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, 2017

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

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

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

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

As of April 28, 2017, the issuer had 57,109,223 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	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	35
Part II. Other Information
Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 5.	Other Information	36
Item 6.	Exhibits	37
	Signatures	39

i

DEFINITIONS

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

Common Industry and Other Terms

Bcf	billion cubic feet
Bcf/d	billion cubic feet per day
Bcf/yr	billion cubic feet per year
Bcfe	billion cubic feet equivalent
DOE	U.S. Department of Energy
EPC	engineering, procurement and construction
FERC	Federal Energy Regulatory Commission
FTA countries	countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP	generally accepted accounting principles in the United States
Henry Hub	the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu	million British thermal units, an energy unit
mtpa	million tonnes per annum
non-FTA countries	countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC	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, 2017, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to “Cheniere 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 millions, except unit data)

	March 31,		December 31,
	2017		2016
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	756		605
Accounts and other receivables	101		90
Accounts receivable—affiliate	89		99
Advances to affiliate	64		38
Inventory	87		97
Other current assets	30		29
Total current assets	1,127		958
Non-current restricted cash	1,000		—
Property, plant and equipment, net	14,636		14,158
Debt issuance costs, net	80		121
Non-current derivative assets	44		83
Other non-current assets, net	205		222
Total assets	$	17,092	$	15,542
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	35	$	27
Accrued liabilities	426		418
Current debt, net	—		224
Due to affiliates	29		99
Deferred revenue	63		73
Deferred revenue—affiliate	20		1
Derivative liabilities	4		14
Total current liabilities	577		856
Long-term debt, net	16,020		14,209
Non-current deferred revenue	4		5
Non-current derivative liabilities	1		2
Other non-current liabilities—affiliate	25		27
Partners’ equity
Common unitholders’ interest (57.1 million units issued and outstanding at March 31, 2017 and December 31, 2016)	50		130
Class B unitholders’ interest (145.3 million units issued and outstanding at March 31, 2017 and December 31, 2016)	297		62
Subordinated unitholders’ interest (135.4 million units issued and outstanding at March 31, 2017 and December 31, 2016)	107		240
General partner’s interest (2% interest with 6.9 million units issued and outstanding at March 31, 2017 and December 31, 2016)	11		11
Total partners’ equity	465		443
Total liabilities and partners’ equity	$	17,092	$	15,542

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

(unaudited)

	Three Months Ended March 31,
	2017			2016
Revenues
LNG revenues	$	492		$	—
LNG revenues—affiliate	331			—
Regasification revenues	67			65
Regasification revenues—affiliate	1			2
Total revenues	891			67
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	513			4
Operating and maintenance expense	50			18
Operating and maintenance expense—affiliate	18			11
General and administrative expense	3			3
General and administrative expense—affiliate	22			22
Depreciation and amortization expense	66			19
Total operating costs and expenses	672			77
Income (loss) from operations	219			(10		)
Other expense
Interest expense, net of capitalized interest	(130		)	(43		)
Loss on early extinguishment of debt	(42		)	(1		)
Derivative loss, net	—			(21		)
Total other expense	(172		)	(65		)
Net income (loss)	$	47		$	(75	)
Basic and diluted net loss per common unit	$	(0.80	)	$	(0.08	)
Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	57.1			57.1

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

4

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY

(in millions)

(unaudited)

	Common Unitholders’ Interest				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, 2016	57.1	$	130		145.3	$	62	135.4	$	240		6.9	$	11		$	443
Net income	—	14			—	—		—	32			—	1			47
Distributions	—	(24		)	—	—		—	—			—	(1		)	(25		)
Amortization of beneficial conversion feature of Class B units	—	(70		)	—	235		—	(165		)	—	—			—
Balance at March 31, 2017	57.1	$	50		145.3	$	297	135.4	$	107		6.9	$	11		$	465

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

5

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	47		$	(75	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense	66			19
Amortization of debt issuance costs, deferred commitment fees, premium and discount	10			4
Loss on early extinguishment of debt	42			1
Total losses on derivatives, net	39			25
Net cash used for settlement of derivative instruments	(13		)	(3		)
Changes in operating assets and liabilities:
Accounts and other receivables	(11		)	—
Accounts receivable—affiliate	59			1
Advances to affiliate	(41		)	(1		)
Inventory	17			—
Accounts payable and accrued liabilities	(38		)	34
Due to affiliates	(68		)	(8		)
Deferred revenue	(11		)	(1		)
Other, net	1			(2		)
Other, net—affiliate	16			—
Net cash provided by (used in) operating activities	115			(6		)
Cash flows from investing activities
Property, plant and equipment, net	(524		)	(715		)
Other	—			(34		)
Net cash used in investing activities	(524		)	(749		)
Cash flows from financing activities
Proceeds from issuances of debt	2,314			1,235
Repayments of debt	(703		)	(415		)
Debt issuance and deferred financing costs	(26		)	(48		)
Distributions to owners	(25		)	(25		)
Net cash provided by financing activities	1,560			747
Net increase (decrease) in cash, cash equivalents and restricted cash	1,151			(8		)
Cash, cash equivalents and restricted cash—beginning of period	605			434
Cash, cash equivalents and restricted cash—end of period	$	1,756		$	426

Balances per Consolidated Balance Sheets:

	March 31,
	2017		2016
Cash and cash equivalents	$	—	$	10
Restricted cash	756		402
Non-current restricted cash	1,000		14
Total cash, cash equivalents and restricted cash	$	1,756	$	426

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

6

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminallocated in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 3 have commenced commercial operations, Train 4 is undergoing commissioning, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. We also own and operate regasification facilities at the Sabine Pass LNG terminal through SPLNG and own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL.

In the second quarter of 2016, we started production at the Liquefaction Project and began recognizing LNG revenues, which include fees that are received pursuant to our SPAs. During the three months ended March 31, 2017, we received 94% of our net LNG revenues from two SPA customers.

We also recognize regasification revenues, which 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 (“Tug Services”), a wholly owned subsidiary of SPLNG. Substantially all of our regasification revenues are received from our two long-term TUA customers.

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere Partners have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2016. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

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

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

NOTE 2—UNITHOLDERS’ EQUITY

The common units, 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 (“IDRs”), which allow the general partner to receive a higher percentage of quarterly distributions of

7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 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 Liquefaction Project. In May 2013, Cheniere purchased an additional 12.0 millionClass B units for consideration of $180 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 1.97 and 1.92, respectively, as of March 31, 2017. Since Train 3 of the Liquefaction Project achieved substantial completion in March 2017, the Class B units will mandatorily convert into common units on the first business day following the record date of our first distribution with respect to the quarter ended June 30, 2017 if not voluntarily converted by Blackstone CQP Holdco earlier.

NOTE 3—RESTRICTED CASH

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

	March 31,		December 31,
	2017		2016
Current restricted cash
Liquefaction Project	$	531	$	358
CQP and cash held by guarantor subsidiaries	225		247
Total current restricted cash	$	756	$	605
Non-current restricted cash
Liquefaction Project	$	1,000	$	—

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

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

	March 31,		December 31,
	2017		2016
SPL trade receivable	$	92	$	88
Other accounts receivable	9		2
Total accounts and other receivables	$	101	$	90

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of SPL’s debt holders, SPL is required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. As of March 31, 2017 and December 31, 2016, substantially all of our trade receivable balance was from two SPA customers.

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 5—INVENTORY

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

	March 31,		December 31,
	2017		2016
Natural gas	$	19	$	15
LNG	22		45
Materials and other	46		37
Total inventory	$	87	$	97

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2017			2016
LNG terminal costs
LNG terminal	$	10,420		$	7,976
LNG terminal construction-in-process	4,826			6,728
Accumulated depreciation	(616		)	(553		)
Total LNG terminal costs, net	14,630			14,151
Fixed assets
Fixed assets	20			20
Accumulated depreciation	(14		)	(13		)
Total fixed assets, net	6			7
Property, plant and equipment, net	$	14,636		$	14,158

Depreciation expense during the three months ended March 31, 2017 and 2016 was $64 million and $18 million, respectively.

During the three months ended March 31, 2017 and 2016, we realized offsets to LNG terminal costs of $124 million and $14 million, respectively, that were related to the sale of commissioning cargoes because these amounts were earned prior to the start of commercial operations, during the testing phase for the construction of the Liquefaction Project.

NOTE 7—DERIVATIVE INSTRUMENTS

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

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

• commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).

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.

9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Fair Value Measurements as of
	March 31, 2017									December 31, 2016
	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
SPL Interest Rate Derivatives liability	$	—		$	—	$	—	$	—	$	—		$	(6	)	$	—	$	(6	)
CQP Interest Rate Derivatives asset	—			16		—		16		—			13			—		13
Liquefaction Supply Derivatives asset (liability)	(2		)	—		41		39		(4		)	(2		)	79		73

There have been no changes to our evaluation of and accounting for our derivative positions designated as Level 1 during the three months ended March 31, 2017. See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016 for additional information.

We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.

The 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 supply contracts as of the reporting date.

The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a 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 supply contracts. As of March 31, 2017 and December 31, 2016, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow.

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2017:

	Net Fair Value Asset (in millions)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$41	Income Approach	Basis Spread	$(0.345) - $0.081

10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table (in millions) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016
Balance, beginning of period	$	79		$	32
Realized and mark-to-market losses:
Included in cost of sales (1)	(41		)	(2		)
Purchases and settlements:
Purchases	4			—
Settlements (1)	(1		)	—
Balance, end of period	$	41		$	30
Change in unrealized gains relating to instruments still held at end of period	$	(41	)	$	(2	)

(1) Does not include the decrease in fair value of $1 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.  Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

SPL had entered into interest rate swaps (“SPL Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “2015 SPL Credit Facilities”). In March 2017, SPL settled the SPL Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 10—Debt.

During the three months ended March 31, 2017 there were no changes to the terms of our interest rate swaps (“CQP Interest Rate Derivatives”) entered into to hedge a portion of the variable interest payments on the credit facilities we entered into in February 2016 (the “2016 CQP Credit Facilities”). See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016 for additional information.

As of March 31, 2017, we had the following Interest Rate Derivatives outstanding:

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

11

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	March 31, 2017						December 31, 2016
	SPL Interest Rate Derivatives		CQP Interest Rate Derivatives		Total		SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			Total
Balance Sheet Location
Non-current derivative assets	$	—	$	16	$	16	$	—		$	16		$	16
Derivative liabilities	—		—		—		(4		)	(3		)	(7		)
Non-current derivative liabilities	—		—		—		(2		)	—			(2		)
Total derivative liabilities	—		—		—		(6		)	(3		)	(9		)
Derivative asset (liability), net	$	—	$	16	$	16	$	(6	)	$	13		$	7

The following table (in millions) 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, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016
SPL Interest Rate Derivatives loss	$	(2	)	$	(11	)
CQP Interest Rate Derivatives gain (loss)	2			(10		)

Liquefaction Supply Derivatives

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

		Fair Value Measurements as of (1)
	Balance Sheet Location	March 31, 2017			December 31, 2016
Liquefaction Supply Derivatives	Other current assets	$	16		$	13
Liquefaction Supply Derivatives	Non-current derivative assets	28			67
Liquefaction Supply Derivatives	Derivative liabilities	(4		)	(7		)
Liquefaction Supply Derivatives	Non-current derivative liabilities	(1		)	—

(1) Does not include collateral of $5 million and $6 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016, respectively.

SPL had secured up to approximately 2,051 millionMMBtu and 1,994 million MMBtu of natural gas feedstock through natural gas supply contracts as of March 31, 2017 and December 31, 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,214 millionMMBtu and 1,117 millionMMBtu as of March 31, 2017 and December 31, 2016, respectively.

The following table (in millions) shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the three months ended March 31, 2017 and 2016:

		Three Months Ended March 31,
	Statement of Operations Location (1)	2017		2016
Liquefaction Supply Derivatives loss (2)	Cost of sales	$	39	$	4

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2017
CQP Interest Rate Derivatives	$	17		$	(1	)	$	16
Liquefaction Supply Derivatives	48			(4		)	44
Liquefaction Supply Derivatives	2			(7		)	(5		)
As of December 31, 2016
SPL Interest Rate Derivatives	$	(6	)	$	—		$	(6	)
CQP Interest Rate Derivatives	16			—			16
CQP Interest Rate Derivatives	(3		)	—			(3		)
Liquefaction Supply Derivatives	82			(2		)	80
Liquefaction Supply Derivatives	(11		)	4			(7		)

NOTE 8—OTHER NON-CURRENT ASSETS

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

	March 31,		December 31,
	2017		2016
Advances made under EPC and non-EPC contracts	$	20	$	23
Advances made to municipalities for water system enhancements	95		95
Advances and other asset conveyances to third parties to support LNG terminals	30		31
Tax-related payments and receivables	25		28
Information technology service assets	26		27
Other	9		18
Total other non-current assets, net	$	205	$	222

NOTE 9—ACCRUED LIABILITIES

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

	March 31,		December 31,
	2017		2016
Interest costs and related debt fees	$	147	$	205
Sabine Pass LNG terminal and related pipeline costs	275		211
Other accrued liabilities	4		2
Total accrued liabilities	$	426	$	418

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—DEBT

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

	March 31,			December 31,
	2017			2016
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7 and $7	$	2,007		$	2,007
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $6	1,505			1,506
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero	1,349			—
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			—
2015 SPL Credit Facilities	—			314
Cheniere Partners
2016 CQP Credit Facilities	2,560			2,560
Unamortized debt issuance costs	(201		)	(178		)
Total long-term debt, net	16,020			14,209
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			224
Total debt, net	$	16,020		$	14,433

2017 Debt Issuances and Redemptions

Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes were used to repay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.

In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the three months ended March 31, 2017.

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

and enter into certain LNG sales contracts. The 2028 SPL Senior Notes are governed by the same common indenture as the other senior notes, which also contains customary terms and events of default, covenants and redemption terms.

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

In connection with the issuance of the 2028 SPL Senior Notes, SPL entered into a registration rights agreement (the “SPL Registration Rights Agreement”). Under the terms of the SPL Registration Rights Agreement, SPL has agreed, and any future guarantors will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2028 SPL Senior Notes for a like aggregate principal amount of debt securities of SPL with terms identical in all material respects to the 2028 SPL Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after March 6, 2017. Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2028 SPL Senior Notes. SPL will be obligated to pay additional interest on the 2028 SPL Senior Notes if it fails to comply with its obligation to register them within the specified time period.

Credit Facilities

Below is a summary (in millions) of our credit facilities outstanding as of March 31, 2017:

	SPL Working Capital Facility		2016 CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Outstanding balance	—		2,560
Letters of credit issued	377		50
Available commitment	$	823	$	190
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020, 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 millions):

	Three Months Ended March 31,
	2017			2016
Total interest cost	$	211		$	192
Capitalized interest	(81		)	(149		)
Total interest expense, net	$	130		$	43

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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 millions) shows the carrying amount and estimated fair value of our debt:

	March 31, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	12,861	$	13,807	$	11,513	$	12,309
2037 SPL Senior Notes (2)	800		826		—		—
Credit facilities (3)	2,560		2,560		3,098		3,098

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

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

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. 

NOTE 11—RELATED PARTY TRANSACTIONS

Below is a summary (in millions) of our related party transactions as reported on our Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017		2016
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	331	$	—
Regasification revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		1
Tug Boat Lease Sharing Agreement	1		1
Total regasification revenues—affiliate	1		2
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		1
Services Agreements	18		10
Total operating and maintenance expense—affiliate	18		11
General and administrative expense—affiliate
Services Agreements	22		22

LNG Terminal Capacity Agreements

Terminal Use Agreements

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 (the “TUA Fees”), continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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 pay the TUA Fees required by the TUA to SPLNG. However, the revenue earned by SPLNG from the TUA Fees and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our Financial Statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA.

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing during the three months ended March 31, 2017 and 2016, 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.

Cheniere Marketing Master SPA

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

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, SPL has executed a confirmation 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

SPL has entered into an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell certain quantities of pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC, one of SPL’s SPA customers. SPL pays a fee to Cheniere Marketing for marketing and transportation, which is based on volume sold under this agreement.

Services Agreements

As of March 31, 2017 and December 31, 2016, we had $64 million and $38 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under the services agreements described below are recorded in general and administrative expense—affiliate.

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 $3 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

SPLNG MSA

SPLNG has 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 pays 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 SPL’s 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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

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 $25 million in order to aid in their reconstruction efforts following Hurricane Rita, which SPLNG fulfilled in the first quarter of 2016. 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 both March 31, 2017 and December 31, 2016, we had $25 million 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.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Tug Services 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.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have 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, 2017 and 2016.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

State Tax Sharing Agreements

SPLNG has 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 calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

SPL has 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.

CTPL has 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 12—NET LOSS PER COMMON UNIT

Net 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 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 21, 2017, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on May 15, 2017 to unitholders of record as of May 2, 2017 for the period from January 1, 2017 to March 31, 2017.

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 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 through the mandatory conversion date of August 2017 for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units. 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, 2017 and 2016.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Based on the capital structure as of March 31, 2017, the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature is as follows in 2017 (in millions):

Common Units	Class B Units	Subordinated Units
$(594)	$2,004	$(1,410)

Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss). 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 millions, except per unit data) provides a reconciliation of net income (loss) and the allocation of net income (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, 2017
Net income	$	47
Declared distributions	25			24			—		—			1
Amortization of beneficial conversion feature of Class B units	—			(70		)	235		(165		)	—
Assumed allocation of undistributed net income	$	22		—			—		22			—
Assumed allocation of net income (loss)				$	(46	)	$	235	$	(143	)	$	1
Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.80	)			$	(1.06	)
Three Months Ended March 31, 2016
Net loss	$	(75	)
Declared distributions	25			24			—		—			1
Assumed allocation of undistributed net loss	$	(100	)	(29		)	—		(69		)	(2		)
Assumed allocation of net loss				$	(5	)	$	—	$	(69	)	$	(1	)
Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.08	)			$	(0.51	)

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2017		2016
Cash paid during the period for interest, net of amounts capitalized	$	175	$	24

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $316 million and $307 million as of March 31, 2017 and 2016, respectively.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 14—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, 2017:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we plan to adopt this standard using the full retrospective approach and we do not currently anticipate that the adoption will have a material impact upon our revenues. The Financial Accounting Standards Board has issued and may issue in the future amendments and interpretive guidance which may cause our evaluation to change. Furthermore, we routinely enter into new contracts and we cannot predict with certainty whether the accounting for any future contract under the new standard would result in a significant change from existing guidance. Because this assessment is preliminary and the accounting for revenue recognition is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact that recognizing fulfillment costs as assets will have on our Consolidated Financial Statements.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, whether we will elect to early adopt this standard or which, if any, practical expedients we will elect upon transition.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.

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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

• statements regarding our ability to pay distributions to our unitholders; 

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

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

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

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

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

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

• statements regarding 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, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;

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

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

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

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

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, 2016. 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. Our vision is to be recognized as the premier global LNG company and provide a reliable, competitive and integrated source of LNG to our customers while creating a safe, productive and rewarding work environment for our employees. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG. Through our wholly owned subsidiary, SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminallocated in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 3 have commenced commercial operations, Train 4 is undergoing commissioning, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa of LNG. Through our wholly owned subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which 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 also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines through our wholly owned subsidiary, CTPL.

Overview of Significant Events

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

Strategic

• Year to date, LNG from the Liquefaction Project has been delivered to 6 new countries. As of April 2017, LNG from the Liquefaction Project had reached 20 of the 39 LNG importing countries around the world.

Operational

• 43 LNG cargoes (154 million MMBtu) were loaded from the Liquefaction Project in the first quarter of 2017, and in early April 2017 we reached the milestone of 100 cumulative LNG cargoes exported from the Liquefaction Project.

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

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• Commissioning activities for Train 4 of the Liquefaction Project began in March 2017.

Financial

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

• In January 2017, Fitch Ratings assigned SPL’s senior secured debt an investment grade rating of BBB-.

Liquidity and Capital Resources

The following table (in millions) provides a summary of our liquidity position at March 31, 2017 and December 31, 2016:

	March 31,		December 31,
	2017		2016
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the following purposes:
Liquefaction Project	1,531		358
CQP and cash held by guarantor subsidiaries	225		247
Available commitments under the following credit facilities:
2015 SPL Credit Facilities	—		1,642
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	823		653
$2.8 billion 2016 CQP Credit Facilities (“2016 CQP Credit Facilities”)	190		195

For additional information regarding our debt agreements, see Note 10—Debt of our Notes to Consolidated Financial Statements.

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 million CTPL tranche term loan that was used to prepay the $400 million term loan facility (the “CTPL Term Loan”) in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that was used to repay and redeem the approximately $2.1 billion of the senior notes previously issued by SPLNG in November 2016, (3) a $125 million DSR Facility that may be used to satisfy a six-month debt service reserve requirement and (4) a $115 million revolving credit facility that may be used for general business purposes. We had $2.6 billion of outstanding borrowings under the 2016 CQP Credit Facilities as of both March 31, 2017 and December 31, 2016, and we had $190 million and $195 million of available commitments and $50 million and $45 million aggregate amount of issued letters of credit as of March 31, 2017 and December 31, 2016, respectively.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit 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 SPL and certain of our subsidiaries owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

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See Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016 for additional information regarding the 2016 CQP Credit Facilities.

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. The following table summarizes the overall project status of the Liquefaction Project as of March 31, 2017:

	Trains 1 & 2		Trains 3 & 4		Train 5
Overall project completion percentage	100%		97.3%		63.1%
Completion percentage of:
Engineering	100%		100%		99.2%
Procurement	100%		100%		93.0%
Subcontract work	100%		84.3%		46.0%
Construction	100%		96.7%		19.2%
Date of expected substantial completion	Train 1	Operational	Train 3	Operational	Train 5	2H 2019
	Train 2	Operational	Train 4	2H 2017

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

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

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

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

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

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

In January 2016, the DOE issued an order authorizing SPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing on January 15, 2016, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports to non-FTA countries under this order, when combined with exports to non-FTA countries under the orders related to Trains 1 through 4 above, may not exceed 1,006 Bcf/yr).

A party to the proceedings requested rehearings of the orders above related to the export of 803 Bcf/yr, 203 Bcf/yr and 503.3 Bcf/yr to non-FTA countries. The DOE issued orders denying rehearing of the orders. The same party petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review (1) the 203 Bcf/yr order to non-FTA countries and the order denying the request for rehearing of the same and (2) the 503.3 Bcf/yr order to non-FTA countries and the order denying the request for rehearing of the same. Both appeals are pending.

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Customers

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

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

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

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing volatility in natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of March 31, 2017, SPL has secured up to approximately 2,051 millionMMBtu of natural gas feedstock through long-term and short-term natural gas supply contracts.

Construction

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

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, $3.9 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through March 31, 2017. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.5 billion and $18.5 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Train 6

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

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal.  Each of Total Gas & Power North America, Inc. (“Total”) and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity

28

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 upon substantial completion of Train 3, SPL commenced gaining access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.

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

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 5 of the Liquefaction Project will be financed through borrowings and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the SPL Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. SPL began generating cash flows from operations from the Liquefaction Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2 and 3 subsequently achieved substantial completion in September 2016 and March 2017, respectively. Additionally, during the three months ended March 31, 2017 and 2016, we realized offsets to LNG terminal costs of $124 million and $14 million, respectively, that were related to the sale of commissioning cargoes because these amounts were earned prior to the start of commercial operations, during the testing phase for the construction of those Trains of the Liquefaction Project.

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

	March 31,		December 31,
	2017		2016
Senior notes (1)	$	13,650	$	11,500
Credit facilities outstanding balance (2)	2,560		3,097
Letters of credit issued (3)	377		324
Available commitments under credit facilities (3)	823		2,295
Total capital resources from borrowings and available commitments	$	17,410	$	17,216

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

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

(3) Includes 2015 SPL Credit Facilities and SPL Working Capital Facility. Does not include the letters of credit issued or available commitments under the 2016 CQP Credit Facilities, which are not specifically for the Liquefaction Project.

For additional information regarding our debt agreements related to the Sabine Pass LNG Terminal, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016.

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Senior Secured Notes

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

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

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

2015 SPL Credit Facilities

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

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction 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, 2017 and December 31, 2016, SPL had $823 million and $653 million of available commitments, $377 million and $324 million aggregate amount of issued letters of credit and zero and $224 million of loans outstanding under the SPL Working Capital Facility, respectively.

The SPL Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. Loans deemed made in connection with a draw upon a letter of credit have a term of up to one year. 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.

30

Sources and Uses of Cash

The following table (in millions) summarizes the sources and uses of our cash, cash equivalents and restricted cash for the three months ended March 31, 2017 and 2016. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.

	Three Months Ended March 31,
	2017			2016
Operating cash flows	$	115		$	(6	)
Investing cash flows	(524		)	(749		)
Financing cash flows	1,560			747
Net increase (decrease) in cash, cash equivalents and restricted cash	1,151			(8		)
Cash, cash equivalents and restricted cash—beginning of period	605			434
Cash, cash equivalents and restricted cash—end of period	$	1,756		$	426

Operating Cash Flows

Our operating cash flows increased from outflows of $6 million during the three months ended March 31, 2016 to inflows of $115 million during the three months ended March 31, 2017. The $121 million increase in operating cash inflows in 2017 compared to 2016 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the commencement of operations of Trains 1, 2 and 3 of the Liquefaction Project in May 2016, September 2016 and March 2017, respectively.

Investing Cash Flows

Investing cash outflows during the three months ended March 31, 2017 and 2016 were $524 million and $749 million respectively, and were primarily used to fund the construction costs for Trains 1 through 5 of the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, during the three months ended March 31, 2016, we used $34 million primarily for payments made pursuant to the information technology services agreement for capital assets purchased on our behalf.

Financing Cash Flows

Financing cash inflows during the three months ended March 31, 2017 were $1.6 billion, primarily as a result of:

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

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

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

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

• $25 million of distributions to unitholders.

Financing cash inflows during the three months ended March 31, 2016 were $747 million, primarily as a result of:

• entering into the 2016 CQP Credit Facilities and borrowing $450 million to prepay the $400 million CTPL Term Loan;

• $660 million of borrowings under the 2015 SPL Credit Facilities;

• $125 million of borrowings and a $15 million repayment made under the SPL Working Capital Facility;

• $48 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and

• $25 million of distributions to unitholders.

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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. On a quarterly basis, we declare and pay a $0.425 distribution per common unit and the related distribution to our general partner of $24 million and $0.5 million, respectively.

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. 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 1.97 and 1.92, respectively, as of March 31, 2017. Since Train 3 of the Liquefaction Project achieved substantial completion in March 2017, the Class B units will mandatorily convert into common units on the first business day following the record date of our first distribution with respect to the quarter ended June 30, 2017 if not voluntarily converted by Blackstone CQP Holdco earlier.

Results of Operations

Our consolidated net income was $47 million, or $0.80 loss per share (basic and diluted), in the three months ended March 31, 2017, compared to a net loss of $75 million, or $0.08 per share (basic and diluted), in the three months ended March 31, 2016. This $122 million increase in net income in 2017 was primarily a result of increased income from operations and decreased derivative loss, net, which were partially offset by increased interest expense, net of amounts capitalized, and loss on early extinguishment of debt.

Revenues

	Three Months Ended March 31,
(in millions)	2017		2016		Change
LNG revenues	$	492	$	—	$	492
LNG revenues—affiliate	331		—		331
Regasification revenues	67		65		2
Regasification revenues—affiliate	1		2		(1		)
Total revenues	$	891	$	67	$	824

We began recognizing LNG revenues from the Liquefaction Project following the substantial completion and the commencement of operating activities of Train 1 in May 2016. Trains 2 and 3 subsequently achieved substantial completion in September 2016 and March 2017, respectively. Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process because these amounts are earned during the testing phase for the construction of those Trains of the Liquefaction Project. During the three months ended March 31, 2017 and 2016, we realized offsets to LNG terminal costs of $124 million and $14 million, respectively, that were related to the sale of commissioning cargoes. During the three months ended March 31, 2017, we recognized revenues related to the sale of 128 million MMBtu of LNG and recognized an offset to LNG terminal costs related to the sale of 18 million MMBtu of LNG. An additional 8 million MMBtu of commissioning LNG was loaded during the current quarter but was in transit as of March 31, 2017. As additional Trains become operational, we expect our LNG revenues to increase in the future.

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Operating costs and expenses

	Three Months Ended March 31,
(in millions)	2017		2016		Change
Cost of sales	$	513	$	4	$	509
Operating and maintenance expense	50		18		32
Operating and maintenance expense—affiliate	18		11		7
General and administrative expense	3		3		—
General and administrative expense—affiliate	22		22		—
Depreciation and amortization expense	66		19		47
Total operating costs and expenses	$	672	$	77	$	595

Our total operating costs and expenses increased $595 million during the three months ended March 31, 2017 compared to the three months ended March 31, 2016, primarily as a result of the commencement of operations of at the Liquefaction Project in May 2016 upon the substantial completion of Train 1, followed by the substantial completion of Trains 2 and 3 in September 2016 and March 2017, respectively.

Cost of sales increased during the three months ended March 31, 2017 compared to the three months ended March 31, 2016 as a result of the commencement of operations at the Liquefaction Project. Cost of sales includes costs incurred directly for the production and delivery 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.

Operating and maintenance expense (including affiliate amounts) increased during the three months ended March 31, 2017 as a result of the commencement of operations at the Liquefaction Project. Operating and maintenance expense 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. Depreciation and amortization expense increased during the three months ended March 31, 2017 as we began depreciation of our assets related to Trains 1 through 3 of the Liquefaction Project upon reaching substantial completion.

As additional Trains become operational, we expect our operating costs and expenses to increase in the future, including higher depreciation and amortization expense as the related assets begin to be depreciated upon reaching substantial completion.

Other expense

	Three Months Ended March 31,
(in millions)	2017		2016		Change
Interest expense, net of capitalized interest	$	130	$	43	$	87
Loss on early extinguishment of debt	42		1		41
Derivative loss, net	—		21		(21		)
Total other expense	$	172	$	65	$	107

Interest expense, net of capitalized interest, increased $87 million in the three months ended March 31, 2017 compared to the three months ended March 31, 2016, primarily as a result of an increase in our indebtedness outstanding (before premium, discount and unamortized debt issuance costs), from $12.7 billion as of March 31, 2016 to $16.2 billion as of March 31, 2017, and a decrease in the portion of total interest costs that could be capitalized as Trains 1 through 3 of the Liquefaction Project were no longer in construction. For the three months ended March 31, 2017, we incurred $211 million of total interest cost, of which we capitalized $81 million which was directly related to the construction of the Liquefaction Project. For the three months ended March 31, 2016, we incurred $192 million of total interest cost, of which we capitalized $149 million, which was directly related to the construction of the Liquefaction Project.

Loss on early extinguishment of debt increased $41 million in the three months ended March 31, 2017, as compared to the three months ended March 31, 2016. Loss on early extinguishment of debt recognized during the three months ended March 31,

33

2017 was attributable to the write-off of debt issuance costs upon termination of the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities in connection with the issuance of the 2028 SPL Senior Notes.

Derivative loss, net decreased $21 million in the three months ended March 31, 2017, as compared to the three months ended March 31, 2016. During the three months ended March 31, 2017, the gain attributable to a relative increase in the long-term forward LIBOR curve during the period was offset by the $7 million loss recognized upon the termination of interest rate swaps associated with approximately $1.6 billion of commitments that were terminated under the 2015 SPL Credit Facilities. The net loss recognized during the three months ended March 31, 2016 was due to a relative decrease in the long-term forward LIBOR curve during the period.

Off-Balance Sheet Arrangements

As of March 31, 2017, 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, 2016.

Recent Accounting Standards

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Marketing and Trading Commodity Price Risk

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

	March 31, 2017				December 31, 2016
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	39	$	2	$	73	$	6

See Note 7—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(“SPL Interest Rate Derivatives”), the 2016 CQP Credit Facilities (“CQP Interest Rate Derivatives” and collectively, with the SPL Interest Rate Derivatives, the “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 terms of the Interest Rate Derivatives as follows (in millions):

	March 31, 2017				December 31, 2016
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
SPL Interest Rate Derivatives	$	—	$	—	$	(6	)	$	2
CQP Interest Rate Derivatives	16		6		13			6

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ITEM 4. CONTROLS AND PROCEDURES

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

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

35

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. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the year ended December 31, 2016.

ITEM 1A. RISK FACTORS 

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2016.

ITEM 5. OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the quarter ended March 31, 2017, 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. During the quarter ended March 31, 2017, we did not engage in any transactions with Iran or with persons or entities related to Iran.

36

ITEM 6. EXHIBITS

Exhibit No.	Description
3.1	Fourth Amended and Restated Agreement of Limited Partnership of Cheniere Energy Partners, L.P. (Incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on February 21, 2017)
4.1	Tenth Supplemental Indenture, dated as of March 6, 2017, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 6, 2017)
4.2	Form of 4.200% Senior Secured Note due 2028 (Included as Exhibit A-1 to Exhibit 4.1 above)
4.3	Indenture, dated as of February 24, 2017, between Sabine Pass Liquefaction, LLC, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on February 27, 2017)
4.4	Form of 5.00% Senior Secured Note due 2037 (Included as Exhibit A-1 to Exhibit 4.3 above)
10.1	Second Omnibus Amendment and Waiver, dated as of January 20, 2017, to the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, the representatives and agents from time to time parties thereto, and Société Générale, as the Common Security Trustee and Intercreditor Agent (Incorporated by reference to Exhibit 10.73 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-215882), filed on February 3, 2017)
10.2	Amendment to the Common Terms Agreement, dated January 20, 2017, to the Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, the representatives and agents from time to time parties thereto, and Société Générale, as the Common Security Trustee and Intercreditor Agent (Incorporated by reference to Exhibit 10.74 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-215882), filed on February 3, 2017)
10.3	Registration Rights Agreement, dated as of March 6, 2017, between Sabine Pass Liquefaction, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated (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 6, 2017)
10.4	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-00056 Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum Closeout, dated February 28, 2017 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.77 to Amendment No. 1 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-215882), filed on March 31, 2017)
10.5	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00033 Instrument Air Tie-In Point Location Change, dated January 25, 2017 and (ii) the Change Order CO-00034 Additional Owner Site Office Provisional Sum Closeout, dated January 25, 2017 (Incorporated by reference to Exhibit 10.76 to Amendment No. 1 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-215882), filed on March 31, 2017)
10.6	Amendment of LNG Sale and Purchase Agreement (FOB), dated January 12, 2017, between Sabine Pass Liquefaction, LLC (Seller) and Gas Natural Fenosa LNG GOM, Limited (assignee of Gas Natural Aprovisionamientos SDG S.A.) (Buyer) (Incorporated by reference to Exhibit 10.3 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-215882), filed on February 3, 2017)
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
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

37

Exhibit No.	Description
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.
**	Furnished herewith.

38

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 3, 2017	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	May 3, 2017	By:	/s/ Leonard Travis
			Leonard Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

39

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

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

I, Jack A. Fusco, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Cheniere Energy Partners, L.P.;

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

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

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

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

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

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

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

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

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

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

Date: May 3, 2017

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

I, Michael J. Wortley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Cheniere Energy Partners, L.P.;

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

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

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

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

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

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

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

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

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

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

Date: May 3, 2017

/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, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: May 3, 2017

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended March 31, 2017, 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 3, 2017

/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, 2017	Apr. 28, 2017
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, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Common Units [Member]
Entity Information [Line Items]
Entity Units, Units Outstanding		57,109,223
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

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Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 0	$ 0
Restricted cash	756	605
Accounts and other receivables	101	90
Accounts receivable—affiliate	89	99
Advances to affiliate	64	38
Inventory	87	97
Other current assets	30	29
Total current assets	1,127	958
Non-current restricted cash	1,000	0
Property, plant and equipment, net	14,636	14,158
Debt issuance costs, net	80	121
Non-current derivative assets	44	83
Other non-current assets, net	205	222
Total assets	17,092	15,542
Current liabilities
Accounts payable	35	27
Accrued liabilities	426	418
Current debt, net	0	224
Due to affiliates	29	99
Deferred revenue	63	73
Deferred revenue—affiliate	20	1
Derivative liabilities	4	14
Total current liabilities	577	856
Long-term debt, net	16,020	14,209
Non-current deferred revenue	4	5
Non-current derivative liabilities	1	2
Other non-current liabilities—affiliate	25	27
Partners’ equity
Common unitholders’ interest (57.1 million units issued and outstanding at March 31, 2017 and December 31, 2016)	50	130
Class B unitholders’ interest (145.3 million units issued and outstanding at March 31, 2017 and December 31, 2016)	297	62
Subordinated unitholders’ interest (135.4 million units issued and outstanding at March 31, 2017 and December 31, 2016)	107	240
General partner’s interest (2% interest with 6.9 million units issued and outstanding at March 31, 2017 and December 31, 2016)	11	11
Total partners’ equity	465	443
Total liabilities and partners’ equity	$ 17,092	$ 15,542

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Consolidated Balance Sheets Parentheticals - shares shares in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
General Partner Ownership Interest Percentage	2.00%	2.00%
General Partners' Capital Account, Units Issued	6.9	6.9
General partner units outstanding	6.9	6.9
Common Units [Member]
Limited Partners' Capital Account, Units Issued	57.1	57.1
Partnership unitholders units outstanding	57.1	57.1
Class B Units [Member]
Limited Partners' Capital Account, Units Issued	145.3	145.3
Partnership unitholders units outstanding	145.3	145.3
Subordinated Units [Member]
Limited Partners' Capital Account, Units Issued	135.4	135.4
Partnership unitholders units outstanding	135.4	135.4

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Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues
LNG revenues	$ 492	$ 0
LNG revenues—affiliate	331	0
Regasification revenues	67	65
Regasification revenues—affiliate	1	2
Total revenues	891	67
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	513	4
Operating and maintenance expense	50	18
Operating and maintenance expense—affiliate	18	11
General and administrative expense	3	3
General and administrative expense—affiliate	22	22
Depreciation and amortization expense	66	19
Total operating costs and expenses	672	77
Income (loss) from operations	219	(10)
Other expense
Interest expense, net of capitalized interest	(130)	(43)
Loss on early extinguishment of debt	(42)	(1)
Derivative loss, net	0	(21)
Total other expense	(172)	(65)
Net income (loss)	$ 47	$ (75)
Basic and diluted net loss per common unit	$ (0.80)	$ (0.08)
Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	57.1	57.1

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Consolidated Statement of Partners' Equity - 3 months ended Mar. 31, 2017 - USD ($) shares in Millions, $ in Millions	Total	Common Units [Member]	Class B Units [Member]	Subordinated Units [Member]	General Partner [Member]
Units, Outstanding, beginning of period at Dec. 31, 2016		57.1	145.3	135.4
Partners' equity, beginning of period at Dec. 31, 2016	$ 443	$ 130	$ 62	$ 240	$ 11
General partner units, Outstanding, beginning of period at Dec. 31, 2016	6.9				6.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 47	14	0	32	$ 1
Distributions	(25)	(24)	0	0	(1)
Amortization of beneficial conversion feature of Class B units	0	$ (70)	$ 235	$ (165)	0
Units, Outstanding, end of period at Mar. 31, 2017		57.1	145.3	135.4
Partners' equity, end of period at Mar. 31, 2017	$ 465	$ 50	$ 297	$ 107	$ 11
General partner units, Outstanding, end of period at Mar. 31, 2017	6.9				6.9

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities
Net income (loss)	$ 47	$ (75)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense	66	19
Amortization of debt issuance costs, deferred commitment fees, premium and discount	10	4
Loss on early extinguishment of debt	42	1
Total losses on derivatives, net	39	25
Net cash used for settlement of derivative instruments	(13)	(3)
Changes in operating assets and liabilities:
Accounts and other receivables	(11)	0
Accounts receivable—affiliate	59	1
Advances to affiliate	(41)	(1)
Inventory	17	0
Accounts payable and accrued liabilities	(38)	34
Due to affiliates	(68)	(8)
Deferred revenue	(11)	(1)
Other, net	1	(2)
Other, net—affiliate	16	0
Net cash provided by (used in) operating activities	115	(6)
Cash flows from investing activities
Property, plant and equipment, net	(524)	(715)
Other	0	(34)
Net cash used in investing activities	(524)	(749)
Cash flows from financing activities
Proceeds from issuances of debt	2,314	1,235
Repayments of debt	(703)	(415)
Debt issuance and deferred financing costs	(26)	(48)
Distributions to owners	(25)	(25)
Net cash provided by financing activities	1,560	747
Net increase (decrease) in cash, cash equivalents and restricted cash	1,151	(8)
Cash, cash equivalents and restricted cash—beginning of period	605	434
Cash, cash equivalents and restricted cash—end of period	1,756	426
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	0	10
Restricted cash	756	402
Non-current restricted cash	1,000	14
Total cash, cash equivalents and restricted cash	$ 1,756	$ 426

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Nature of Operations and Basis of Presentation

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminallocated in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 3 have commenced commercial operations, Train 4 is undergoing commissioning, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. We also own and operate regasification facilities at the Sabine Pass LNG terminal through SPLNG and own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL.

In the second quarter of 2016, we started production at the Liquefaction Project and began recognizing LNG revenues, which include fees that are received pursuant to our SPAs. During the three months ended March 31, 2017, we received 94% of our net LNG revenues from two SPA customers.

We also recognize regasification revenues, which 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 (“Tug Services”), a wholly owned subsidiary of SPLNG. Substantially all of our regasification revenues are received from our two long-term TUA customers.

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere Partners have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2016. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

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

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

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Unitholders' Equity

3 Months Ended

Mar. 31, 2017

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 (“IDRs”), which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met. 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 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 Liquefaction Project. In May 2013, Cheniere purchased an additional 12.0 millionClass B units for consideration of $180 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 1.97 and 1.92, respectively, as of March 31, 2017. Since Train 3 of the Liquefaction Project achieved substantial completion in March 2017, the Class B units will mandatorily convert into common units on the first business day following the record date of our first distribution with respect to the quarter ended June 30, 2017 if not voluntarily converted by Blackstone CQP Holdco earlier.

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Restricted Cash

3 Months Ended

Mar. 31, 2017

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. As of March 31, 2017 and December 31, 2016, restricted cash consisted of the following (in millions):

	March 31,		December 31,
	2017		2016
Current restricted cash
Liquefaction Project	$	531	$	358
CQP and cash held by guarantor subsidiaries	225		247
Total current restricted cash	$	756	$	605
Non-current restricted cash
Liquefaction Project	$	1,000	$	—

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Accounts and Other Receivables

3 Months Ended

Mar. 31, 2017

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

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

	March 31,		December 31,
	2017		2016
SPL trade receivable	$	92	$	88
Other accounts receivable	9		2
Total accounts and other receivables	$	101	$	90

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of SPL’s debt holders, SPL is required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. As of March 31, 2017 and December 31, 2016, substantially all of our trade receivable balance was from two SPA customers.

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Inventory

3 Months Ended

Mar. 31, 2017

Inventory Disclosure [Abstract]

Inventory

INVENTORY

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

	March 31,		December 31,
	2017		2016
Natural gas	$	19	$	15
LNG	22		45
Materials and other	46		37
Total inventory	$	87	$	97

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2017			2016
LNG terminal costs
LNG terminal	$	10,420		$	7,976
LNG terminal construction-in-process	4,826			6,728
Accumulated depreciation	(616		)	(553		)
Total LNG terminal costs, net	14,630			14,151
Fixed assets
Fixed assets	20			20
Accumulated depreciation	(14		)	(13		)
Total fixed assets, net	6			7
Property, plant and equipment, net	$	14,636		$	14,158

Depreciation expense during the three months ended March 31, 2017 and 2016 was $64 million and $18 million, respectively.

During the three months ended March 31, 2017 and 2016, we realized offsets to LNG terminal costs of $124 million and $14 million, respectively, that were related to the sale of commissioning cargoes because these amounts were earned prior to the start of commercial operations, during the testing phase for the construction of the Liquefaction Project.

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Derivative Instruments

3 Months Ended

Mar. 31, 2017

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”) and

• commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project(“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).

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.

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

	Fair Value Measurements as of
	March 31, 2017									December 31, 2016
	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
SPL Interest Rate Derivatives liability	$	—		$	—	$	—	$	—	$	—		$	(6	)	$	—	$	(6	)
CQP Interest Rate Derivatives asset	—			16		—		16		—			13			—		13
Liquefaction Supply Derivatives asset (liability)	(2		)	—		41		39		(4		)	(2		)	79		73

There have been no changes to our evaluation of and accounting for our derivative positions designated as Level 1 during the three months ended March 31, 2017. See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016 for additional information.

We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.

The 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 supply contracts as of the reporting date.

The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a 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 supply contracts. As of March 31, 2017 and December 31, 2016, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow.

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2017:

	Net Fair Value Asset (in millions)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$41	Income Approach	Basis Spread	$(0.345) - $0.081

The following table (in millions) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016
Balance, beginning of period	$	79		$	32
Realized and mark-to-market losses:
Included in cost of sales (1)	(41		)	(2		)
Purchases and settlements:
Purchases	4			—
Settlements (1)	(1		)	—
Balance, end of period	$	41		$	30
Change in unrealized gains relating to instruments still held at end of period	$	(41	)	$	(2	)

(1) Does not include the decrease in fair value of $1 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.  Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

SPL had entered into interest rate swaps (“SPL Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “2015 SPL Credit Facilities”). In March 2017, SPL settled the SPL Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 10—Debt.

During the three months ended March 31, 2017 there were no changes to the terms of our interest rate swaps (“CQP Interest Rate Derivatives”) entered into to hedge a portion of the variable interest payments on the credit facilities we entered into in February 2016 (the “2016 CQP Credit Facilities”). See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016 for additional information.

As of March 31, 2017, we had the following Interest Rate Derivatives outstanding:

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

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

	March 31, 2017						December 31, 2016
	SPL Interest Rate Derivatives		CQP Interest Rate Derivatives		Total		SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			Total
Balance Sheet Location
Non-current derivative assets	$	—	$	16	$	16	$	—		$	16		$	16
Derivative liabilities	—		—		—		(4		)	(3		)	(7		)
Non-current derivative liabilities	—		—		—		(2		)	—			(2		)
Total derivative liabilities	—		—		—		(6		)	(3		)	(9		)
Derivative asset (liability), net	$	—	$	16	$	16	$	(6	)	$	13		$	7

The following table (in millions) 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, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016
SPL Interest Rate Derivatives loss	$	(2	)	$	(11	)
CQP Interest Rate Derivatives gain (loss)	2			(10		)

Liquefaction Supply Derivatives

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

		Fair Value Measurements as of (1)
	Balance Sheet Location	March 31, 2017			December 31, 2016
Liquefaction Supply Derivatives	Other current assets	$	16		$	13
Liquefaction Supply Derivatives	Non-current derivative assets	28			67
Liquefaction Supply Derivatives	Derivative liabilities	(4		)	(7		)
Liquefaction Supply Derivatives	Non-current derivative liabilities	(1		)	—

(1) Does not include collateral of $5 million and $6 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016, respectively.

SPL had secured up to approximately 2,051 millionMMBtu and 1,994 million MMBtu of natural gas feedstock through natural gas supply contracts as of March 31, 2017 and December 31, 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,214 millionMMBtu and 1,117 millionMMBtu as of March 31, 2017 and December 31, 2016, respectively.

The following table (in millions) shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the three months ended March 31, 2017 and 2016:

		Three Months Ended March 31,
	Statement of Operations Location (1)	2017		2016
Liquefaction Supply Derivatives loss (2)	Cost of sales	$	39	$	4

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

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

Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2017
CQP Interest Rate Derivatives	$	17		$	(1	)	$	16
Liquefaction Supply Derivatives	48			(4		)	44
Liquefaction Supply Derivatives	2			(7		)	(5		)
As of December 31, 2016
SPL Interest Rate Derivatives	$	(6	)	$	—		$	(6	)
CQP Interest Rate Derivatives	16			—			16
CQP Interest Rate Derivatives	(3		)	—			(3		)
Liquefaction Supply Derivatives	82			(2		)	80
Liquefaction Supply Derivatives	(11		)	4			(7		)

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Other Non-Current Assets

3 Months Ended

Mar. 31, 2017

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

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

	March 31,		December 31,
	2017		2016
Advances made under EPC and non-EPC contracts	$	20	$	23
Advances made to municipalities for water system enhancements	95		95
Advances and other asset conveyances to third parties to support LNG terminals	30		31
Tax-related payments and receivables	25		28
Information technology service assets	26		27
Other	9		18
Total other non-current assets, net	$	205	$	222

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Accrued Liabilities

3 Months Ended

Mar. 31, 2017

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

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

	March 31,		December 31,
	2017		2016
Interest costs and related debt fees	$	147	$	205
Sabine Pass LNG terminal and related pipeline costs	275		211
Other accrued liabilities	4		2
Total accrued liabilities	$	426	$	418

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Debt

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Debt

DEBT

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

	March 31,			December 31,
	2017			2016
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7 and $7	$	2,007		$	2,007
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $6	1,505			1,506
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero	1,349			—
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			—
2015 SPL Credit Facilities	—			314
Cheniere Partners
2016 CQP Credit Facilities	2,560			2,560
Unamortized debt issuance costs	(201		)	(178		)
Total long-term debt, net	16,020			14,209
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			224
Total debt, net	$	16,020		$	14,433

2017 Debt Issuances and Redemptions

Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes were used to repay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.

In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the three months ended March 31, 2017.

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

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

In connection with the issuance of the 2028 SPL Senior Notes, SPL entered into a registration rights agreement (the “SPL Registration Rights Agreement”). Under the terms of the SPL Registration Rights Agreement, SPL has agreed, and any future guarantors will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2028 SPL Senior Notes for a like aggregate principal amount of debt securities of SPL with terms identical in all material respects to the 2028 SPL Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after March 6, 2017. Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2028 SPL Senior Notes. SPL will be obligated to pay additional interest on the 2028 SPL Senior Notes if it fails to comply with its obligation to register them within the specified time period.

Credit Facilities

Below is a summary (in millions) of our credit facilities outstanding as of March 31, 2017:

	SPL Working Capital Facility		2016 CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Outstanding balance	—		2,560
Letters of credit issued	377		50
Available commitment	$	823	$	190
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020, 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 millions):

	Three Months Ended March 31,
	2017			2016
Total interest cost	$	211		$	192
Capitalized interest	(81		)	(149		)
Total interest expense, net	$	130		$	43

Fair Value Disclosures

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

	March 31, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	12,861	$	13,807	$	11,513	$	12,309
2037 SPL Senior Notes (2)	800		826		—		—
Credit facilities (3)	2,560		2,560		3,098		3,098

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

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

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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Related Party Transactions

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Below is a summary (in millions) of our related party transactions as reported on our Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017		2016
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	331	$	—
Regasification revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		1
Tug Boat Lease Sharing Agreement	1		1
Total regasification revenues—affiliate	1		2
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		1
Services Agreements	18		10
Total operating and maintenance expense—affiliate	18		11
General and administrative expense—affiliate
Services Agreements	22		22

LNG Terminal Capacity Agreements

Terminal Use Agreements

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 (the “TUA Fees”), 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, which is recorded as operating and maintenance expense on our Consolidated Statements of Operations.

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 pay the TUA Fees required by the TUA to SPLNG. However, the revenue earned by SPLNG from the TUA Fees and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our Financial Statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA.

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing during the three months ended March 31, 2017 and 2016, 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.

Cheniere Marketing Master SPA

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

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, SPL has executed a confirmation 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

SPL has entered into an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell certain quantities of pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC, one of SPL’s SPA customers. SPL pays a fee to Cheniere Marketing for marketing and transportation, which is based on volume sold under this agreement.

Services Agreements

As of March 31, 2017 and December 31, 2016, we had $64 million and $38 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under the services agreements described below are recorded in general and administrative expense—affiliate.

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 $3 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Cheniere Investments Information Technology Services Agreement

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

SPLNG MSA

SPLNG has 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 pays 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 SPL’s 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.

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 $25 million in order to aid in their reconstruction efforts following Hurricane Rita, which SPLNG fulfilled in the first quarter of 2016. 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 both March 31, 2017 and December 31, 2016, we had $25 million 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.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Tug Services 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.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have 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, 2017 and 2016.

State Tax Sharing Agreements

SPLNG has 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 calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

SPL has 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.

CTPL has 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, 2017

Earnings Per Share [Abstract]

Net Loss per Common Unit

NET LOSS PER COMMON UNIT

Net 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 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 21, 2017, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on May 15, 2017 to unitholders of record as of May 2, 2017 for the period from January 1, 2017 to March 31, 2017.

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 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 through the mandatory conversion date of August 2017 for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units. 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, 2017 and 2016.

Based on the capital structure as of March 31, 2017, the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature is as follows in 2017 (in millions):

Common Units	Class B Units	Subordinated Units
$(594)	$2,004	$(1,410)

Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss). 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 millions, except per unit data) provides a reconciliation of net income (loss) and the allocation of net income (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, 2017
Net income	$	47
Declared distributions	25			24			—		—			1
Amortization of beneficial conversion feature of Class B units	—			(70		)	235		(165		)	—
Assumed allocation of undistributed net income	$	22		—			—		22			—
Assumed allocation of net income (loss)				$	(46	)	$	235	$	(143	)	$	1
Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.80	)			$	(1.06	)
Three Months Ended March 31, 2016
Net loss	$	(75	)
Declared distributions	25			24			—		—			1
Assumed allocation of undistributed net loss	$	(100	)	(29		)	—		(69		)	(2		)
Assumed allocation of net loss				$	(5	)	$	—	$	(69	)	$	(1	)
Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.08	)			$	(0.51	)

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2017		2016
Cash paid during the period for interest, net of amounts capitalized	$	175	$	24

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $316 million and $307 million as of March 31, 2017 and 2016, respectively.

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Recent Accounting Standards

3 Months Ended

Mar. 31, 2017

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, 2017:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we plan to adopt this standard using the full retrospective approach and we do not currently anticipate that the adoption will have a material impact upon our revenues. The Financial Accounting Standards Board has issued and may issue in the future amendments and interpretive guidance which may cause our evaluation to change. Furthermore, we routinely enter into new contracts and we cannot predict with certainty whether the accounting for any future contract under the new standard would result in a significant change from existing guidance. Because this assessment is preliminary and the accounting for revenue recognition is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact that recognizing fulfillment costs as assets will have on our Consolidated Financial Statements.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, whether we will elect to early adopt this standard or which, if any, practical expedients we will elect upon transition.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.

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Nature of Operations and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere Partners have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2016. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

Income Taxes, Policy

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

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Restricted Cash (Tables)

3 Months Ended

Mar. 31, 2017

Cash and Cash Equivalents [Abstract]

Schedule of Restricted Cash

As of March 31, 2017 and December 31, 2016, restricted cash consisted of the following (in millions):

	March 31,		December 31,
	2017		2016
Current restricted cash
Liquefaction Project	$	531	$	358
CQP and cash held by guarantor subsidiaries	225		247
Total current restricted cash	$	756	$	605
Non-current restricted cash
Liquefaction Project	$	1,000	$	—

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Accounts and Other Receivables (Tables)

3 Months Ended

Mar. 31, 2017

Receivables [Abstract]

Schedule of Accounts and Other Receivables

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

	March 31,		December 31,
	2017		2016
SPL trade receivable	$	92	$	88
Other accounts receivable	9		2
Total accounts and other receivables	$	101	$	90

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Inventory (Tables)

3 Months Ended

Mar. 31, 2017

Inventory Disclosure [Abstract]

Schedule of Inventory

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

	March 31,		December 31,
	2017		2016
Natural gas	$	19	$	15
LNG	22		45
Materials and other	46		37
Total inventory	$	87	$	97

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

	March 31,			December 31,
	2017			2016
LNG terminal costs
LNG terminal	$	10,420		$	7,976
LNG terminal construction-in-process	4,826			6,728
Accumulated depreciation	(616		)	(553		)
Total LNG terminal costs, net	14,630			14,151
Fixed assets
Fixed assets	20			20
Accumulated depreciation	(14		)	(13		)
Total fixed assets, net	6			7
Property, plant and equipment, net	$	14,636		$	14,158

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

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

	Fair Value Measurements as of
	March 31, 2017									December 31, 2016
	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
SPL Interest Rate Derivatives liability	$	—		$	—	$	—	$	—	$	—		$	(6	)	$	—	$	(6	)
CQP Interest Rate Derivatives asset	—			16		—		16		—			13			—		13
Liquefaction Supply Derivatives asset (liability)	(2		)	—		41		39		(4		)	(2		)	79		73

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, 2017:

	Net Fair Value Asset (in millions)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$41	Income Approach	Basis Spread	$(0.345) - $0.081

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

The following table (in millions) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016
Balance, beginning of period	$	79		$	32
Realized and mark-to-market losses:
Included in cost of sales (1)	(41		)	(2		)
Purchases and settlements:
Purchases	4			—
Settlements (1)	(1		)	—
Balance, end of period	$	41		$	30
Change in unrealized gains relating to instruments still held at end of period	$	(41	)	$	(2	)

(1) Does not include the decrease in fair value of $1 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 millions) shows the fair value of our derivatives outstanding on a gross and net basis:

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2017
CQP Interest Rate Derivatives	$	17		$	(1	)	$	16
Liquefaction Supply Derivatives	48			(4		)	44
Liquefaction Supply Derivatives	2			(7		)	(5		)
As of December 31, 2016
SPL Interest Rate Derivatives	$	(6	)	$	—		$	(6	)
CQP Interest Rate Derivatives	16			—			16
CQP Interest Rate Derivatives	(3		)	—			(3		)
Liquefaction Supply Derivatives	82			(2		)	80
Liquefaction Supply Derivatives	(11		)	4			(7		)

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of March 31, 2017, we had the following Interest Rate Derivatives outstanding:

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

Fair Value of Derivative Instruments by Balance Sheet Location

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

	March 31, 2017						December 31, 2016
	SPL Interest Rate Derivatives		CQP Interest Rate Derivatives		Total		SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			Total
Balance Sheet Location
Non-current derivative assets	$	—	$	16	$	16	$	—		$	16		$	16
Derivative liabilities	—		—		—		(4		)	(3		)	(7		)
Non-current derivative liabilities	—		—		—		(2		)	—			(2		)
Total derivative liabilities	—		—		—		(6		)	(3		)	(9		)
Derivative asset (liability), net	$	—	$	16	$	16	$	(6	)	$	13		$	7

Derivative Instruments, Gain (Loss)

The following table (in millions) 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, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016
SPL Interest Rate Derivatives loss	$	(2	)	$	(11	)
CQP Interest Rate Derivatives gain (loss)	2			(10		)

Liquefaction Supply Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Instruments by Balance Sheet Location

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

		Fair Value Measurements as of (1)
	Balance Sheet Location	March 31, 2017			December 31, 2016
Liquefaction Supply Derivatives	Other current assets	$	16		$	13
Liquefaction Supply Derivatives	Non-current derivative assets	28			67
Liquefaction Supply Derivatives	Derivative liabilities	(4		)	(7		)
Liquefaction Supply Derivatives	Non-current derivative liabilities	(1		)	—

(1) Does not include collateral of $5 million and $6 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016, respectively.

SPL had secured up to approximately 2,051 millionMMBtu and 1,994 million MMBtu of natural gas feedstock through natural gas supply contracts as of March 31, 2017 and December 31, 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,214 millionMMBtu and 1,117 millionMMBtu as of March 31, 2017 and December 31, 2016, respectively.

Derivative Instruments, Gain (Loss)

The following table (in millions) shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the three months ended March 31, 2017 and 2016:

		Three Months Ended March 31,
	Statement of Operations Location (1)	2017		2016
Liquefaction Supply Derivatives loss (2)	Cost of sales	$	39	$	4

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

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

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Other Non-Current Assets (Tables)

3 Months Ended

Mar. 31, 2017

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

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

	March 31,		December 31,
	2017		2016
Advances made under EPC and non-EPC contracts	$	20	$	23
Advances made to municipalities for water system enhancements	95		95
Advances and other asset conveyances to third parties to support LNG terminals	30		31
Tax-related payments and receivables	25		28
Information technology service assets	26		27
Other	9		18
Total other non-current assets, net	$	205	$	222

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Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2017

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

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

	March 31,		December 31,
	2017		2016
Interest costs and related debt fees	$	147	$	205
Sabine Pass LNG terminal and related pipeline costs	275		211
Other accrued liabilities	4		2
Total accrued liabilities	$	426	$	418

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Debt (Tables)

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Schedule of Debt Instruments

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

	March 31,			December 31,
	2017			2016
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7 and $7	$	2,007		$	2,007
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $6	1,505			1,506
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero	1,349			—
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			—
2015 SPL Credit Facilities	—			314
Cheniere Partners
2016 CQP Credit Facilities	2,560			2,560
Unamortized debt issuance costs	(201		)	(178		)
Total long-term debt, net	16,020			14,209
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			224
Total debt, net	$	16,020		$	14,433

Schedule of Line of Credit Facilities

Below is a summary (in millions) of our credit facilities outstanding as of March 31, 2017:

	SPL Working Capital Facility		2016 CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Outstanding balance	—		2,560
Letters of credit issued	377		50
Available commitment	$	823	$	190
Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020, 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.

Schedule of Interest Expense

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

	Three Months Ended March 31,
	2017			2016
Total interest cost	$	211		$	192
Capitalized interest	(81		)	(149		)
Total interest expense, net	$	130		$	43

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	March 31, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	12,861	$	13,807	$	11,513	$	12,309
2037 SPL Senior Notes (2)	800		826		—		—
Credit facilities (3)	2,560		2,560		3,098		3,098

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

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

(3) Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary (in millions) of our related party transactions as reported on our Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017		2016
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	331	$	—
Regasification revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		1
Tug Boat Lease Sharing Agreement	1		1
Total regasification revenues—affiliate	1		2
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		1
Services Agreements	18		10
Total operating and maintenance expense—affiliate	18		11
General and administrative expense—affiliate
Services Agreements	22		22

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Net Loss per Common Unit (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts

Based on the capital structure as of March 31, 2017, the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature is as follows in 2017 (in millions):

Common Units	Class B Units	Subordinated Units
$(594)	$2,004	$(1,410)

Schedule of Net Loss per Common Unit

The following table (in millions, except per unit data) provides a reconciliation of net income (loss) and the allocation of net income (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, 2017
Net income	$	47
Declared distributions	25			24			—		—			1
Amortization of beneficial conversion feature of Class B units	—			(70		)	235		(165		)	—
Assumed allocation of undistributed net income	$	22		—			—		22			—
Assumed allocation of net income (loss)				$	(46	)	$	235	$	(143	)	$	1
Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.80	)			$	(1.06	)
Three Months Ended March 31, 2016
Net loss	$	(75	)
Declared distributions	25			24			—		—			1
Assumed allocation of undistributed net loss	$	(100	)	(29		)	—		(69		)	(2		)
Assumed allocation of net loss				$	(5	)	$	—	$	(69	)	$	(1	)
Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.08	)			$	(0.51	)

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2017

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Three Months Ended March 31,
	2017		2016
Cash paid during the period for interest, net of amounts capitalized	$	175	$	24

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Recent Accounting Standards (Tables)

3 Months Ended

Mar. 31, 2017

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, 2017:

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we plan to adopt this standard using the full retrospective approach and we do not currently anticipate that the adoption will have a material impact upon our revenues. The Financial Accounting Standards Board has issued and may issue in the future amendments and interpretive guidance which may cause our evaluation to change. Furthermore, we routinely enter into new contracts and we cannot predict with certainty whether the accounting for any future contract under the new standard would result in a significant change from existing guidance. Because this assessment is preliminary and the accounting for revenue recognition is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact that recognizing fulfillment costs as assets will have on our Consolidated Financial Statements.
ASU 2016-02, Leases (Topic 842)	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, whether we will elect to early adopt this standard or which, if any, practical expedients we will elect upon transition.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

Recent Accounting Standards, Adopted

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.

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Nature of Operations and Basis of Presentation (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2017 mi customer trains	Dec. 31, 2016 customer
Customer Concentration Risk [Member] | SPA Customers [Member]
Nature of Operations and Basis of Presentation [Line Items]
Concentration Risk, Number Of Significant Customers		2
Customer Concentration Risk [Member] | LNG Revenues [Member]
Nature of Operations and Basis of Presentation [Line Items]
Concentration Risk, Percentage	94.00%
Customer Concentration Risk [Member] | LNG Revenues [Member] | SPA Customers [Member]
Nature of Operations and Basis of Presentation [Line Items]
Concentration Risk, Number Of Significant Customers	2
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	6
CTPL [Member] | Creole Trail Pipeline [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length Of Natural Gas Pipeline | mi	94
SPLNG [Member] | Customer Concentration Risk [Member] | TUA Customers [Member]
Nature of Operations and Basis of Presentation [Line Items]
Concentration Risk, Number Of Significant Customers	2

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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, 2017 Rate $ / shares	Dec. 31, 2012 USD ($) item
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 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
Partnership Units, Accreted Conversion Ratio | Rate		1.92
Cheniere [Member] | Class B Units [Member]
Other Ownership Interests [Line Items]
Proceeds from sale of partnership common and general partner units | $	$ 180		$ 500
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		1.97

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Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 756	$ 605	$ 402
Non-current restricted cash	1,000	0	$ 14
Liquefaction Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	531	358
Non-current restricted cash	1,000	0
CQP and cash held by guarantor subsidiaries [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 225	$ 247

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Accounts and Other Receivables (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017 USD ($) customer	Dec. 31, 2016 USD ($) customer
Accounts and Other Receivables [Line Items]
SPL trade receivable	$ 92	$ 88
Other accounts receivable	9	2
Total accounts and other receivables	$ 101	$ 90
Customer Concentration Risk [Member] | SPA Customers [Member]
Accounts and Other Receivables [Line Items]
Concentration Risk, Number Of Significant Customers | customer		2
Customer Concentration Risk [Member] | SPA Customers [Member] | Accounts Receivable [Member]
Accounts and Other Receivables [Line Items]
Concentration Risk, Number Of Significant Customers | customer	2

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Inventory (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Inventory [Line Items]
Inventory	$ 87	$ 97
Natural gas [Member]
Inventory [Line Items]
Inventory	19	15
LNG [Member]
Inventory [Line Items]
Inventory	22	45
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 46	$ 37

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Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 14,636		$ 14,158
Depreciation expense	64	$ 18
Property, plant and equipment, reduction for testing costs recovered	124	$ 14
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(616)		(553)
Property, plant and equipment, net	14,630		14,151
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	10,420		7,976
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	4,826		6,728
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	20		20
Accumulated depreciation	(14)		(13)
Property, plant and equipment, net	$ 6		$ 7

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Derivative Instruments - Narrative (Details) MMBTU in Millions, $ in Millions	1 Months Ended
	Mar. 31, 2017 USD ($) MMBTU	Dec. 31, 2016 MMBTU
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount (in MMBtu) | MMBTU	1,214	1,117
SPL [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Energy Units Secured Through Long-Term Supply Contracts | MMBTU	2,051	1,994
SPL [Member] | 2015 SPL Credit Facilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Decrease | $	$ 1,600
SPL [Member] | SPL Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Loss, Net | $	$ 7

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
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	$ 0	$ (6)
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	0	(6)
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	16	13
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	16	13
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	39	73
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	(2)	(4)
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	0	(2)
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	$ 41	$ 79

XML

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	3 Months Ended
	Mar. 31, 2017 USD ($)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Net Fair Value Asset	$ 41,000,000
Valuation Technique	Income Approach
Significant Unobservable Input	Basis Spread
Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Significant Unobservable Input Range	$ (0.345)
Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Significant Unobservable Input Range	$ 0.081

XML

Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period	$ 79	$ 32
Realized and mark-to-market gains:
Included in cost of sales	(41)	(2)	[1]
Purchases and settlements:
Purchases	4	0
Settlements	(1)	0	[1]
Balance, end of period	41	30
Change in unrealized gains relating to instruments still held at end of period	$ (41)	(2)
Decrease in Fair Value Realized and Capitalized During Period		$ 1

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

XML

Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - CQP Interest Rate Derivatives [Member] $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Derivative [Line Items]
Notional Amount	$ 225
Effective Date	Mar. 22, 2016
Maturity Date	Feb. 29, 2020
Weighted Average Fixed Interest Rate Paid	1.19%
Variable Interest Rate Received	One-month LIBOR
Maximum [Member]
Derivative [Line Items]
Notional Amount	$ 1,300

XML

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Non-current derivative assets		$ 44	$ 83
Derivative liabilities		(4)	(14)
Non-current derivative liabilities		(1)	(2)
Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities		0	(9)
Derivative asset (liability), net		16	7
Interest Rate Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		16	16
Interest Rate Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		0	(7)
Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0	(2)
SPL Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities		0	(6)
Derivative asset (liability), net		0	(6)
SPL Interest Rate Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		0	0
SPL Interest Rate Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		0	(4)
SPL Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0	(2)
CQP Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities		0	(3)
Derivative asset (liability), net		16	13
CQP Interest Rate Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		16	16
CQP Interest Rate Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		0	(3)
CQP Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0	0
Liquefaction Supply Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Other current assets	[1]	16	13
Derivative, Collateral, Right to Reclaim Cash		5	6
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[1]	28	67
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(4)	(7)
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[1]	$ (1)	$ 0

[1] Does not include collateral of $5 million and $6 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016, respectively.

XML

Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
SPL Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ (2)	$ (11)
CQP Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		2	(10)
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	[1]	$ (39)	$ (4)

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

XML

Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
SPL Interest Rate Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		$ (6)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet		0
Derivative Assets (Liabilities), at Fair Value, Net		(6)
CQP Interest Rate Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 17	16
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(1)	0
Derivative Assets (Liabilities), at Fair Value, Net	16	16
CQP Interest Rate Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(3)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet		0
Derivative Assets (Liabilities), at Fair Value, Net		(3)
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	48	82
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(4)	(2)
Derivative Assets (Liabilities), at Fair Value, Net	44	80
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	2	(11)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	(7)	4
Derivative Assets (Liabilities), at Fair Value, Net	$ (5)	$ (7)

XML

Other Non-Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Other Assets, Noncurrent [Abstract]
Advances made under EPC and non-EPC contracts	$ 20	$ 23
Advances made to municipalities for water system enhancements	95	95
Advances and other asset conveyances to third parties to support LNG terminals	30	31
Tax-related payments and receivables	25	28
Information technology service assets	26	27
Other	9	18
Other non-current assets, net	$ 205	$ 222

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Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 147	$ 205
Sabine Pass LNG terminal and related pipeline costs	275	211
Other accrued liabilities	4	2
Total accrued liabilities	$ 426	$ 418

XML

Debt - Schedule of Debt Instruments (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt, Net	$ 16,020,000,000	$ 14,209,000,000
Unamortized Debt Issuance Costs, Noncurrent	(201,000,000)	(178,000,000)
Current Debt, Working Capital Facility	0	224,000,000
Total Debt, Net	16,020,000,000	14,433,000,000
2021 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 2,007,000,000	2,007,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debt Instrument, Unamortized Premium	$ 7,000,000	7,000,000
2022 SPL 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 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,505,000,000	1,506,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debt Instrument, Unamortized Premium	$ 5,000,000	6,000,000
2024 SPL 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 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,349,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	4.20%
Debt Instrument, Unamortized Discount	$ 1,000,000	0
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 800,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2015 SPL Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 0	314,000,000
2016 CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	2,560,000,000	2,560,000,000
SPL Working Capital Facility [Member]
Debt Instrument [Line Items]
Current Debt, Working Capital Facility	0	$ 244,000,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,200,000,000.0

XML

Debt - Debt Issuances and Redemptions (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended
	Mar. 31, 2017	Feb. 28, 2017	Mar. 31, 2017	Mar. 31, 2016
Debt Instrument [Line Items]
Loss on early extinguishment of debt			$ 42	$ 1
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.00%		5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.20%		4.20%
SPL [Member] | 2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount		$ 800
Proceeds from issuances of long-term debt		$ 789
Debt Instrument, Interest Rate, Stated Percentage	5.00%		5.00%
Debt Instrument, Redemption Period, Minimum Number of Months Prior to Maturity Date, Redemption Price Equals Optional Redemption Price			6 months
Debt Instrument, Redemption Period, Maximum Number of Months Prior to Maturity Date, Redemption Price Equals Principal Amount			6 months
Debt Instrument, Redemption Price, Percentage			100.00%
SPL [Member] | 2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 1,350		$ 1,350
Proceeds from issuances of long-term debt	$ 1,330
Debt Instrument, Interest Rate, Stated Percentage	4.20%		4.20%
Debt Instrument, Redemption Period, Minimum Number of Months Prior to Maturity Date, Redemption Price Equals Make-Whole Price			6 months
Debt Instrument, Redemption Period, Maximum Number of Months Prior to Maturity Date, Redemption Price Equals Principal Amount			6 months
Debt Instrument, Redemption Price, Percentage			100.00%
Debt Instrument Registration Period			360 days
SPL [Member] | 2015 SPL Credit Facilities [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	$ 369
Commitments prepaid or terminated	$ 1,600		$ 1,600
Loss on early extinguishment of debt			$ 42

XML

Debt - Credit Facilities (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Outstanding balance		$ 16,020	$ 14,209
Outstanding balance, current		0	224
SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size		1,200
Outstanding balance, current		0	244
Letters of credit issued		377
Available commitment		$ 823
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		December 31, 2020, with various terms for underlying loans
SPL Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
SPL Working Capital Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
2016 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Original facility size		$ 2,800
Outstanding balance		2,560	$ 2,560
Letters of credit issued		50
Available commitment		$ 190
Debt Instrument, Description of Variable Rate Basis	[1]	LIBOR or base rate
Debt Instrument, Maturity Date, Description		February 25, 2020, with principals due quarterly commencing on February 19, 2019
2016 CQP Credit Facilities [Member] | February 25, 2019 [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase		0.50%
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 Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Debt Disclosure [Abstract]
Total interest cost	$ 211	$ 192
Capitalized interest	(81)	(149)
Total interest expense, net	$ 130	$ 43

XML

Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 16,020	$ 14,433
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]	12,861	11,513
Senior Notes, net of premium or discount [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	13,807	12,309
2037 SPL Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	800	0
2037 SPL Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	826	0
Credit facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[3]	2,560	3,098
Credit facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facilities, Estimated Fair Value	[3]	$ 2,560	$ 3,098

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

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

[3] Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 331	$ 0
Regasification revenues—affiliate	1	2
Operating and maintenance expense—affiliate	18	11
General and administrative expense—affiliate	22	22
Cheniere Marketing SPA and Cheniere Marketing Master SPA [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	331	0
Contracts for Sale and Purchase of Natural Gas and LNG [Member]
Related Party Transaction [Line Items]
Regasification revenues—affiliate	0	1
Operating and maintenance expense—affiliate	0	1
Tug Boat Lease Sharing Agreement [Member]
Related Party Transaction [Line Items]
Regasification revenues—affiliate	1	1
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	18	10
General and administrative expense—affiliate	$ 22	$ 22

XML

Related Party Transactions - LNG Terminal Capacity Agreements (Details)	3 Months Ended
	Mar. 31, 2017 USD ($) bcf / d trains $ / MMBTU	Mar. 31, 2016 USD ($)
Related Party Transaction [Line Items]
Revenues—affiliate	$ 331,000,000	$ 0
Terminal Use Agreement [Member] | SPLNG [Member] | SPL [Member]
Related Party Transaction [Line Items]
Regasification Capacity | bcf / d	2.0
Related Party Transaction, Committed Annual Fee	$ 250,000,000
Related Party Agreement Term	20 years
Amended and Restated Variable Capacity Rights Agreement [Member] | Cheniere Investments [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
Proceeds (Payments) of Gross Margin Earned, Percentage	80.00%
Revenues—affiliate	$ 0	$ 0
LNG Sale and Purchase Agreement [Member] | SPL [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu | $ / MMBTU	3.00
Commissioning Agreement [Member] | Cheniere Marketing [Member] | SPL [Member]
Related Party Transaction [Line Items]
Number of Liquefaction LNG Trains Subject To In Agreement | trains	4

XML

Related Party Transactions - Service Agreements (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 64,000,000	$ 38,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	64,000,000	$ 38,000,000
Cheniere Partners Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Quarterly non-accountable overhead reimbursement charge	3,000,000
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 130,000
Related Party Transaction, Bonus Percentage of Salary Entitled Upon Meeting Certain Criteria	50.00%
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | SPL [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	0.60%
Related Party Transaction, Committed Monthly Fee	$ 83,333
Management Services Agreement [Member] | Cheniere Terminals [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 520,000
Management Services Agreement [Member] | Cheniere Terminals [Member] | SPL [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	2.40%
Related Party Transaction, Committed Monthly Fee	$ 541,667
Management Services Agreement [Member] | Cheniere Terminals [Member] | CTPL [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	3.00%

XML

Related Party Transactions - Other Agreements (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Related Party Transaction [Line Items]
Revenues—affiliate	$ 331,000,000	$ 0
Cooperative Endeavor Agreements [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Tax Initiative Agreement Term	10 years
Aggregate commitment under the Agreement	$ 25,000,000
Cooperative Endeavor Agreements [Member] | Cheniere Marketing [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Advance ad valorem tax payments	25,000,000		$ 25,000,000
LNG Terminal Export Agreement [Member] | Cheniere Marketing [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Revenues—affiliate	0	$ 0
Tax Sharing Agreement [Member] | Cheniere [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	0
Tax Sharing Agreement [Member] | Cheniere [Member] | SPL [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	0
Tax Sharing Agreement [Member] | Cheniere [Member] | CTPL [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0

XML

Net Loss per Common Unit - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
	Apr. 21, 2017	Mar. 31, 2017
Class B Units [Member]
Distribution Made to Limited Partner [Line Items]
Discount upon issuance of Class B units representing beneficial conversion feature		$ 2,130
Cheniere Holdings [Member] | Class B Units [Member] | Effective Yield Method [Member]
Distribution Made to Limited Partner [Line Items]
Amortization of Beneficial Conversion Feature of Class B Units		888.70%
Blackstone [Member] | Class B Units [Member] | Effective Yield Method [Member]
Distribution Made to Limited Partner [Line Items]
Amortization of Beneficial Conversion Feature of Class B Units		966.10%
Subsequent Event [Member] | Common Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.425

XML

Net Loss per Common Unit - Schedule of Anticipated Beneficial Conversion Feature Impact to Capital Accounts (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Common Units [Member]
Schedule of Anticipated Beneficial Conversion Feature Impact to Capital Accounts [Line Items]
Anticipated Beneficial Conversion Feature Impact to Capital Accounts	$ (594)
Class B Units [Member]
Schedule of Anticipated Beneficial Conversion Feature Impact to Capital Accounts [Line Items]
Anticipated Beneficial Conversion Feature Impact to Capital Accounts	2,004
Subordinated Units [Member]
Schedule of Anticipated Beneficial Conversion Feature Impact to Capital Accounts [Line Items]
Anticipated Beneficial Conversion Feature Impact to Capital Accounts	$ (1,410)

XML

Net Loss per Common Unit - Schedule of Net Loss per Unit and Allocation of Distribution (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	$ 47	$ (75)
Declared distributions	25	25
Amortization of beneficial conversion feature of Class B units	0
Assumed allocation of undistributed net income (loss)	$ 22	$ (100)
Weighted average units outstanding	57.1	57.1
Net loss per unit	$ (0.80)	$ (0.08)
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	$ 14
Declared distributions	24	$ 24
Amortization of beneficial conversion feature of Class B units	(70)
Assumed allocation of undistributed net income (loss)	0	(29)
Assumed allocation of net income (loss)	$ (46)	$ (5)
Weighted average units outstanding	57.1	57.1
Net loss per unit	$ (0.80)	$ (0.08)
Class B Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	$ 0
Declared distributions	0	$ 0
Amortization of beneficial conversion feature of Class B units	235
Assumed allocation of undistributed net income (loss)	0	0
Assumed allocation of net income (loss)	$ 235	$ 0
Weighted average units outstanding	145.3	145.3
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	$ 32
Declared distributions	0	$ 0
Amortization of beneficial conversion feature of Class B units	(165)
Assumed allocation of undistributed net income (loss)	22	(69)
Assumed allocation of net income (loss)	$ (143)	$ (69)
Weighted average units outstanding	135.4	135.4
Net loss per unit	$ (1.06)	$ (0.51)
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	$ 1
Declared distributions	1	$ 1
Amortization of beneficial conversion feature of Class B units	0
Assumed allocation of undistributed net income (loss)	0	(2)
Assumed allocation of net income (loss)	$ 1	$ (1)

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 175	$ 24
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 316	$ 307