 CQP Credit Facilities - CTPL Tranche Term Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 450,000,000.0
2016 CQP Credit Facilities - SPLNG Tranche Term Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			2,100,000,000
Debt Issuance Costs, Line of Credit Arrangements, Gross			21,500,000
2016 CQP Credit Facilities - Debt Service Reserve Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			125,000,000.0
2016 CQP Credit Facilities - Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 115,000,000.0
2016 CQP Credit Facilities - Letter of Credit [Member] | Portion issued and not drawn [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase			0.50%
Line of Credit Facility, Commitment Fee Percentage			2.25%
CTPL Term Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					$ 400.0
Repayments of Long-term Debt		$ 400,000,000
Loss on early extinguishment of debt			$ 1,457,000
SPLNG Senior Notes [Member]
Line of Credit Facility [Line Items]
Long-term Debt, Gross			$ 2,100,000,000

[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 - Credit Facilities (Details) - USD ($)		3 Months Ended
		Mar. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Outstanding balance		$ 10,734,069,000	$ 10,018,325,000
Outstanding balance, current		1,785,318,000	1,673,379,000
2015 SPL Credit Facilities [Member]
Line of Credit Facility [Line Items]
Total facility size		4,600,000,000
Outstanding balance		1,505,000,000	845,000,000
Letters of credit issued		0
Available commitment		$ 3,095,000,000
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date
2015 SPL Credit Facilities [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
2015 SPL Credit Facilities [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.30%
2015 SPL Credit Facilities [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size		$ 1,200,000,000
Outstanding balance, current		125,000,000	15,000,000
Letters of credit issued		236,459,000
Available commitment		$ 838,541,000
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		December 31, 2020, with various terms for underlying loans
Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Working Capital Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
2016 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Total facility size		$ 2,800,000,000.0
Outstanding balance		450,000,000	$ 0
Letters of credit issued		7,500,000
Available commitment		$ 2,342,500,000
Debt Instrument, Description of Variable Rate Basis	[1]	LIBOR or base rate
Debt Instrument, Interest Rate, Increase		0.50%
Debt Instrument, Maturity Date, Description		February 25, 2020, with principals due quarterly commencing on February 19, 2019
2016 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%
2016 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 Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Debt Disclosure [Abstract]
Total interest cost	$ 192,620	$ 160,086
Capitalized interest	(149,168)	(117,241)
Total interest expense, net	$ 43,452	$ 42,845

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 12,519,387	$ 11,691,704
Senior Notes, net of premium or discount [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	10,596,923	10,596,307
Senior Notes, net of premium or discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	[1]	10,299,660	9,525,809
CTPL Term Loan, net of discount [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	0	398,571
CTPL Term Loan, net of discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Loans Payable, Fair Value Disclosure	[2]	0	400,000
Credit facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2],[3]	2,080,000	860,000
Credit facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[2],[3]	$ 2,080,000	$ 860,000

[1] Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes and 2025 SPL Senior Notes (collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of our Senior Notes and other similar instruments.

[2] 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.

[3] Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities.

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Related Party Transactions - LNG Terminal Capacity Agreements (Details) $ in Thousands	1 Months Ended	3 Months Ended
	May. 31, 2015 trains	Mar. 31, 2016 USD ($) bcf / d $ / MMBTU	Mar. 31, 2015 USD ($)
Related Party Transaction [Line Items]
Operating and maintenance expense		$ 17,385	$ 30,540
Regasification revenues—affiliate		$ 1,635	812
SPL [Member] | LNG Terminal Capacity Agreements [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Regasification Capacity | bcf / d		2.0
Related Party Transaction, Committed Annual Fee		$ 250,000
Related Party Agreement Term		20 years
Operating and maintenance expense		$ 300	17,800
SPL [Member] | Commissioning Agreement [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
Number of Liquefaction LNG Trains Subject To In Agreement | trains	4
Cheniere Marketing [Member] | LNG Terminal Capacity Agreements [Member] | Cheniere Investments [Member]
Related Party Transaction [Line Items]
Proceeds (Payments) of Gross Margin Earned, Percentage		80.00%
Regasification revenues—affiliate		$ 0	$ 0
Cheniere Marketing [Member] | LNG Sale and Purchase Agreement [Member] | SPL [Member]
Related Party Transaction [Line Items]
Incremental LNG Volume, Purchase Price Percentage of Henry Hub		115.00%
Incremental LNG Volume, Purchase Price Per MMBtu | $ / MMBTU		3.00

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Related Party Transactions - Service Agreements (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 29,356,000		$ 39,836,000
General and administrative expense—affiliate	22,198,000	$ 21,597,000
Operating and maintenance expense—affiliate	10,830,000	4,773,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	29,400,000		$ 39,800,000
General and administrative expense—affiliate	22,200,000	21,600,000
Operating and maintenance expense—affiliate	10,800,000	$ 4,800,000
Cheniere Partners Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Quarterly non-accountable overhead reimbursement charge	2,800,000
SPLNG [Member] | Operation and Maintenance Agreement [Member] | Cheniere Investments [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%
SPLNG [Member] | Management Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 520,000
SPL [Member] | Operation and Maintenance Agreement [Member] | Cheniere Investments [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	0.60%
Related Party Transaction, Committed Monthly Fee	$ 83,333
SPL [Member] | Management Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	2.40%
Related Party Transaction, Committed Monthly Fee	$ 541,667
CTPL [Member] | Management Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	3.00%

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Related Party Transactions - Other Agreements (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Regasification revenues—affiliate	$ 1,635,000	$ 812,000
Cheniere Investments [Member] | LNG Lease Agreement [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
LNG inventory related party	$ 0		$ 0
SPLNG [Member] | Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Tax Initiative Agreement Term	10 years
SPLNG [Member] | Cooperative Endeavor Agreements [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Aggregate commitment under the Agreement	$ 25,000,000
SPLNG [Member] | Cooperative Endeavor Agreements [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
Advance ad valorem tax payments	24,500,000		$ 22,100,000
SPLNG [Member] | Contracts for Sale and Purchase of Natural Gas and LNG [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
Operating and Maintenance Expense—affiliate	700,000	1,600,000
Regasification revenues—affiliate	900,000	1,300,000
SPLNG [Member] | LNG Terminal Export Agreement [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
Regasification revenues—affiliate	0	0
SPLNG [Member] | Tax Sharing Agreement [Member] | Cheniere [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	0
Tug Services [Member] | Tug Boat Lease Sharing Agreement [Member] | Wholly owned subsidiary of Cheniere [Member]
Related Party Transaction [Line Items]
Regasification revenues—affiliate	600,000	$ 700,000
SPL [Member] | Tax Sharing Agreement [Member] | Cheniere [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	0
CTPL [Member] | Tax Sharing Agreement [Member] | Cheniere [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0

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Net Loss per Common Unit - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
	Apr. 22, 2016	Mar. 31, 2016
Class B Units [Member]
Distribution Made to Limited Partner [Line Items]
Discount upon issuance of Class B units representing beneficial conversion feature		$ 2,130.0
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	$ 0.425

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Net Loss per Common Unit - Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016 USD ($)
Common Units [Member]
Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts [Line Items]
2016	$ (29,565)
2017	(594,426)
Class B Units [Member]
Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts [Line Items]
2016	99,685
2017	2,004,209
Subordinated Units [Member]
Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts [Line Items]
2016	(70,119)
2017	$ (1,409,783)

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Net Loss per Common Unit - Schedule of Net Loss per Unit and Allocation of Distribution (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (74,906)	$ (178,676)
Declared distributions	24,756	24,754
Assumed allocation of undistributed net loss	$ (99,662)	$ (203,430)
Weighted average units outstanding	57,084	57,080
Net loss per unit	$ (0.08)	$ (0.61)
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (21,772)
Declared distributions	24,261	$ 24,259
Assumed allocation of undistributed net loss	(28,967)	(59,125)
Assumed allocation of net loss	$ (4,706)	$ (34,866)
Weighted average units outstanding	57,084	57,080
Net loss per unit	$ (0.08)	$ (0.61)
Class B Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ 0
Declared distributions	0	$ 0
Assumed allocation of undistributed net loss	0	0
Assumed allocation of net loss	$ 0	$ 0
Weighted average units outstanding	145,333	145,333
Net loss per unit	$ 0.00	$ 0.00
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (51,636)
Declared distributions	0	$ 0
Assumed allocation of undistributed net loss	(68,702)	(140,236)
Assumed allocation of net loss	$ (68,702)	$ (140,236)
Weighted average units outstanding	135,384	135,384
Net loss per unit	$ (0.51)	$ (1.04)
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (1,498)
Declared distributions	495	$ 495
Assumed allocation of undistributed net loss	(1,993)	(4,070)
Assumed allocation of net loss	$ (1,498)	$ (3,575)

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized and deferred	$ 23,903	$ 0
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 307,300	$ 147,500