8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): June 15, 2018

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)	(Commission File Number)	(I.R.S. Employer Identification No.)
700 Milam Street Suite 1900 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code: (713) 375-5000

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

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. ¨

Item 8.01 Other Events

Cheniere Energy Partners, L.P. (the “Partnership”) is filing this Current Report on Form 8-K to include in the Partnership’s Quarterly Report on Form 10-Q for the three months ended March 31, 2018 (the “2018 Q1 Form 10-Q”), originally filed with the SEC on May 4, 2018, unaudited condensed consolidating financial information for the Partnership pursuant to Rule 3-10 of Regulation S-X. Additionally, the Partnership is filing unaudited financial statements as of and for the three months ended March 31, 2018 for certain of the Partnership’s affiliates whose securities collateralize the Partnership's $1.5 billion of 5.250% Senior Notes due 2025 (the "CQP Affiliates") pursuant to Rule 3-16 of Regulation S-X. The financial statements of the CQP Affiliates are filed as Exhibit 99.2 to this report and are incorporated herein by reference.

In connection with the requirements of Rule 3-10 of Regulation S-X, the Partnership has recast the unaudited consolidated financial statements included in its 2018 Q1 Form 10-Q solely to include Note 17, Supplemental Guarantor Information. The recast historical financial statements are filed as Exhibit 99.1 to this report and are incorporated herein by reference. All other information provided in the 2018 Q1 Form 10-Q remains unchanged and this report does not modify or update the disclosures in the 2018 Q1 Form 10-Q in any way other than the inclusion of the additional footnote. This report does not reflect events occurring after the original filing of the 2018 Q1 Form 10-Q and should be read in conjunction with other information that the Partnership has filed with the SEC.

Item 9.01 Financial Statements and Exhibits.

d) Exhibits

Exhibit No.	Description
99.1*	Update to the Partnership's Quarterly Report on Form 10-Q for the three months ended March 31, 2018, Item 1. Consolidated Financial Statements, as modified solely to include unaudited condensed consolidating financial information for the Partnership
99.2*	Unaudited financial statements as of and for the three months ended March 31, 2018 of Cheniere Energy Investments, LLC, Sabine Pass LNG-LP, LLC, Sabine Pass LNG, L.P., and Cheniere Creole Trail Pipeline, L.P., including the notes thereto and the independent auditors' review reports thereon
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

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 hereunto duly authorized.

		CHENIERE ENERGY PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC,
			its general partner
Date:	June 15, 2018	By:	/s/ Michael J. Wortley
		Name:	Michael J. Wortley
		Title:	Executive Vice President and
			Chief Financial Officer

EX-99.1

Exhibit 99.1

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,
	2018			2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—		$	—
Restricted cash	1,477			1,589
Accounts and other receivables	240			191
Accounts receivable—affiliate	114			163
Advances to affiliate	97			36
Inventory	83			95
Other current assets	54			65
Total current assets	2,065			2,139
Property, plant and equipment, net	15,145			15,139
Debt issuance costs, net	34			38
Non-current derivative assets	24			31
Other non-current assets, net	197			206
Total assets	$	17,465		$	17,553
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	11		$	12
Accrued liabilities	509			637
Due to affiliates	30			68
Deferred revenue	95			111
Deferred revenue—affiliate	—			1
Derivative liabilities	4			—
Total current liabilities	649			829
Long-term debt, net	16,052			16,046
Non-current deferred revenue	—			1
Non-current derivative liabilities	3			3
Other non-current liabilities	11			10
Other non-current liabilities—affiliate	25			25
Partners’ equity
Common unitholders’ interest (348.6 million units issued and outstanding at March 31, 2018 and December 31, 2017)	1,731			1,670
Subordinated unitholders’ interest (135.4 million units issued and outstanding at March 31, 2018 and December 31, 2017)	(1,019		)	(1,043		)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at March 31, 2018 and December 31, 2017)	13			12
Total partners’ equity	725			639
Total liabilities and partners’ equity	$	17,465		$	17,553

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per unit data)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Revenues
LNG revenues	$	1,015		$	492
LNG revenues—affiliate	503			331
Regasification revenues	65			65
Other revenues	10			2
Other revenues—affiliate	—			1
Total revenues	1,593			891
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	837			513
Operating and maintenance expense	95			50
Operating and maintenance expense—affiliate	26			18
General and administrative expense	4			3
General and administrative expense—affiliate	18			22
Depreciation and amortization expense	105			66
Total operating costs and expenses	1,085			672
Income from operations	508			219
Other income (expense)
Interest expense, net of capitalized interest	(185		)	(130		)
Loss on early extinguishment of debt	—			(42		)
Derivative gain, net	8			—
Other income	4			—
Total other expense	(173		)	(172		)
Net income	$	335		$	47
Basic and diluted net income (loss) per common unit	$	0.67		$	(0.80	)
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation	348.6			57.1

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY

(in millions)

(unaudited)

	Common Unitholders’ Interest				Subordinated Unitholder’s Interest				General Partner’s Interest				Total Partners’ Equity
	Units	Amount			Units	Amount			Units	Amount
Balance at December 31, 2017	348.6	$	1,670		135.4	$	(1,043	)	9.9	$	12		$	639
Net income	—	236			—	92			—	7			335
Distributions	—	(175		)	—	(68		)	—	(6		)	(249		)
Balance at March 31, 2018	348.6	$	1,731		135.4	$	(1,019	)	9.9	$	13		$	725

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

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities
Net income	$	335		$	47
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	105			66
Amortization of debt issuance costs, deferred commitment fees, premium and discount	8			10
Loss on early extinguishment of debt	—			42
Total losses on derivatives, net	42			39
Net cash used for settlement of derivative instruments	(3		)	(13		)
Other	2			—
Changes in operating assets and liabilities:
Accounts and other receivables	(50		)	(11		)
Accounts receivable—affiliate	48			59
Advances to affiliate	(56		)	(41		)
Inventory	12			17
Accounts payable and accrued liabilities	(69		)	(38		)
Due to affiliates	(25		)	(68		)
Deferred revenue	(18		)	(11		)
Other, net	—			1
Other, net—affiliate	—			16
Net cash provided by operating activities	331			115
Cash flows from investing activities
Property, plant and equipment, net	(194		)	(524		)
Net cash used in investing activities	(194		)	(524		)
Cash flows from financing activities
Proceeds from issuances of debt	—			2,314
Repayments of debt	—			(703		)
Debt issuance and deferred financing costs	—			(26		)
Distributions to owners	(249		)	(25		)
Net cash provided by (used in) financing activities	(249		)	1,560
Net increase (decrease) in cash, cash equivalents and restricted cash	(112		)	1,151
Cash, cash equivalents and restricted cash—beginning of period	1,589			605
Cash, cash equivalents and restricted cash—end of period	$	1,477		$	1,756

Balances per Consolidated Balance Sheet:

	March 31,
	2018
Cash and cash equivalents	$	—
Restricted cash	1,477
Total cash, cash equivalents and restricted cash	$	1,477

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. We also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL. 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, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

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

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

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

NOTE 2—UNITHOLDERS’ EQUITY

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

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

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights (“IDRs”), which allow the general partner to receive a higher percentage of quarterly distributions of

5

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

Cheniere Holdings, Blackstone CQP Holdco and the public own a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere Holdings’ ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.

NOTE 3—RESTRICTED CASH

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

	March 31,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	561	$	544
CQP and cash held by guarantor subsidiaries	916		1,045
Total current restricted cash	$	1,477	$	1,589

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

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

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

	March 31,		December 31,
	2018		2017
SPL trade receivable	$	232	$	185
Other accounts receivable	8		6
Total accounts and other receivables	$	240	$	191

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.

NOTE 5—INVENTORY

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

	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	14		26
Materials and other	53		52
Total inventory	$	83	$	95

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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,
	2018			2017
LNG terminal costs
LNG terminal	$	12,690		$	12,703
LNG terminal construction-in-process	3,431			3,310
Accumulated depreciation	(982		)	(880		)
Total LNG terminal costs, net	15,139			15,133
Fixed assets
Fixed assets	23			23
Accumulated depreciation	(17		)	(17		)
Total fixed assets, net	6			6
Property, plant and equipment, net	$	15,145		$	15,139

Depreciation expense was $102 million and $64 million during the three months ended March 31, 2018 and 2017, respectively.

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

NOTE 7—DERIVATIVE INSTRUMENTS

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

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

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

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

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

	Fair Value Measurements as of
	March 31, 2018								December 31, 2017
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
CQP Interest Rate Derivatives asset	$	—	$	27	$	—	$	27	$	—	$	21	$	—	$	21
Liquefaction Supply Derivatives asset	—		—		10		10		2		10		43		55

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

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

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

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

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

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Interest Rate Derivatives

During the three months ended March 31, 2018, there were no changes to the terms of the interest rate swaps (“CQP Interest Rate Derivatives”) we entered into to protect against volatility of future cash flows and hedge a portion of the variable interest payments on 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, 2017 for additional information.

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 of March 31, 2018, we had the following Interest Rate Derivatives outstanding:

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

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

	March 31,		December 31,
Balance Sheet Location	2018		2017
Other current assets	$	12	$	7
Non-current derivative assets	15		14
Total derivative assets	$	27	$	21

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

	Three Months Ended March 31,
	2018		2017
CQP Interest Rate Derivatives gain	$	8	$	2
SPL Interest Rate Derivatives loss	—		(2		)

Liquefaction Supply Derivatives

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

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

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

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

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

Consolidated Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2018
CQP Interest Rate Derivatives	$	27		$	—		$	27
Liquefaction Supply Derivatives	25			(8		)	17
Liquefaction Supply Derivatives	(9		)	2			(7		)
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—OTHER NON-CURRENT ASSETS

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

	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	25		25
Information technology service assets	23		24
Other	9		8
Total other non-current assets, net	$	197	$	206

NOTE 9—ACCRUED LIABILITIES

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

	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	186	$	253
Sabine Pass LNG terminal and related pipeline costs	319		384
Other accrued liabilities	4		—
Total accrued liabilities	$	509	$	637

NOTE 10—DEBT

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

	March 31,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
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 $5	1,505			1,505
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 $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
2016 CQP Credit Facilities	1,090			1,090
Unamortized debt issuance costs	(197		)	(204		)
Total long-term debt, net	16,052			16,046
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	16,052		$	16,046

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2018 (in millions):

	SPL Working Capital Facility		2016 CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Less:
Outstanding balance	—		1,090
Commitments prepaid or terminated	—		1,470
Letters of credit issued	706		20
Available commitment	$	494	$	220
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 principal payments due quarterly commencing on March 31, 2019

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

Restrictive Debt Covenants

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

Interest Expense

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

	Three Months Ended March 31,
	2018			2017
Total interest cost	$	232		$	211
Capitalized interest	(47		)	(81		)
Total interest expense, net	$	185		$	130

Fair Value Disclosures

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

	March 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	14,359	$	15,116	$	14,360	$	15,485
2037 SPL Senior Notes (2)	800		838		800		871
Credit facilities (3)	1,090		1,090		1,090		1,090

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

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

(3) Includes SPL Working Capital Facility and 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. 

12

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues	$	996	$	485
LNG revenues—affiliate	503		331
Regasification revenues	65		65
Other revenues	10		2
Other revenues—affiliate	—		1
Total revenues from customers	1,574		884
Revenues from derivative instruments	19		7
Total revenues	$	1,593	$	891

LNG Revenues

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

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

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

Regasification Revenues

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

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis

13

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

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

Upon substantial completion of Train 3, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During the three months ended March 31, 2018 and 2017, SPL recorded $8 million and zero as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

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

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	111		$	73
Cash received but not yet recognized	95			61
Revenue recognized from prior period deferral	(111		)	(71		)
Deferred revenues, end of period	$	95		$	63

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

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	55.2	10.0
Regasification revenues	2.8		5.6
Total revenues	$	58.0

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

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance

14

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. The receipt of such variable consideration is considered constrained due to the uncertainty of ultimate pricing and receipt and we have not included such variable consideration in the transaction price. During the three months ended March 31, 2018, approximately 56% of our LNG Revenues, 100% of our LNG revenues—affiliate and approximately 3% of our Regasification Revenues were related to variable consideration received from customers.

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

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

NOTE 12—RELATED PARTY TRANSACTIONS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	503	$	331
Other revenues—affiliate
Terminal Marine Services Agreement	—		1
Operating and maintenance expense—affiliate
Services Agreements	26		18
General and administrative expense—affiliate
Services Agreements	18		22

LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least 20 years after May 2016.

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

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments 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 Consolidated Financial Statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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, 2018 and 2017, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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

Cheniere Marketing Master SPA

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

Commissioning Confirmation

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

Services Agreements

As of March 31, 2018 and December 31, 2017, we had $97 million and $36 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 a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $3 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Cheniere Investments Information Technology Services Agreement

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

SPLNG O&M Agreement

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPLNG MSA

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

SPL O&M Agreement

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

SPL MSA

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

CTPL O&M Agreement

CTPL has an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse 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.

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.

17

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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, 2018 and December 31, 2017, 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.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the three months ended March 31, 2018 and 2017.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

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

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013.

18

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statement of Partners’ Equity. On April 27, 2018, we declared a $0.55 distribution per common unit and subordinated unit and the related distribution to our general partner and IDR holders to be paid on May 15, 2018 to unitholders of record as of May 7, 2018 for the period from January 1, 2018 to March 31, 2018.

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

The Class B units, which were mandatorily converted into our common units in accordance with the terms of our partnership agreement on August 2, 2017, were issued at a discount to the market price of the common units into which they were convertible.  This discount, totaling $2,130 million, represented a beneficial conversion feature and was reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statement of Partners’ Equity.  The beneficial conversion feature was considered a dividend that was distributed ratably with respect to any Class B unit from its issuance date through its conversion date, which resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortized the beneficial conversion feature through the mandatory conversion date of August 2, 2017 using the effective yield method, with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature was also included in earnings per unit for the three months ended March 31, 2017.

19

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

			Limited Partner Units
	Total		Common Units			Class B Units		Subordinated Units			General Partner Units		IDR
Three Months Ended March 31, 2018
Net income	$	335
Declared distributions	278		192			—		74			6		6
Assumed allocation of undistributed net income (1)	$	57	40			—		16			1		—
Assumed allocation of net income			$	232		$	—	$	90		$	7	$	6
Weighted average units outstanding			348.6			—		135.4
Net income per unit (2)			$	0.67				$	0.67
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			$	(46	)	$	235	$	(143	)	$	1	$	—
Weighted average units outstanding			57.1			145.3		135.4
Net loss per unit (2)			$	(0.80	)			$	(1.06	)

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

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

NOTE 14—CUSTOMER CONCENTRATION

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

	Percentage of Total Third-Party Revenues		Percentage of Accounts Receivable from Third Parties
	Three Months Ended March 31,		March 31,	December 31,
	2018	2017	2018	2017
Customer A	31%	54%	33%	39%
Customer B	25%	29%	19%	32%
Customer C	25%	—%	19%	26%
Customer D	*	—%	26%	—%

* Less than 10%

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	242	$	175

20

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $200 million and $316 million as of March 31, 2018 and 2017, respectively.

NOTE 16—RECENT ACCOUNTING STANDARDS

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

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and 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. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we anticipate a material impact from the requirement to recognize all leases 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. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

21

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

22

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 17—SUPPLEMENTAL GUARANTOR INFORMATION

Our 2025 CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (the “CQP Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the CQP Indenture. See Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information regarding the 2025 CQP Senior Notes.

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

23

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Balance Sheet
March 31, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantor		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	903		13		561		—			1,477
Accounts and other receivables	1		1		238		—			240
Accounts receivable—affiliate	—		26		114		(26		)	114
Advances to affiliate	—		76		91		(70		)	97
Inventory	—		11		72		—			83
Other current assets	13		3		38		—			54
Other current assets—affiliate	—		—		22		(22		)	—
Total current assets	917		130		1,136		(118		)	2,065
Property, plant and equipment, net	79		2,157		12,933		(24		)	15,145
Debt issuance costs, net	18		—		16		—			34
Non-current derivative assets	15		—		9		—			24
Investments in subsidiaries	2,308		180		—		(2,488		)	—
Other non-current assets, net	—		38		159		—			197
Total assets	$	3,337	$	2,505	$	14,253	$	(2,630	)	$	17,465
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4	$	7	$	—		$	11
Accrued liabilities	43		15		451		—			509
Due to affiliates	—		94		32		(96		)	30
Deferred revenue	—		26		69		—			95
Deferred revenue—affiliate	—		22		—		(22		)	—
Derivative liabilities	—		—		4		—			4
Total current liabilities	43		161		563		(118		)	649
Long-term debt, net	2,569		—		13,483		—			16,052
Non-current derivative liabilities	—		—		3		—			3
Other non-current liabilities	—		11		—		—			11
Other non-current liabilities—affiliate	—		25		—		—			25
Partners’ equity	725		2,308		204		(2,512		)	725
Total liabilities and partners’ equity	$	3,337	$	2,505	$	14,253	$	(2,630	)	$	17,465

24

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

25

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,015		$	—		$	1,015
LNG revenues—affiliate	—			—			503			—			503
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			64			—			(64		)	—
Other revenues	—			10			—			—			10
Other revenues—affiliate	—			55			—			(55		)	—
Total revenues	—			194			1,518			(119		)	1,593
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			838			(1		)	837
Cost of sales—affiliate	—			—			8			(8		)	—
Operating and maintenance expense	—			17			78			—			95
Operating and maintenance expense—affiliate	—			32			103			(109		)	26
General and administrative expense	1			1			2			—			4
General and administrative expense—affiliate	3			4			12			(1		)	18
Depreciation and amortization expense	1			18			86			—			105
Total operating costs and expenses	5			72			1,127			(119		)	1,085
Income (loss) from operations	(5		)	122			391			—			508
Other income (expense)
Interest expense, net of capitalized interest	(34		)	—			(151		)	—			(185		)
Derivative gain, net	8			—			—			—			8
Equity earnings of subsidiaries	363			242			—			(605		)	—
Other income (expense)	3			(1		)	2			—			4
Total other income (expense)	340			241			(149		)	(605		)	(173		)
Net income	$	335		$	363		$	242		$	(605	)	$	335

26

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	492		$	—		$	492
LNG revenues—affiliate	—			—			331			—			331
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			33			—			(33		)	—
Other revenues	—			2			—			—			2
Other revenues—affiliate	—			51			—			(50		)	1
Total revenues	—			151			823			(83		)	891
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			510			3			513
Cost of sales—affiliate	—			—			4			(4		)	—
Operating and maintenance expense	1			10			39			—			50
Operating and maintenance expense—affiliate	—			34			59			(75		)	18
General and administrative expense	1			—			2			—			3
General and administrative expense—affiliate	3			3			17			(1		)	22
Depreciation and amortization expense	—			19			47			—			66
Total operating costs and expenses	5			66			678			(77		)	672
Income (loss) from operations	(5		)	85			145			(6		)	219
Other income (expense)
Interest expense, net of capitalized interest	(25		)	—			(105		)	—			(130		)
Loss on early extinguishment of debt	—			—			(42		)	—			(42		)
Derivative gain (loss), net	2			—			(2		)	—			—
Equity earnings (losses) of subsidiaries	75			(4		)	—			(71		)	—
Total other income (expense)	52			(4		)	(149		)	(71		)	(172		)
Net income (loss)	$	47		$	81		$	(4	)	$	(77	)	$	47

27

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(10	)	$	135		$	206		$	—		$	331
Cash flows from investing activities
Property, plant and equipment, net	—			(5		)	(189		)	—			(194		)
Investments in subsidiaries	(38		)	—			—			38			—
Distributions received from affiliates, net	167			—			—			(167		)	—
Net cash provided by (used in) investing activities	129			(5		)	(189		)	(129		)	(194		)
Cash flows from financing activities
Distributions to parent	—			(167		)	—			167			—
Contributions from parent	—			38			—			(38		)	—
Distributions to owners	(249		)	—			—			—			(249		)
Net cash used in financing activities	(249		)	(129		)	—			129			(249		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(130		)	1			17			—			(112		)
Cash, cash equivalents and restricted cash—beginning of period	1,033			12			544			—			1,589
Cash, cash equivalents and restricted cash—end of period	$	903		$	13		$	561		$	—		$	1,477

Balances per Condensed Consolidating Balance Sheet:

	March 31, 2018
	Parent Issuer		Guarantors		Non-Guarantor		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Restricted cash	903		13		561		—		1,477
Total cash, cash equivalents and restricted cash	$	903	$	13	$	561	$	—	$	1,477

28

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(29	)	$	32		$	116		$	(4	)	$	115
Cash flows from investing activities
Property, plant and equipment, net	—			—			(528		)	4			(524		)
Investments in subsidiaries	(127		)	—			—			127			—
Distributions received from affiliates, net	159			—			—			(159		)	—
Net cash provided by (used in) investing activities	32			—			(528		)	(28		)	(524		)
Cash flows from financing activities
Proceeds from issuances of debt	—			—			2,314			—			2,314
Repayments of debt	—			—			(703		)	—			(703		)
Debt issuance and deferred financing costs	—			—			(26		)	—			(26		)
Distributions to parent	—			(159		)	—			159			—
Contributions from parent	—			127			—			(127		)	—
Distributions to owners	(25		)	—			—			—			(25		)
Net cash provided by (used in) financing activities	(25		)	(32		)	1,585			32			1,560
Net increase (decrease) in cash, cash equivalents and restricted cash	(22		)	—			1,173			—			1,151
Cash, cash equivalents and restricted cash—beginning of period	234			13			358			—			605
Cash, cash equivalents and restricted cash—end of period	$	212		$	13		$	1,531		$	—		$	1,756

29

EX-99.2

Exhibit 99.2

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS OF SUBSIDIARIES INCLUDED

PURSUANT TO RULE 3-16 OF REGULATION S-X

UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS OF CHENIERE ENERGY INVESTMENTS, LLC	2
Independent Auditors’ Review Report	5
Consolidated Balance Sheets	6
Consolidated Statements of Income	7
Consolidated Statement of Member’s Equity	8
Consolidated Statements of Cash Flows	9
Notes to Consolidated Financial Statements	10
UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS OF SABINE PASS LNG-LP, LLC	26
Independent Auditors’ Review Report	29
Consolidated Balance Sheets	30
Consolidated Statements of Income	31
Consolidated Statement of Member’s Equity	32
Consolidated Statements of Cash Flows	33
Notes to Consolidated Financial Statements	34
UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS OF SABINE PASS LNG, L.P.	50
Independent Auditors’ Review Report	53
Consolidated Balance Sheets	54
Consolidated Statements of Income	55
Consolidated Statement of Partners’ Equity	56
Consolidated Statements of Cash Flows	57
Notes to Consolidated Financial Statements	58
UNAUDITED FINANCIAL STATEMENTS OF CHENIERE CREOLE TRAIL PIPELINE, L.P.	68
Independent Auditors’ Review Report	69
Balance Sheets	70
Statements of Income	71
Statement of Partners’ Equity	72
Statements of Cash Flows	73
Notes to Financial Statements	74

1

Cheniere Energy Investments, LLC

Consolidated Financial Statements

As of March 31, 2018 and December 31, 2017

and for the three months ended March 31, 2018 and 2017

2

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

DEFINITIONS

As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

Bcf/d	billion cubic feet per day
EPC	engineering, procurement and construction
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
SEC	U.S. Securities and Exchange Commission
SPA	LNG sale and purchase agreement
TBtu	trillion British thermal units, an energy unit
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA	terminal use agreement

3

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of March 31, 2018, including our ownership of certain subsidiaries, and the references to these entities used in these Consolidated Financial Statements:

Unless the context requires otherwise, references to “Cheniere Investments,” “the Company,” “we,” “us” and “our” refer to Cheniere Energy Investments, LLC and its consolidated subsidiaries, including SPLNG, SPL and CTPL. 

4

Independent Auditors’ Review Report

To the Member of Cheniere Energy Investments, LLC:

Report on the Financial Statements

We have reviewed the consolidated financial statements of Cheniere Energy Investments, LLC and its subsidiaries (the Company), which comprise the consolidated balance sheet as of March 31, 2018, the related consolidated statements of income and cash flows for the three-month periods ended March 31, 2018 and 2017, and the related consolidated statement of member’s equity for the three-month period ended March 31, 2018.

Management’s Responsibility

The Company’s management is responsible for the preparation and fair presentation of the financial information in accordance with U.S. generally accepted accounting principles; this responsibility includes the design, implementation, and maintenance of internal control sufficient to provide a reasonable basis for the preparation and fair presentation of interim financial information in accordance with U.S. generally accepted accounting principles.

Auditors’ Responsibility

Our responsibility is to conduct our reviews in accordance with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial information. Accordingly, we do not express such an opinion.

Conclusion

Based on our reviews, we are not aware of any material modifications that should be made to the consolidated financial information referred to above for it to be in accordance with U.S. generally accepted accounting principles.

Report on Consolidated Balance Sheet as of December 31, 2017

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of December 31, 2017, and the related consolidated statements of operations, member’s equity, and cash flows for the year then ended (not presented herein); and we expressed an unmodified audit opinion on those audited consolidated financial statements in our report dated June 15, 2018. Our report also included an emphasis of matter related to a change in the method of accounting for revenue recognition due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. In our opinion, the consolidated balance sheet of the Company as of December 31, 2017 is consistent, in all material respects, with the audited consolidated financial statements from which it has been derived.

/s/ KPMG LLP

Houston, Texas

June 15, 2018

5

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions)

	March 31,		December 31,
	2018		2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	574		557
Accounts and other receivables	240		190
Accounts receivable—affiliate	114		163
Advances to affiliate	97		36
Inventory	83		95
Other current assets	38		56
Other current assets—affiliate	2		1
Total current assets	1,148		1,098
Property, plant and equipment, net	15,066		15,059
Debt issuance costs, net	16		18
Non-current derivative assets	9		17
Other non-current assets, net	196		206
Total assets	$	16,435	$	16,398
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	11	$	12
Accrued liabilities	466		614
Due to affiliates	30		68
Deferred revenue	95		111
Derivative liabilities	4		—
Other current liabilities—affiliate	—		1
Total current liabilities	606		806
Long-term debt, net	13,483		13,477
Non-current deferred revenue	—		1
Non-current derivative liabilities	3		3
Other non-current liabilities	10		10
Other non-current liabilities—affiliate	25		25
Member’s equity	2,308		2,076
Total liabilities and member’s equity	$	16,435	$	16,398

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

6

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Revenues
LNG revenues	$	1,015		$	492
LNG revenues—affiliate	503			331
Regasification revenues	65			65
Other revenues	10			2
Other revenues—affiliate	—			1
Total revenues	1,593			891
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	837			513
Operating and maintenance expense	95			49
Operating and maintenance expense—affiliate	26			18
General and administrative expense	3			2
General and administrative expense—affiliate	15			19
Depreciation and amortization expense	105			65
Total operating costs and expenses	1,081			666
Income from operations	512			225
Other income (expense)
Interest expense, net of capitalized interest	(151		)	(105		)
Loss on early extinguishment of debt	—			(42		)
Derivative loss, net	—			(2		)
Other income	2			—
Total other expense	(149		)	(149		)
Net income	$	363		$	76

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

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF MEMBER’S EQUITY

(in millions)

(unaudited)

	Cheniere Energy Partners, L.P.			Total Member’s Equity
Balance at December 31, 2017	$	2,076		$	2,076
Net income	363			363
Contributions	37			37
Distributions	(168		)	(168		)
Balance at March 31, 2018	$	2,308		$	2,308

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

8

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities
Net income	$	363		$	76
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	105			65
Amortization of debt issuance costs, deferred commitment fees, premium and discount	5			5
Loss on early extinguishment of debt	—			42
Total losses on derivatives, net	50			41
Net cash used for settlement of derivative instruments	(5		)	(11		)
Other	1			—
Changes in operating assets and liabilities:
Accounts and other receivables	(49		)	(11		)
Accounts receivable—affiliate	48			59
Advances to affiliate	(56		)	(41		)
Inventory	12			17
Accounts payable and accrued liabilities	(89		)	(37		)
Due to affiliates	(25		)	(42		)
Deferred revenue	(18		)	(11		)
Other, net	1			2
Other, net—affiliate	(1		)	17
Net cash provided by operating activities	342			171
Cash flows from investing activities
Property, plant and equipment, net	(194		)	(525		)
Net cash used in investing activities	(194		)	(525		)
Cash flows from financing activities
Proceeds from issuances of debt	—			2,314
Repayments of debt	—			(703		)
Debt issuance and deferred financing costs	—			(26		)
Capital contributions	37			101
Distributions	(168		)	(159		)
Net cash provided by (used in) financing activities	(131		)	1,527
Net increase in cash, cash equivalents and restricted cash	17			1,173
Cash, cash equivalents and restricted cash—beginning of period	557			371
Cash, cash equivalents and restricted cash—end of period	$	574		$	1,544

Balances per Consolidated Balance Sheet:

	March 31, 2018
Cash and cash equivalents	$	—
Restricted cash	574
Total cash, cash equivalents and restricted cash	$	574

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

9

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is 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.

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP for interim financial information and pursuant to the rules and regulations of the SEC. 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 our Consolidated Financial Statements and accompanying notes included in Cheniere Partners’ annual report on Form 10-K for the year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

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

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

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

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

NOTE 2—RESTRICTED CASH

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

	March 31,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	561	$	544
Cash held by Cheniere Partners’ guarantor subsidiaries, including us	13		13
Total current restricted cash	$	574	$	557

Under the terms of the credit and guaranty agreement aggregating $2.8 billion that Cheniere Partners entered into in February 2016 (the “2016 CQP Credit Facilities”), Cheniere Partners’ guarantor subsidiaries are required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities. See Note 14—Guarantees for information regarding Cheniere Partners’ guarantor subsidiaries.

10

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

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

	March 31,		December 31,
	2018		2017
SPL trade receivable	$	232	$	185
Other accounts receivable	8		5
Total accounts and other receivables	$	240	$	190

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.

NOTE 4—INVENTORY

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

	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	14		26
Materials and other	53		52
Total inventory	$	83	$	95

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	12,650		$	12,663
LNG terminal construction-in-process	3,391			3,269
Accumulated depreciation	(981		)	(879		)
Total LNG terminal costs, net	15,060			15,053
Fixed assets
Fixed assets	21			23
Accumulated depreciation	(15		)	(17		)
Total fixed assets, net	6			6
Property, plant and equipment, net	$	15,066		$	15,059

Depreciation expense was $102 million and $63 million during the three months ended March 31, 2018 and 2017, respectively.

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

11

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 6—DERIVATIVE INSTRUMENTS

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

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

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

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

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

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

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

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

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

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

12

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

Interest Rate Derivatives

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

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

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

Liquefaction Supply Derivatives

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

13

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

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

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

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

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

Consolidated Balance Sheet Presentation

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

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

14

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 7—OTHER NON-CURRENT ASSETS

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

	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	25		25
Information technology service assets	23		24
Other	8		8
Total other non-current assets, net	$	196	$	206

NOTE 8—ACCRUED LIABILITIES

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

	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	143	$	229
Sabine Pass LNG terminal and related pipeline costs	319		384
Other accrued liabilities	4		—
Total accrued liabilities	$	466	$	614

NOTE 9—DEBT

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

	March 31,			December 31,
	2018			2017
Long-term debt:
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
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 $5	1,505			1,505
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 $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Unamortized debt issuance costs	(176		)	(183		)
Total long-term debt, net	13,483			13,477
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	13,483		$	13,477

15

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPL Working Capital Facility

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

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

Restrictive Debt Covenants

As of March 31, 2018, SPL was in compliance with all covenants related to its debt agreements.

Interest Expense

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

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

Fair Value Disclosures

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

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

(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 interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 

16

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—REVENUES FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues	$	996	$	485
LNG revenues—affiliate	503		331
Regasification revenues	65		65
Other revenues	10		2
Other revenues—affiliate	—		1
Total revenues from customers	1,574		884
Revenues from derivative instruments (1)	19		7
Total revenues	$	1,593	$	891

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

LNG Revenues

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

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

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

Regasification Revenues

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

17

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During the three months ended March 31, 2018 and 2017, SPL recorded $8 million and zero as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

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

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	111		$	73
Cash received but not yet recognized	95			61
Revenue recognized from prior period deferral	(111		)	(71		)
Deferred revenues, end of period	$	95		$	63

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

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	55.2	10.0
Regasification revenues	2.8		5.6
Total revenues	$	58.0

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

18

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During the three months ended March 31, 2018, approximately 56% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 3% of our Regasification revenues were related to variable consideration received from customers.

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

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

NOTE 11—RELATED PARTY TRANSACTIONS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	503	$	331
Other revenues—affiliate
Terminal Marine Services Agreement	—		1
Operating and maintenance expense—affiliate
Services Agreements	26		18
General and administrative expense—affiliate
Services Agreements	15		19

LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0 Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least 20 years after May 2016.

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

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay

19

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

the TUA Fees required by the TUA to SPLNG. However, the revenue earned by SPLNG from the TUA Fees and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our Consolidated Financial Statements. Cheniere Partners has 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, LLC (“Cheniere Marketing US”) has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing US is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing US arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing US during the three months ended March 31, 2018 and 2017 related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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

Cheniere Marketing Master SPA

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

Commissioning Confirmation

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

Services Agreements

As of March 31, 2018 and December 31, 2017, we had $97 million and $36 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Information Technology Services Agreement

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

SPLNG MSA

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

20

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPL O&M Agreement

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

SPL MSA

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

CTPL O&M Agreement

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

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represented an aggregate commitment of $25 million in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to, 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, 2018 and December 31, 2017, we had $25 million of both other non-current assets resulting from SPLNG’s ad valorem tax payments and other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.

21

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing US have an LNG Terminal Export Agreement that provides Cheniere Marketing US 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, 2018 and 2017.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

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

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013.

22

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 12—CUSTOMER CONCENTRATION

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

	Percentage of Total Third-Party Revenues		Percentage of Accounts Receivable from Third Parties
	Three Months Ended March 31,		March 31,	December 31,
	2018	2017	2018	2017
Customer A	31%	54%	33%	39%
Customer B	25%	29%	19%	32%
Customer C	25%	—%	19%	26%
Customer D	*	—%	26%	—%

* Less than 10%

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

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

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

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $198 million and $314 million, as of March 31, 2018 and 2017, respectively.

NOTE 14—GUARANTEES

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities, which included an approximately $2.1 billion SPLNG tranche term loan and a $450.0 million CTPL tranche term loan that were used to satisfy our subsidiaries’ outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LP subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of March 31, 2018, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us but not including our non-guarantor subsidiary’s assets and rights, and our real property (except for certain excluded properties). As of March 31, 2018, the collateralized net assets of the CQP Guarantors was $2.3 billion.

23

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 15—RECENT ACCOUNTING STANDARDS

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

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

24

CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

25

Sabine Pass LNG-LP, LLC

Consolidated Financial Statements

As of March 31, 2018 and December 31, 2017

and for the three months ended March 31, 2018 and 2017

26

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

DEFINITIONS

As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

Bcf/d	billion cubic feet per day
EPC	engineering, procurement and construction
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
SEC	U.S. Securities and Exchange Commission
SPA	LNG sale and purchase agreement
TBtu	trillion British thermal units, an energy unit
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA	terminal use agreement

27

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of March 31, 2018, including our ownership of certain subsidiaries, and the references to these entities used in these Consolidated Financial Statements:

Unless the context requires otherwise, references to “Sabine Pass LP,” “the Company,” “we,” “us” and “our” refer to Sabine Pass LNG-LP, LLC and its consolidated subsidiaries, including SPL, SPLNG and Tug Services.

28

Independent Auditors’ Review Report

To the Member of Sabine Pass LNG-LP, LLC:

Report on the Financial Statements

We have reviewed the consolidated financial statements of Sabine Pass LNG-LP, LLC, and its subsidiaries (the Company), which comprise the consolidated balance sheet as of March 31, 2018, the related consolidated statements of income and cash flows for the three‑month periods ended March 31, 2018 and 2017, and the related consolidated statement of member’s equity for the three-month period ended March 31, 2018.

Management’s Responsibility

The Company’s management is responsible for the preparation and fair presentation of the financial information in accordance with U.S. generally accepted accounting principles; this responsibility includes the design, implementation, and maintenance of internal control sufficient to provide a reasonable basis for the preparation and fair presentation of interim financial information in accordance with U.S. generally accepted accounting principles.

Auditors’ Responsibility

Our responsibility is to conduct our reviews in accordance with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial information. Accordingly, we do not express such an opinion.

Conclusion

Based on our reviews, we are not aware of any material modifications that should be made to the consolidated financial information referred to above for it to be in accordance with U.S. generally accepted accounting principles.

Report on Consolidated Balance Sheet as of December 31, 2017

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of December 31, 2017, and the related consolidated statements of operations, member’s equity, and cash flows for the year then ended (not presented herein); and we expressed an unmodified audit opinion on those audited consolidated financial statements in our report dated June 15, 2018. Our report also included an emphasis of matter related to a change in the method of accounting for revenue recognition due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. In our opinion, the consolidated balance sheet of the Company as of December 31, 2017 is consistent, in all material respects, with the audited consolidated financial statements from which it has been derived.

/s/ KPMG LLP

Houston, Texas

June 15, 2018

29

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions)

	March 31,		December 31,
	2018		2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	573		556
Accounts and other receivables	239		190
Accounts receivable—affiliate	114		163
Advances to affiliate	95		32
Inventory	82		94
Other current assets	38		55
Other current assets—affiliate	2		1
Total current assets	1,143		1,091
Property, plant and equipment, net	14,529		14,518
Debt issuance costs, net	16		18
Non-current derivative assets	9		17
Other non-current assets, net	187		197
Total assets	$	15,884	$	15,841
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	10	$	11
Accrued liabilities	462		613
Due to affiliates	35		72
Deferred revenue	95		111
Deferred revenue—affiliate	—		1
Derivative liabilities	4		—
Total current liabilities	606		808
Long-term debt, net	13,483		13,477
Non-current deferred revenue	—		1
Non-current derivative liabilities	3		3
Other non-current liabilities	10		10
Other non-current liabilities—affiliate	25		25
Member’s equity	1,757		1,517
Total liabilities and member’s equity	$	15,884	$	15,841

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

30

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Revenues
LNG revenues	$	1,015		$	492
LNG revenues—affiliate	503			331
Regasification revenues	65			65
Regasification revenues—affiliate	—			31
Other revenues	10			1
Other revenues—affiliate	—			1
Total revenues	1,593			921
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	838			510
Operating and maintenance expense	90			48
Operating and maintenance expense—affiliate	45			31
General and administrative expense	2			1
General and administrative expense—affiliate	14			19
Depreciation and amortization expense	100			61
Total operating costs and expenses	1,089			670
Income from operations	504			251
Other income (expense)
Interest expense, net of capitalized interest	(151		)	(105		)
Loss on early extinguishment of debt	—			(42		)
Derivative loss, net	—			(2		)
Other income	2			—
Total other expense	(149		)	(149		)
Net income	$	355		$	102

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

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF MEMBER’S EQUITY

(in millions)

(unaudited)

	Cheniere Energy Investments, LLC			Total Member’s Equity
Balance at December 31, 2017	$	1,517		$	1,517
Contributions	32			32
Distributions	(147		)	(147		)
Net income	355			355
Balance at March 31, 2018	$	1,757		$	1,757

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

32

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities
Net income	$	355		$	102
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	100			61
Amortization of debt issuance costs, deferred commitment fees, premium and discount	5			5
Loss on early extinguishment of debt	—			42
Total losses on derivatives, net	50			41
Net cash used for settlement of derivative instruments	(5		)	(11		)
Other	1			2
Changes in operating assets and liabilities:
Accounts and other receivables	(49		)	(11		)
Accounts receivable—affiliate	48			56
Advances to affiliate	(58		)	(40		)
Inventory	12			17
Accounts payable and accrued liabilities	(93		)	(40		)
Due to affiliates	(22		)	7
Deferred revenue	(18		)	(11		)
Other, net	1			5
Other, net—affiliate	(1		)	12
Net cash provided by operating activities	326			237
Cash flows from investing activities
Property, plant and equipment, net	(194		)	(527		)
Net cash used in investing activities	(194		)	(527		)
Cash flows from financing activities
Proceeds from issuances of debt	—			2,314
Repayments of debt	—			(703		)
Debt issuance and deferred financing costs	—			(26		)
Capital contributions	32			17
Distributions	(147		)	(139		)
Net cash provided by (used in) financing activities	(115		)	1,463
Net increase in cash, cash equivalents and restricted cash	17			1,173
Cash, cash equivalents and restricted cash—beginning of period	556			359
Cash, cash equivalents and restricted cash—end of period	$	573		$	1,532

Balances per Consolidated Balance Sheet:

	March 31, 2018
Cash and cash equivalents	$	—
Restricted cash	573
Total cash, cash equivalents and restricted cash	$	573

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

33

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is 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.

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP for interim financial information and pursuant to the rules and regulations of the SEC. 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 our Consolidated Financial Statements and accompanying notes included in Cheniere Partners’ annual report on Form 10-K for the year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

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

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

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

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

NOTE 2—RESTRICTED CASH

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

	March 31,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	561	$	544
Cash held by Cheniere Partners’ guarantor subsidiaries, including us	12		12
Total current restricted cash	$	573	$	556

Under the terms of the credit and guaranty agreement aggregating $2.8 billion that Cheniere Partners entered into in February 2016 (the “2016 CQP Credit Facilities”), Cheniere Partners’ guarantor subsidiaries are required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities. See Note 14—Guarantees for information regarding Cheniere Partners’ guarantor subsidiaries.

34

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

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

	March 31,		December 31,
	2018		2017
SPL trade receivable	$	232	$	185
Other accounts receivable	7		5
Total accounts and other receivables	$	239	$	190

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.

NOTE 4—INVENTORY

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

	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	14		26
Materials and other	52		51
Total inventory	$	82	$	94

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	11,943		$	11,956
LNG terminal construction-in-process	3,410			3,289
Accumulated depreciation	(829		)	(732		)
Total LNG terminal costs, net	14,524			14,513
Fixed assets
Fixed assets	14			14
Accumulated depreciation	(9		)	(9		)
Total fixed assets, net	5			5
Property, plant and equipment, net	$	14,529		$	14,518

Depreciation expense was $97 million and $59 million during the three months ended March 31, 2018 and 2017, respectively.

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

NOTE 6—DERIVATIVE INSTRUMENTS

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

35

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

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

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

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

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

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

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

36

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

Interest Rate Derivatives

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

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

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

Liquefaction Supply Derivatives

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

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

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

37

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

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

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

Consolidated Balance Sheet Presentation

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

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

NOTE 7—OTHER NON-CURRENT ASSETS

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

	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	25		25
Information technology service assets	21		22
Other	1		1
Total other non-current assets, net	$	187	$	197

NOTE 8—ACCRUED LIABILITIES

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

	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	143	$	229
Sabine Pass LNG terminal costs	319		384
Total accrued liabilities	$	462	$	613

38

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—DEBT

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

	March 31,			December 31,
	2018			2017
Long-term debt:
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
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 $5	1,505			1,505
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 $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Unamortized debt issuance costs	(176		)	(183		)
Total long-term debt, net	13,483			13,477
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	13,483		$	13,477

SPL Working Capital Facility

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

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

Restrictive Debt Covenants

As of March 31, 2018, SPL was in compliance with all covenants related to its debt agreements.

Interest Expense

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

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

39

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

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

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

(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 interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 

NOTE 10—REVENUES FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues	$	996	$	485
LNG revenues—affiliate	503		331
Regasification revenues	65		65
Regasification revenues—affiliate	—		31
Other revenues	10		1
Other revenues—affiliate	—		1
Total revenues from customers	1,574		914
Revenues from derivative instruments (1)	19		7
Total revenues	$	1,593	$	921

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

LNG Revenues

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

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the optional exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized

40

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

when that distinct molecule of LNG is delivered to the customer. Because of the use of the optional exception, variable consideration related to the sale of LNG is also not included in the transaction price.

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

Regasification Revenues

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

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

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

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During the three months ended March 31, 2018 and 2017, SPL recorded $8 million and zero as operating and maintenance expense under this partial TUA assignment agreement.

Regasification Revenues—Affiliate

SPLNG has a terminal use rights assignment and agreement (the “TURA”) with SPL and Cheniere Investments pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay a portion of the fees required by the TUA to SPLNG, of approximately $250 million per year (the “TUA Fees”). Cheniere Investments’ right to use capacity at SPLNG’s LNG terminal and its respective percentage of TUA fees payable was reduced from 100% to zero as each of Trains 1 through 4 of SPL’s Liquefaction Project reached commercial operations. Train 4 reached commercial operations in October 2017 at which time Cheniere Investments’ right to capacity and obligation to pay future fees were substantially eliminated. SPL’s portion of the TUA Fees and SPLNG’s related revenues are eliminated in consolidation.

41

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the percentage of all TUA Fees receivable from Cheniere Investments and SPL in accordance with the TURA:

Period	Percentage of TUA Fees Receivable from Cheniere Investments	Percentage of TUA Fees Receivable from SPL
Prior to May 2016 (substantial completion of Train 1)	100%	0%
May 2016 - September 2016 (substantial completion of Train 2)	75%	25%
September 2016 - March 2017 (substantial completion of Train 3)	50%	50%
March 2017 - October 2017 (substantial completion of Train 4)	25%	75%
Thereafter	0%	100%

Cheniere Investments’ obligation to pay its percentage share of the approximately $250 million annual payments to SPLNG regardless of its use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. Because SPLNG provides recurring firm liquefaction support service throughout the course of the agreement, and because the customer immediately receives the benefit of such performance, we have concluded that we have a single performance obligation for which the related revenues shall be recognized over time. We have determined that an output method of recognition based on the quantity of firm liquefaction support services used best reflects the benefits of this service to the customer. Because we expect that SPLNG’s customer shall use its full amount of firm liquefaction support services on a periodic basis, this methodology results in the recognition of such fixed fees on a substantially straight-line basis. We have concluded that the inflation element within the contract meets the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Deferred Revenue Reconciliation

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

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	112		$	73
Cash received but not yet recognized	95			61
Revenue recognized from prior period deferral	(112		)	(71		)
Deferred revenues, end of period	$	95		$	63

The following table reflects the changes in our contract liabilities to affiliate, which we classify as “Deferred revenue—affiliate” on our Consolidated Balance Sheets (in millions):

	Three Months Ended March 31,
	2018			2017
Deferred revenues—affiliate, beginning of period	$	1		$	11
Cash received but not yet recognized	—			5
Revenue recognized from prior period deferral	(1		)	(10		)
Deferred revenues—affiliate, end of period	$	—		$	6

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

42

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	55.2	10.0
Regasification revenues	2.8		5.6
Total revenues	$	58.0

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

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During the three months ended March 31, 2018, approximately 56% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 3% of our Regasification revenues were related to variable consideration received from customers.

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

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

43

SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—RELATED PARTY TRANSACTIONS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	503	$	331
Regasification revenues—affiliate
TUA fees from Cheniere Investments	—		31
Other revenues—affiliate
Terminal Marine Services Agreement	—		1
Operating and maintenance expense—affiliate
Natural Gas Transportation Agreement	20		16
Services Agreements	25		15
Total operating and maintenance expense—affiliate	45		31
General and administrative expense—affiliate
Services Agreements	14		19

LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG, as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to pay the TUA Fees until at least May 2036.

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

Pursuant to the TURA, Cheniere Investments had the right to use SPL’s reserved capacity under SPL’s TUA with SPLNG and had the obligation to pay the TUA Fees required by the TUA to SPLNG. See Note 10—Revenues from Contracts with Customers for information regarding these agreements.

Cheniere Marketing SPA

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

Cheniere Marketing Master SPA

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

Commissioning Confirmation

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

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Natural Gas Transportation Agreements

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, SPL has a transportation precedent agreement and a negotiated rate agreement to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. These agreements have a primary term through 2036 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, SPL has the right to elect to extend the term of the agreements for up to two consecutive ten-year terms. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised SPL that it has agreed otherwise.

Services Agreements

As of March 31, 2018 and December 31, 2017, we had $95 million and $32 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

SPLNG O&M Agreement

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

SPLNG MSA

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

SPL O&M Agreement

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

SPL MSA

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

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including SPL and SPLNG, 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.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represented an aggregate commitment of $25 million in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to, 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, 2018 and December 31, 2017, we had $25 million of both other non-current assets resulting from SPLNG’s ad valorem tax payments and other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

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

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing US have an LNG Terminal Export Agreement that provides Cheniere Marketing US 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, 2018 and 2017.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

NOTE 12—CUSTOMER CONCENTRATION

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

	Percentage of Total Third-Party Revenues		Percentage of Accounts Receivable from Third Parties
	Three Months Ended March 31,		March 31,	December 31,
	2018	2017	2018	2017
Customer A	31%	54%	33%	39%
Customer B	25%	29%	19%	32%
Customer C	25%	—%	19%	26%
Customer D	*	—%	26%	—%

* Less than 10%

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

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

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

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $197 million and $315 million, as of March 31, 2018 and 2017, respectively.

NOTE 14—GUARANTEES

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities, which included an approximately $2.1 billion SPLNG tranche term loan that was used to satisfy SPLNG’s outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with us subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

As of March 31, 2018, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us but not including our non-guarantor subsidiary’s assets and rights, and our real property (except for certain excluded properties). As of March 31, 2018, the collateralized net assets of the CQP Guarantors was $2.3 billion.

NOTE 15—RECENT ACCOUNTING STANDARDS

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

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

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

49

Sabine Pass LNG, L.P.

Consolidated Financial Statements

As of March 31, 2018 and December 31, 2017

and for the three months ended March 31, 2018 and 2017

50

SABINE PASS LNG, L.P. AND SUBSIDIARY

DEFINITIONS

As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

Bcf/d	billion cubic feet per day
GAAP	generally accepted accounting principles in the United States
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
SEC	U.S. Securities and Exchange Commission
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA	terminal use agreement

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SABINE PASS LNG, L.P. AND SUBSIDIARY

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of March 31, 2018 and the references to these entities used in these Consolidated Financial Statements:

Unless the context requires otherwise, references to “SPLNG,” “the Partnership,” “we,” “us” and “our” refer to Sabine Pass LNG, L.P. and its wholly owned subsidiary, Tug Services.

52

Independent Auditors’ Review Report

To the Managers of Sabine Pass LNG-LP, LLC and

Partners of Sabine Pass LNG, L.P.:

Report on the Financial Statements

We have reviewed the consolidated financial statements of Sabine Pass LNG, L.P., and its subsidiary (the Partnership), which comprise the consolidated balance sheet as of March 31, 2018, the related consolidated statements of income and cash flows for the three‑month periods ended March 31, 2018 and 2017, and the related consolidated statement of partners’ equity for the three-month period ended March 31, 2018.

Management’s Responsibility

The Partnership’s management is responsible for the preparation and fair presentation of the financial information in accordance with U.S. generally accepted accounting principles; this responsibility includes the design, implementation, and maintenance of internal control sufficient to provide a reasonable basis for the preparation and fair presentation of interim financial information in accordance with U.S. generally accepted accounting principles.

Auditors’ Responsibility

Our responsibility is to conduct our reviews in accordance with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial information. Accordingly, we do not express such an opinion.

Conclusion

Based on our reviews, we are not aware of any material modifications that should be made to the consolidated financial information referred to above for it to be in accordance with U.S. generally accepted accounting principles.

Report on Consolidated Balance Sheet as of December 31, 2017

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of December 31, 2017, and the related consolidated statements of income, partners’ equity (deficit), and cash flows for the year then ended (not presented herein); and we expressed an unmodified audit opinion on those audited consolidated financial statements in our report dated June 15, 2018. Our report also included an emphasis of matter related to a change in the method of accounting for revenue recognition due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. In our opinion, the consolidated balance sheet of the Partnership as of December 31, 2017 is consistent, in all material respects, with the audited consolidated financial statements from which it has been derived.

/s/ KPMG LLP

Houston, Texas

June 15, 2018

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SABINE PASS LNG, L.P. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(in thousands)

	March 31,		December 31,
	2018		2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	11,881		11,389
Accounts and other receivables	1,134		924
Accounts receivable—affiliate	2,977		3,069
Advances to affiliate	4,007		6,676
Inventory	9,419		8,974
Other current assets	2,106		2,295
Other current assets—affiliate	481		—
Total current assets	32,005		33,327
Property, plant and equipment, net	1,601,034		1,603,054
Other non-current assets, net	27,423		27,630
Total assets	$	1,660,462	$	1,664,011
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	2,724	$	3,639
Accrued liabilities	10,180		6,996
Due to affiliates	8,625		8,377
Deferred revenue	25,420		26,817
Deferred revenue—affiliate	21,303		21,974
Total current liabilities	68,252		67,803
Non-current deferred revenue	500		1,500
Non-current deferred revenue—affiliate	24,533		24,533
Other non-current liabilities	9,568		9,918
Other non-current liabilities—affiliate	65		66
Partners’ equity	1,557,544		1,560,191
Total liabilities and partners’ equity	$	1,660,462	$	1,664,011

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

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SABINE PASS LNG, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME

(in thousands)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Revenues
Regasification revenues	$	65,239		$	65,050
Regasification revenues—affiliate	63,909			63,723
Other revenues	9,400			1,451
Other revenues—affiliate	7,920			5,961
Total revenues	146,468			136,185
Operating costs and expenses
Operating and maintenance expense	11,690			9,186
Operating and maintenance expense—affiliate	5,167			4,222
Development expense	237			—
Development expense—affiliate	2			—
General and administrative expense	139			125
General and administrative expense—affiliate	2,269			2,219
Depreciation and amortization expense	13,789			13,615
Total operating costs and expenses	33,293			29,367
Income from operations	113,175			106,818
Other income (expense)
Interest expense	(902		)	—
Other income	6			2
Total other income (expense)	(896		)	2
Net income	$	112,279		$	106,820

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

55

SABINE PASS LNG, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY

(in thousands)

(unaudited)

	General Partner Sabine Pass LNG-GP, LLC		Limited Partner Sabine Pass LNG-LP, LLC			Total Partners’ Equity
Balance at December 31, 2017	$	—	$	1,560,191		$	1,560,191
Net income	—		112,279			112,279
Contributions	—		32,119			32,119
Distributions	—		(147,045		)	(147,045		)
Balance at March 31, 2018	$	—	$	1,557,544		$	1,557,544

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

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SABINE PASS LNG, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities
Net income	$	112,279		$	106,820
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	13,789			13,615
Non-cash interest expense	902			—
Other	—			1
Other—affiliate	—			2,183
Changes in operating assets and liabilities:
Accounts receivable—affiliate	92			(1,053		)
Advances to affiliate	2,670			516
Inventory	(445		)	(1,045		)
Accounts payable and accrued liabilities	879			(539		)
Due to affiliates	(5,324		)	6,712
Deferred revenue	(2,397		)	(893		)
Deferred revenue—affiliate	(671		)	(5,220		)
Other, net	(1,315		)	1,283
Other—affiliate	(482		)	(78		)
Net cash provided by operating activities	119,977			122,302
Cash flows from investing activities
Property, plant and equipment, net	(4,559		)	(102		)
Net cash used in investing activities	(4,559		)	(102		)
Cash flows from financing activities
Capital contributions	32,119			16,782
Distributions to limited partner	(147,045		)	(138,647		)
Net cash used in financing activities	(114,926		)	(121,865		)
Net increase in cash, cash equivalents and restricted cash	492			335
Cash, cash equivalents and restricted cash—beginning of period	11,389			739
Cash, cash equivalents and restricted cash—end of period	$	11,881		$	1,074

Balances per Consolidated Balance Sheet:

	March 31,
	2018
Cash and cash equivalents	$	—
Restricted cash	11,881
Total cash, cash equivalents and restricted cash	$	11,881

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

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We own, develop and operate regasification facilities located in Cameron Parish, Louisiana, less than four miles from the Gulf Coast on the Sabine-Neches Waterway (our “LNG terminal”). Regasification revenues include LNG regasification capacity payments that are received from our long-term TUA customers and regasification revenues—affiliate include liquefaction support services. We recognize tug services fees that are received by Tug Services, which were historically included in regasification revenues but are now included within other revenues on our Consolidated Statements of Income. We also recognize cargo loading fees from SPL for the loading of LNG vessels at our LNG terminal, which are included within other revenues—affiliate on our Consolidated Statements of Income.

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP for interim financial information and pursuant to the rules and regulations of the SEC. 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 our Consolidated Financial Statements and accompanying notes included in Cheniere Partners’ annual report on Form 10-K for the year ended December 31, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

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

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

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

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

NOTE 2—RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of March 31, 2018 and December 31, 2017, we had $11.9 million and $11.4 million of current restricted cash, respectively, for short-term operating expenses and capital expenditures.

In February 2016, Cheniere Partners entered into a $2.8 billion credit facility (the “2016 CQP Credit Facilities”). We, as a guarantor subsidiary of the 2016 CQP Credit Facilities, are subject to limitations on the use of cash under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit. Specifically, we may only withdraw funds from collateral accounts held at a designated depositary bank on a monthly basis and for specific purposes. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions. See Note 9—Guarantees for more information regarding these guarantees.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 3—INVENTORY

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

	March 31,		December 31,
	2018		2017
LNG	$	585	$	539
Materials and other	8,834		8,435
Total inventory	$	9,419	$	8,974

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	1,998,434		$	1,993,215
LNG terminal construction-in-process	17,406			11,148
LNG site and related costs	119			120
Accumulated depreciation	(414,994		)	(401,512		)
Total LNG terminal costs, net	1,600,965			1,602,971
Fixed assets
Fixed assets	2,229			2,255
Accumulated depreciation	(2,160		)	(2,172		)
Total fixed assets, net	69			83
Property, plant and equipment, net	$	1,601,034		$	1,603,054

Depreciation expense was $13.5 million and $13.4 million during the three months ended March 31, 2018 and 2017, respectively.

NOTE 5—OTHER NON-CURRENT LIABILITIES

We, through Tug Services, entered into an agreement in 2009 which required the contingent payment of a portion of our future tug service revenues to third party counterparties over the life of the agreement in exchange for an initial cash payment of $6.0 million. We classified the cash received in 2009 as other non-current liabilities on our Consolidated Balance Sheets and impute interest expense on the non-current liability using the effective interest method. We had other non-current liabilities of $9.4 million and $9.8 million as of March 31, 2018 and December 31, 2017, respectively, resulting from this agreement. The effective interest rate is computed based on estimated payments of tug service revenues to third party counterparties over the life of the agreement, which concludes in January 2028. Changes in estimated payments to be paid to the counterparties to the agreement are reflected prospectively in interest expense on our Consolidated Statements of Income. The interest rate on the liability may vary during the term of the agreement depending primarily on the aggregate total revenue earned by Tug Services. Payments made to counterparties pursuant to the agreement reduce the other non-current liability balance.

NOTE 6—REVENUES FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended March 31,
	2018		2017
Regasification revenues	$	65,239	$	65,050
Regasification revenues—affiliate	63,909		63,723
Other revenues	9,400		1,451
Other revenues—affiliate	7,920		5,961
Total revenues	$	146,468	$	136,185

59

SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to us aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, a wholly owned subsidiary of Cheniere Partners. See “Regasification revenues—affiliate” below for information on revenue from SPL.

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

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with us. 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 additional Trains.

Upon substantial completion of Train 3, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with us. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to us will continue to be made by Total to us in accordance with its TUA and we continue to recognize the payments received from Total as third-party revenue.

Regasification Revenues—Affiliate

SPL obtained 2.0 Bcf/d of regasification capacity and other liquefaction support services as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with us. SPL is obligated to make monthly capacity payments to us aggregating approximately $250 million per year (the “TUA Fees”), continuing until May 2036. In addition, SPL is required to pay us $120,000 in cargo loading fees for each LNG vessel that they load at our LNG terminal.

We have a terminal use rights assignment and agreement (the “TURA”) with SPL and Cheniere Investments pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay a portion of the TUA Fees required by the TUA to us. Cheniere Investments’ right to use capacity at our LNG terminal and its respective percentage of TUA fees payable was reduced from 100% to zero as each of Trains 1 through 4 of SPL’s liquefaction project reached commercial operations. Train 4 reached commercial operations in October 2017 at which time Cheniere Investments’ right to capacity and obligation to pay future fees were substantially eliminated.

The following table shows the percentage of all TUA Fees receivable from Cheniere Investments and SPL in accordance with the TURA:

Period	Percentage of TUA Fees Receivable from Cheniere Investments	Percentage of TUA Fees Receivable from SPL
Prior to May 2016 (substantial completion of Train 1)	100%	0%
May 2016 - September 2016 (substantial completion of Train 2)	75%	25%
September 2016 - March 2017 (substantial completion of Train 3)	50%	50%
March 2017 - October 2017 (substantial completion of Train 4)	25%	75%
Thereafter	0%	100%

60

SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Partners has guaranteed SPL’s obligations under the TUA and the obligations of Cheniere Investments under the TURA.

SPL’s obligation to pay their percentage share of the approximately $250 million annual payments to us regardless of their use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. Cargo loading fees are also considered variable consideration because their receipt depends upon SPL’s use of liquefaction support services. Because we provide recurring firm liquefaction support service throughout the course of the agreement, and because SPL immediately receives the benefit of such performance, we have concluded that we have a single performance obligation for which the related revenues shall be recognized over time. We have determined that an output method of recognition based on the quantity of firm liquefaction support services used best reflects the benefits of this service to the customer. Because we expect that SPL shall use the full amount of firm liquefaction support services on a periodic basis, this methodology results in the recognition of such fixed fees on a substantially straight-line basis. We have concluded that both the inflation element within the contract and cargo loading fees meet the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Cheniere Investments’ obligation to pay their percentage share of the approximately $250 million annual payments to us regardless of their use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. SPLNG provides access to an integrated regasification service to Cheniere Investments. Because SPLNG reduces Cheniere Investments’ access to the terminal as each Train reaches substantial completion, we have concluded that each of the periods in the table above must be accounted for as separate performance obligations. We have allocated the transaction price to each performance obligation using estimated stand-alone selling prices corresponding with the customer’s access to capacity in that period. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer. We have concluded that the variable consideration within the contract meets the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Other Revenues

Tug Services has entered into arrangements to provide tug related services to each vessel that docks at the Sabine Pass LNG terminal. These customers have historically paid tug services fees of $125,000 for each vessel that docks at our LNG terminal, which is included in other revenues. This fee increased to $150,000 in February 2018 for future tug related services. Because we are continuously available to provide tug services on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to our customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer. Tug services fees are considered variable consideration because their receipt depends entirely upon the customer’s need to dock at the facility. We have concluded that the tug service fees meet the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in thousands):

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	28,317		$	32,209
Cash received but not yet recognized	25,420			25,384
Revenue recognized from prior period deferral	(27,817		)	(26,276		)
Deferred revenues, end of period	$	25,920		$	31,317

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table reflects the changes in our contract liabilities to affiliate, which we classify as “Deferred revenue—affiliate” and “Non-current deferred revenue—affiliate” on our Consolidated Balance Sheets (in thousands):

	Three Months Ended March 31,
	2018			2017
Deferred revenues—affiliate, beginning of period	$	46,507		$	46,417
Cash received but not yet recognized	21,303			15,948
Revenue recognized from prior period deferral	(21,974		)	(21,168		)
Deferred revenues—affiliate, end of period	$	45,836		$	41,197

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. We recognize deferred revenue related to our TUAs because our customers are required to pay a month in advance of the associated service period. We have recorded non-current deferred revenue—affiliate representing a prepayment of SPL’s future obligations under the TUA.

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
Regasification revenues	$	2.8	5.6
Regasification revenues—affiliate	4.5		9.0
Total revenues	$	7.3

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

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the number of LNG vessels loaded and adjustments to the consumer price index. During the three months ended March 31, 2018, approximately 3% of our Regasification revenues and approximately 2% of our Regasification revenues—affiliate were related to variable consideration received from customers.

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

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 7—RELATED PARTY TRANSACTIONS

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

	Three Months Ended March 31,
	2018			2017
Regasification revenues—affiliate
TUA fees from Cheniere Investments	$	—		$	31,176
TUA fees from SPL	63,909			32,547
Total regasification revenues—affiliate	63,909			63,723
Other revenues—affiliate
Cargo loading fees under TUA	7,920			5,236
Other agreements	—			725
Total other revenues—affiliate	7,920			5,961
Operating and maintenance expense—affiliate
Services Agreements	5,447			4,380
LNG Site Sublease Agreement	(244		)	(236		)
Other agreements	(36		)	78
Total operating and maintenance expense—affiliate	5,167			4,222
Development expense—affiliate
Services Agreements	2			—
General and administrative expense—affiliate
Services Agreements	2,269			2,219

Terminal Use Agreements

Pursuant to the TURA, Cheniere Investments had the right to use SPL’s reserved capacity under SPL’s TUA with us and had the obligation to pay the TUA Fees required by the TUA to us. See Note 6—Revenues from Contracts with Customers for information regarding these agreements.

Services Agreements

As of March 31, 2018 and December 31, 2017, we had $4.0 million and $6.7 million, respectively, of advances to affiliates under the services agreements described below. The non-reimbursable amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Operation and Maintenance Agreement

We have a long-term operation and maintenance agreement (the “O&M Agreement”) with Cheniere Investments pursuant to which we receive all necessary services required to operate and maintain our LNG receiving terminal. We pay a fixed monthly fee of $130,000 (indexed for inflation) under the 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 the parties at the beginning of each operating year. In addition, we are required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses.

Management Services Agreement

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

63

SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Investments Information Technology Services Agreement

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

Agreement to Fund Our Cooperative Endeavor Agreements

We have executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from 2007 through 2016. This ten-year initiative represented an aggregate commitment of $24.5 million in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for our advance payments of annual ad valorem taxes, Cameron Parish will grant us a dollar-for-dollar credit against future ad valorem taxes to be levied against our LNG terminal starting in 2019. Beginning in September 2007, we entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay us additional TUA revenues equal to any and all amounts payable by us to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, we 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.

These advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that we utilized to make the ad valorem tax payments were recorded as non-current deferred revenue—affiliate. As of both March 31, 2018 and December 31, 2017, we had $24.5 million of both other non-current assets resulting from ad valorem tax payments and non-current deferred revenue—affiliate resulting from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

We are able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing, LLC (“Cheniere Marketing US”). Under these agreements, we purchase natural gas or LNG from Cheniere Marketing US at a sales price equal to the actual purchase price paid by Cheniere Marketing US to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing US with respect to the receipt, purchase and delivery of the natural gas or LNG to our LNG terminal. We are also able to sell and purchase natural gas and LNG under an agreement with SPL.

Terminal Marine Services Agreement

In connection with our tug boat lease, Tug Services has an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at our LNG terminal. The agreement also provides that Tug Services shall contingently pay the wholly owned subsidiary of Cheniere a portion of its future revenues. We did not have any distributions pursuant to this agreement during the three months ended March 31, 2018 and 2017.

LNG Site Sublease Agreement

We have agreements with SPL to sublease a portion of the LNG terminal site for its liquefaction project. The aggregate annual sublease payment is $0.9 million. The initial term of the sublease expires on December 31, 2034, with options to renew for multiple 10-year extensions with similar terms as the initial term. The annual sublease payment will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreement.

LNG Terminal Export Agreement

We have an LNG Terminal Export Agreement with Cheniere Marketing US that provides Cheniere Marketing US with the ability to export LNG from our LNG terminal.  We did not record any revenues associated with this agreement during the three months ended March 31, 2018 and 2017.

64

SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cooperation Agreement

We have an agreement (the “Cooperation Agreement”) with SPL to allow SPL to retain and acquire certain rights to access the property and facilities that we own for the purpose of constructing, modifying and operating SPL’s facilities under construction. In consideration for the access we have given, SPL has agreed to transfer title to us of certain facilities, equipment and modifications, which we are obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. SPL did not convey any assets to us under this agreement during the three months ended March 31, 2018 and 2017.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after January 1, 2008.

NOTE 8—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2018		2017
Non-cash contributions from limited partner for certain operating activities	$	—	$	2,183

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $9.1 million and $9.7 million as of March 31, 2018 and 2017, respectively.

NOTE 9—GUARANTEES

The 2016 CQP Credit Facilities includes an approximately $2.1 billion SPLNG tranche term loan that was used to satisfy our outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LP subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of March 31, 2018, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of its assets and the assets of the CQP Guarantors, including us, except for certain excluded properties.

65

SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—RECENT ACCOUNTING STANDARDS

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

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

66

SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 6—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.

67

Cheniere Creole Trail Pipeline, L.P.

Financial Statements

As of March 31, 2018 and December 31, 2017

and for the three months ended March 31, 2018 and 2017

68

Independent Auditors’ Review Report

To the Managing Member of Cheniere Pipeline GP Interests, LLC:

Report on the Financial Statements

We have reviewed the financial statements Cheniere Creole Trail Pipeline, L.P. (the Partnership) which comprise the balance sheet as of March 31, 2018, the related statements of income and cash flows for the three-month periods ended March 31, 2018 and 2017, and the related statement of partners’ equity for the three-month period ended March 31, 2018.

Management’s Responsibility

The Partnership’s management is responsible for the preparation and fair presentation of the financial information in accordance with U.S. generally accepted accounting principles; this responsibility includes the design, implementation, and maintenance of internal control sufficient to provide a reasonable basis for the preparation and fair presentation of interim financial information in accordance with U.S. generally accepted accounting principles.

Auditors’ Responsibility

Our responsibility is to conduct our reviews in accordance with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial information. Accordingly, we do not express such an opinion.

Conclusion

Based on our reviews, we are not aware of any material modifications that should be made to the financial information referred to above for it to be in accordance with U.S. generally accepted accounting principles.

Report on Balance Sheet as of December 31, 2017

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the balance sheet as of December 31, 2017, and the related statements of operations, partners’ equity, and cash flows for the year then ended (not presented herein); and we expressed an unmodified audit opinion on those audited financial statements in our report dated June 15, 2018. Our report also included an emphasis of matter related to a change in the method of accounting for revenue recognition due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. In our opinion, the balance sheet of the Partnership as of December 31, 2017 is consistent, in all material respects, with the audited financial statements from which it has been derived.

/s/ KPMG LLP

Houston, Texas

June 15, 2018

69

CHENIERE CREOLE TRAIL PIPELINE, L.P.

BALANCE SHEETS

(in thousands)

	March 31,		December 31,
	2018		2017
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	48		48
Accounts receivable—affiliate	6,805		6,805
Advances to affiliate	2,010		3,937
Inventory	1,476		1,536
Other current assets	482		1,014
Total current assets	10,821		13,340
Property, plant and equipment, net	555,851		560,534
Other non-current assets, net	9,713		9,583
Total assets	$	576,385	$	583,457
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	732	$	757
Accrued liabilities	4,013		219
Accrued liabilities—affiliate	683		3,991
Other current liabilities—affiliate	194		601
Total current liabilities	5,622		5,568
Partners’ equity	570,763		577,889
Total liabilities and partners’ equity	$	576,385	$	583,457

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

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CHENIERE CREOLE TRAIL PIPELINE, L.P.

STATEMENTS OF INCOME

(in thousands)

(unaudited)

	Three Months Ended March 31,
	2018		2017
Revenues—affiliate	$	20,420	$	20,416
Expenses
Operating and maintenance expense	5,194		305
Operating and maintenance expense—affiliate	1,783		5,657
General and administrative expense	560		385
General and administrative expense—affiliate	202		242
Depreciation and amortization expense	4,838		4,848
Total expenses	12,577		11,437
Income from operations	7,843		8,979
Other expense	—		(1		)
Net income	$	7,843	$	8,978

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

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CHENIERE CREOLE TRAIL PIPELINE, L.P.

STATEMENT OF PARTNERS’ EQUITY

(in thousands)

(unaudited)

	General Partner Interest		Limited Partner Interest			Total Partners’ Equity
Balance at December 31, 2017	$	—	$	577,889		$	577,889
Net income	—		7,843			7,843
Contributions	—		5,451			5,451
Distributions	—		(20,420		)	(20,420		)
Balance at March 31, 2018	$	—	$	570,763		$	570,763

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

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CHENIERE CREOLE TRAIL PIPELINE, L.P.

STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities
Net income	$	7,843		$	8,978
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	4,838			4,848
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities	3,938			2,159
Accrued liabilities—affiliate	(3,304		)	(523		)
Advances to affiliate	1,927			(1,087		)
Other	361			(2,615		)
Other—affiliate	(407		)	2,588
Net cash provided by operating activities	15,196			14,348
Cash flows from investing activities
Property, plant and equipment, net	(227		)	(2		)
Net cash used in investing activities	(227		)	(2		)
Cash flows from financing activities
Capital contributions	5,451			6,069
Distributions to limited partner	(20,420		)	(20,416		)
Net cash used in financing activities	(14,969		)	(14,347		)
Net decrease in cash, cash equivalents and restricted cash	—			(1		)
Cash, cash equivalents and restricted cash—beginning of period	48			96
Cash, cash equivalents and restricted cash—end of period	$	48		$	95

Balances per Balance Sheet:

	March 31,
	2018
Cash and cash equivalents	$	—
Restricted cash	48
Total cash, cash equivalents and restricted cash	$	48

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

73

CHENIERE CREOLE TRAIL PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS

(unaudited)

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Cheniere Creole Trail Pipeline, L.P. (“CTPL”), a Delaware limited partnership, is a Houston based partnership formed with one general partner, Cheniere Pipeline GP Interests, LLC, and one limited partner, Cheniere Energy Investments, LLC (“Cheniere Investments”), both of which are wholly owned subsidiaries of Cheniere Energy Partners, L.P. (“Cheniere Partners”). Cheniere Partners is a publicly-traded Delaware limited partnership (NYSE American: CQP) formed by Cheniere Energy, Inc. (“Cheniere”). Unless the context requires otherwise, references to “we,” “us” and “our” refer to CTPL.

We were formed to own and operate a 94-mile pipeline (the “Creole Trail Pipeline”) interconnecting the Sabine Pass liquefied natural gas (“LNG”) terminal with a number of large interstate pipelines. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC (“SPL”). Cheniere Partners plans to construct up to six industrial trains comprised of refrigerant compressor loops used to cool natural gas into LNG (“Trains”), which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Cheniere Partners also owns and operates regasification facilities at the Sabine Pass LNG terminal through its wholly owned subsidiary, Sabine Pass LNG, L.P. (“SPLNG”).

SPL has entered into transportation precedent and other agreements to secure firm pipeline capacity with us, which supplement enabling agreements and long-term natural gas supply contracts SPL has executed with third parties to secure natural gas feedstock for the Liquefaction Project.

NOTE 2—BASIS OF PRESENTATION

Our Financial Statements were prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission. 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 our Financial Statements and accompanying notes included in Cheniere Partners’ annual report on Form 10-K for the year ended December 31, 2017. As a rate-regulated gas pipeline business, we apply GAAP for entities with regulated operations. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

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

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

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

We have evaluated subsequent events through June 15, 2018, the date the Financial Statements were available to be issued.

74

CHENIERE CREOLE TRAIL PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consists of natural gas pipeline costs and fixed assets, as follows (in thousands):

	March 31,			December 31,
	2018			2017
Natural gas pipeline costs
Natural gas pipeline	$	706,982		$	706,980
Natural gas pipeline construction-in-progress	109			86
Accumulated depreciation	(151,750		)	(147,206		)
Total natural gas pipeline costs, net	555,341			559,860
Fixed assets
Fixed assets	7,290			7,290
Accumulated depreciation	(6,780		)	(6,616		)
Total fixed assets, net	510			674
Property, plant and equipment, net	$	555,851		$	560,534

Depreciation expense was $4.7 million and $4.8 million during the three months ended March 31, 2018 and 2017, respectively.

NOTE 4—ACCRUED LIABILITIES

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

	March 31,		December 31,
	2018		2017
Pipeline costs	$	35	$	179
Taxes other than income	3,675		—
Other	303		40
Total accrued liabilities	$	4,013	$	219

NOTE 5—REVENUES FROM CONTRACTS WITH CUSTOMERS

SPL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of adequate natural gas feedstock to the Sabine Pass LNG terminal. These agreements have a primary term through September 2036, with the right for SPL to extend the term of the agreements for up to two consecutive ten-year terms. Thereafter, the agreements continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. SPL has continuous access to its firm transportation capacity during the contract term but has no ability to defer unused capacity to future periods. SPL pays fixed fees of approximately $82 million per year to reserve the right to transport natural gas up to maximum contractually specified levels, regardless of the quantities that SPL actually transports.

Because we are continuously available to provide transportation service on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to SPL on a continuous basis over time. Because our rights to consideration corresponds directly with the value of the incremental service performed, we have elected to recognize revenue when we have the right to invoice SPL for services performed to date, which results in a substantially straight-line recognition pattern over the term of the contract.

75

CHENIERE CREOLE TRAIL PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
Revenues—affiliate	$	1.5	9.2

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

We omit from the table above all variable consideration expected to be recognized through our use of the right to invoice election.

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

NOTE 6—RELATED PARTY TRANSACTIONS

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

	Three Months Ended March 31,
	2018			2017
Revenues—affiliate
Transportation Agreements	$	20,420		$	20,415
Other agreements	—			1
Total revenues—affiliate	20,420			20,416
Operating and maintenance expense—affiliate
Services Agreements	2,190			2,678
Operational Balancing Agreements	(407		)	2,979
Total operating and maintenance expense—affiliate	1,783			5,657
General and administrative expense—affiliate
Services Agreements	202			242

We had $2.0 million and $3.9 million of advances to affiliates and $0.7 million and $4.0 million of accrued liabilities—affiliate as of March 31, 2018 and December 31, 2017, respectively, under the services agreements described below.

Services Agreements

Operation and Maintenance Agreement

We have a long-term operation and maintenance agreement (the “O&M Agreement”) with Cheniere Investments pursuant to which we receive all necessary services required to operate and maintain the Creole Trail Pipeline. We are required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses. Cheniere Investments meets its obligations under the O&M Agreement with resources provided by a wholly owned subsidiary of Cheniere pursuant to a secondment agreement. All payments received by Cheniere Investments under the O&M Agreement are required to be remitted to such subsidiary.

76

CHENIERE CREOLE TRAIL PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Investments Information Technology Services Agreement

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

Operational Balancing Agreements

We have Operational Balancing Agreements (“OBAs”) with SPLNG and SPL that provide for the resolution of any operational imbalances (1) during the term of the agreement on an in-kind basis and (2) upon termination of the agreement by cash-out at a rate equivalent to the average of the midpoint prices for Henry Hub, Louisiana pricing published in “Gas Daily’s-Daily Price Survey” for each day of the month following termination. The SPLNG OBA became effective following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, and the SPL OBA became effective in April 2015. As of March 31, 2018 and December 31, 2017, we had $0.2 million and $0.6 million, respectively, of other current liabilities—affiliate under the operational balancing agreements.

Transportation Agreements

SPL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of adequate natural gas feedstock to the Sabine Pass LNG terminal. See Note 5—Revenues from Contracts with Customers for information regarding these agreements. As of both March 31, 2018 and December 31, 2017, we had $6.8 million of accounts receivable—affiliate under the transportation agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after May 2013.

NOTE 7—SUPPLEMENTAL CASH FLOW INFORMATION

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $0.2 million as of both March 31, 2018 and 2017.

NOTE 8—GUARANTEES

Cheniere Partners has a credit and guaranty agreement aggregating $2.8 billion (the “2016 CQP Credit Facilities”), which includes a $450.0 million CTPL tranche term loan that was used to satisfy our obligations under an existing term loan in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LNG-LP, LLC, a wholly owned subsidiary of Cheniere Partners, subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’

77

CHENIERE CREOLE TRAIL PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of March 31, 2018, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us, and the real property of Sabine Pass LNG, L.P. (except for certain excluded properties).

NOTE 9—RECENT ACCOUNTING STANDARDS

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

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

78

CHENIERE CREOLE TRAIL PIPELINE, L.P.

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

Standard	Description	Date of Adoption	Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 5—Revenues from Contracts with Customers for additional disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory	This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.	January 1, 2018	The adoption of this guidance did not have an impact on our Financial Statements or related disclosures.

NOTE 10—REGULATORY EVENTS

Recent Federal Energy Regulatory Commission (“FERC”) Developments

On March 15, 2018, the FERC issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (“MLP”) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in Tax Reform and this policy statement. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are currently evaluating the impact of these developments and continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform.

79

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	Cheniere Energy Partners, L.P.
Entity Central Index Key	0001383650
Document Type	8-K
Document Period End Date	Mar. 31, 2018
Amendment Flag	false

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 0	$ 0
Restricted cash	1,477	1,589
Accounts and other receivables	240	191
Accounts receivable—affiliate	114	163
Advances to affiliate	97	36
Inventory	83	95
Other current assets	54	65
Total current assets	2,065	2,139
Property, plant and equipment, net	15,145	15,139
Debt issuance costs, net	34	38
Non-current derivative assets	24	31
Other non-current assets, net	197	206
Total assets	17,465	17,553
Current liabilities
Accounts payable	11	12
Accrued liabilities	509	637
Due to affiliates	30	68
Deferred revenue	95	111
Deferred revenue—affiliate	0	1
Derivative liabilities	4	0
Total current liabilities	649	829
Long-term debt, net	16,052	16,046
Non-current deferred revenue	0	1
Non-current derivative liabilities	3	3
Other non-current liabilities	11	10
Other non-current liabilities—affiliate	25	25
Partners’ equity
Common unitholders’ interest (348.6 million units issued and outstanding at March 31, 2018 and December 31, 2017)	1,731	1,670
Subordinated unitholders’ interest (135.4 million units issued and outstanding at March 31, 2018 and December 31, 2017)	(1,019)	(1,043)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at March 31, 2018 and December 31, 2017)	13	12
Total partners’ equity	725	639
Total liabilities and partners’ equity (deficit)	$ 17,465	$ 17,553

XML

Consolidated Balance Sheets Parentheticals - shares shares in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
General Partner Ownership Interest Percentage	2.00%	2.00%
General Partners' Capital Account, Units Issued	9.9	9.9
General partner units outstanding	9.9	9.9
Common Units [Member]
Limited Partners' Capital Account, Units Issued	348.6	348.6
Partnership unitholders units outstanding	348.6	348.6
Subordinated Units [Member]
Limited Partners' Capital Account, Units Issued	135.4	135.4
Partnership unitholders units outstanding	135.4	135.4

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues
LNG revenues	$ 1,015	$ 492
LNG revenues—affiliate	503	331
Regasification revenues	65	65
Other revenues	10	2
Other revenues—affiliate	0	1
Total revenues	1,593	891
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	837	513
Operating and maintenance expense	95	50
Operating and maintenance expense—affiliate	26	18
General and administrative expense	4	3
General and administrative expense—affiliate	18	22
Depreciation and amortization expense	105	66
Total operating costs and expenses	1,085	672
Income (loss) from operations	508	219
Other income (expense)
Interest expense, net of capitalized interest	(185)	(130)
Loss on early extinguishment of debt	0	(42)
Derivative gain, net	8	0
Other income	4	0
Total other income (expense)	(173)	(172)
Net income (loss)	$ 335	$ 47
Basic and diluted net income (loss) per common unit	$ 0.67	$ (0.80)
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation	348.6	57.1

XML

Consolidated Statement of Partners' Equity - 3 months ended Mar. 31, 2018 - USD ($) shares in Millions, $ in Millions	Total	Common Units [Member]	Subordinated Units [Member]	General Partner [Member]
Units, Outstanding, beginning of period at Dec. 31, 2017		348.6	135.4
Partners' equity, beginning of period at Dec. 31, 2017	$ 639	$ 1,670	$ (1,043)	$ 12
General partner units, Outstanding, beginning of period at Dec. 31, 2017	9.9			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 335	236	92	$ 7
Distributions	(249)	$ (175)	$ (68)	(6)
Units, Outstanding, end of period at Mar. 31, 2018		348.6	135.4
Partners' equity, end of period at Mar. 31, 2018	$ 725	$ 1,731	$ (1,019)	$ 13
General partner units, Outstanding, end of period at Mar. 31, 2018	9.9			9.9

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities
Net income	$ 335	$ 47
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	105	66
Amortization of debt issuance costs, deferred commitment fees, premium and discount	8	10
Loss on early extinguishment of debt	0	42
Total losses on derivatives, net	42	39
Net cash used for settlement of derivative instruments	(3)	(13)
Other	2	0
Changes in operating assets and liabilities:
Accounts and other receivables	(50)	(11)
Accounts receivable—affiliate	48	59
Advances to affiliate	(56)	(41)
Inventory	12	17
Accounts payable and accrued liabilities	(69)	(38)
Due to affiliates	(25)	(68)
Deferred revenue	(18)	(11)
Other, net	0	1
Other, net—affiliate	0	16
Net cash provided by operating activities	331	115
Cash flows from investing activities
Property, plant and equipment, net	(194)	(524)
Net cash provided by (used in) investing activities	(194)	(524)
Cash flows from financing activities
Proceeds from issuances of debt	0	2,314
Repayments of debt	0	(703)
Debt issuance and deferred financing costs	0	(26)
Distributions to owners	(249)	(25)
Net cash provided by (used in) financing activities	(249)	1,560
Net increase (decrease) in cash, cash equivalents and restricted cash	(112)	1,151
Cash, cash equivalents and restricted cash—beginning of period	1,589	605
Cash, cash equivalents and restricted cash—end of period	$ 1,477	$ 1,756

XML

Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheet - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	$ 0	$ 0
Restricted cash	1,477	1,589
Total cash, cash equivalents and restricted cash	$ 1,477	$ 1,589	$ 1,756	$ 605

XML

Nature of Operations and Basis of Presentation

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. We also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL. 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, 2017. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

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

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

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

XML

Unitholders' Equity

3 Months Ended

Mar. 31, 2018

Partners' Capital Notes [Abstract]

Unitholders' Equity

UNITHOLDERS’ EQUITY

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

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

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

Cheniere Holdings, Blackstone CQP Holdco and the public own a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere Holdings’ ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.

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Restricted Cash

3 Months Ended

Mar. 31, 2018

Restricted Cash [Abstract]

Restricted Cash

RESTRICTED CASH

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

	March 31,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	561	$	544
CQP and cash held by guarantor subsidiaries	916		1,045
Total current restricted cash	$	1,477	$	1,589

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

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Accounts and Other Receivables

3 Months Ended

Mar. 31, 2018

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

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

	March 31,		December 31,
	2018		2017
SPL trade receivable	$	232	$	185
Other accounts receivable	8		6
Total accounts and other receivables	$	240	$	191

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.

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Inventory

3 Months Ended

Mar. 31, 2018

Inventory Disclosure [Abstract]

Inventory

INVENTORY

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

	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	14		26
Materials and other	53		52
Total inventory	$	83	$	95

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	12,690		$	12,703
LNG terminal construction-in-process	3,431			3,310
Accumulated depreciation	(982		)	(880		)
Total LNG terminal costs, net	15,139			15,133
Fixed assets
Fixed assets	23			23
Accumulated depreciation	(17		)	(17		)
Total fixed assets, net	6			6
Property, plant and equipment, net	$	15,145		$	15,139

Depreciation expense was $102 million and $64 million during the three months ended March 31, 2018 and 2017, respectively.

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

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Derivative Instruments

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

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

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

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

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

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

	Fair Value Measurements as of
	March 31, 2018								December 31, 2017
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
CQP Interest Rate Derivatives asset	$	—	$	27	$	—	$	27	$	—	$	21	$	—	$	21
Liquefaction Supply Derivatives asset	—		—		10		10		2		10		43		55

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

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

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

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

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

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

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

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

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

Interest Rate Derivatives

During the three months ended March 31, 2018, there were no changes to the terms of the interest rate swaps (“CQP Interest Rate Derivatives”) we entered into to protect against volatility of future cash flows and hedge a portion of the variable interest payments on 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, 2017 for additional information.

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 of March 31, 2018, we had the following Interest Rate Derivatives outstanding:

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

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

	March 31,		December 31,
Balance Sheet Location	2018		2017
Other current assets	$	12	$	7
Non-current derivative assets	15		14
Total derivative assets	$	27	$	21

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

	Three Months Ended March 31,
	2018		2017
CQP Interest Rate Derivatives gain	$	8	$	2
SPL Interest Rate Derivatives loss	—		(2		)

Liquefaction Supply Derivatives

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

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

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

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

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

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

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

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

Consolidated Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2018
CQP Interest Rate Derivatives	$	27		$	—		$	27
Liquefaction Supply Derivatives	25			(8		)	17
Liquefaction Supply Derivatives	(9		)	2			(7		)
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

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Other Non-Current Assets

3 Months Ended

Mar. 31, 2018

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

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

	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	25		25
Information technology service assets	23		24
Other	9		8
Total other non-current assets, net	$	197	$	206

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Accrued Liabilities

3 Months Ended

Mar. 31, 2018

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

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

	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	186	$	253
Sabine Pass LNG terminal and related pipeline costs	319		384
Other accrued liabilities	4		—
Total accrued liabilities	$	509	$	637

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Debt

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Debt

DEBT

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

	March 31,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
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 $5	1,505			1,505
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 $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
2016 CQP Credit Facilities	1,090			1,090
Unamortized debt issuance costs	(197		)	(204		)
Total long-term debt, net	16,052			16,046
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	16,052		$	16,046

Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2018 (in millions):

	SPL Working Capital Facility		2016 CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Less:
Outstanding balance	—		1,090
Commitments prepaid or terminated	—		1,470
Letters of credit issued	706		20
Available commitment	$	494	$	220
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 principal payments due quarterly commencing on March 31, 2019

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

Restrictive Debt Covenants

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

Interest Expense

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

	Three Months Ended March 31,
	2018			2017
Total interest cost	$	232		$	211
Capitalized interest	(47		)	(81		)
Total interest expense, net	$	185		$	130

Fair Value Disclosures

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

	March 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	14,359	$	15,116	$	14,360	$	15,485
2037 SPL Senior Notes (2)	800		838		800		871
Credit facilities (3)	1,090		1,090		1,090		1,090

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

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

(3) Includes SPL Working Capital Facility and 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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Revenues from Contracts with Customers

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenues from Contracts with Customers

REVENUES FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues	$	996	$	485
LNG revenues—affiliate	503		331
Regasification revenues	65		65
Other revenues	10		2
Other revenues—affiliate	—		1
Total revenues from customers	1,574		884
Revenues from derivative instruments	19		7
Total revenues	$	1,593	$	891

LNG Revenues

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

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

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

Regasification Revenues

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

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

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

Upon substantial completion of Train 3, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During the three months ended March 31, 2018 and 2017, SPL recorded $8 million and zero as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

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

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	111		$	73
Cash received but not yet recognized	95			61
Revenue recognized from prior period deferral	(111		)	(71		)
Deferred revenues, end of period	$	95		$	63

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

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	55.2	10.0
Regasification revenues	2.8		5.6
Total revenues	$	58.0

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

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. The receipt of such variable consideration is considered constrained due to the uncertainty of ultimate pricing and receipt and we have not included such variable consideration in the transaction price. During the three months ended March 31, 2018, approximately 56% of our LNG Revenues, 100% of our LNG revenues—affiliate and approximately 3% of our Regasification Revenues were related to variable consideration received from customers.

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

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

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Related Party Transactions

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

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

	Three Months Ended March 31,
	2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	503	$	331
Other revenues—affiliate
Terminal Marine Services Agreement	—		1
Operating and maintenance expense—affiliate
Services Agreements	26		18
General and administrative expense—affiliate
Services Agreements	18		22

LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least 20 years after May 2016.

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

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments 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 Consolidated Financial Statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA.

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing during the three months ended March 31, 2018 and 2017, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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

Cheniere Marketing Master SPA

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

Commissioning Confirmation

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

Services Agreements

As of March 31, 2018 and December 31, 2017, we had $97 million and $36 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 a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $3 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Cheniere Investments Information Technology Services Agreement

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

SPLNG O&M Agreement

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

SPLNG MSA

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

SPL O&M Agreement

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

SPL MSA

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

CTPL O&M Agreement

CTPL has an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse 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.

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, 2018 and December 31, 2017, 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.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the three months ended March 31, 2018 and 2017.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

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

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013.

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Net Income (Loss) per Common Unit

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Net Income (Loss) per Common Unit

NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statement of Partners’ Equity. On April 27, 2018, we declared a $0.55 distribution per common unit and subordinated unit and the related distribution to our general partner and IDR holders to be paid on May 15, 2018 to unitholders of record as of May 7, 2018 for the period from January 1, 2018 to March 31, 2018.

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

The Class B units, which were mandatorily converted into our common units in accordance with the terms of our partnership agreement on August 2, 2017, were issued at a discount to the market price of the common units into which they were convertible.  This discount, totaling $2,130 million, represented a beneficial conversion feature and was reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statement of Partners’ Equity.  The beneficial conversion feature was considered a dividend that was distributed ratably with respect to any Class B unit from its issuance date through its conversion date, which resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortized the beneficial conversion feature through the mandatory conversion date of August 2, 2017 using the effective yield method, with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature was also included in earnings per unit for the three months ended March 31, 2017.

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

			Limited Partner Units
	Total		Common Units			Class B Units		Subordinated Units			General Partner Units		IDR
Three Months Ended March 31, 2018
Net income	$	335
Declared distributions	278		192			—		74			6		6
Assumed allocation of undistributed net income (1)	$	57	40			—		16			1		—
Assumed allocation of net income			$	232		$	—	$	90		$	7	$	6
Weighted average units outstanding			348.6			—		135.4
Net income per unit (2)			$	0.67				$	0.67
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			$	(46	)	$	235	$	(143	)	$	1	$	—
Weighted average units outstanding			57.1			145.3		135.4
Net loss per unit (2)			$	(0.80	)			$	(1.06	)

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

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

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Customer Concentration

3 Months Ended

Mar. 31, 2018

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

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

	Percentage of Total Third-Party Revenues		Percentage of Accounts Receivable from Third Parties
	Three Months Ended March 31,		March 31,	December 31,
	2018	2017	2018	2017
Customer A	31%	54%	33%	39%
Customer B	25%	29%	19%	32%
Customer C	25%	—%	19%	26%
Customer D	*	—%	26%	—%

* Less than 10%

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	242	$	175

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $200 million and $316 million as of March 31, 2018 and 2017, respectively.

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Recent Accounting Standards

3 Months Ended

Mar. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards

RECENT ACCOUNTING STANDARDS

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

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and 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. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we anticipate a material impact from the requirement to recognize all leases 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. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

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

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

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Supplemental Guarantor Information

3 Months Ended

Mar. 31, 2018

Supplemental Guarantor Financial Information [Abstract]

Supplemental Guarantor Information

SUPPLEMENTAL GUARANTOR INFORMATION

Our 2025 CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (the “CQP Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the CQP Indenture. See Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2017 for additional information regarding the 2025 CQP Senior Notes.

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

Condensed Consolidating Balance Sheet
March 31, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantor		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	903		13		561		—			1,477
Accounts and other receivables	1		1		238		—			240
Accounts receivable—affiliate	—		26		114		(26		)	114
Advances to affiliate	—		76		91		(70		)	97
Inventory	—		11		72		—			83
Other current assets	13		3		38		—			54
Other current assets—affiliate	—		—		22		(22		)	—
Total current assets	917		130		1,136		(118		)	2,065
Property, plant and equipment, net	79		2,157		12,933		(24		)	15,145
Debt issuance costs, net	18		—		16		—			34
Non-current derivative assets	15		—		9		—			24
Investments in subsidiaries	2,308		180		—		(2,488		)	—
Other non-current assets, net	—		38		159		—			197
Total assets	$	3,337	$	2,505	$	14,253	$	(2,630	)	$	17,465
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4	$	7	$	—		$	11
Accrued liabilities	43		15		451		—			509
Due to affiliates	—		94		32		(96		)	30
Deferred revenue	—		26		69		—			95
Deferred revenue—affiliate	—		22		—		(22		)	—
Derivative liabilities	—		—		4		—			4
Total current liabilities	43		161		563		(118		)	649
Long-term debt, net	2,569		—		13,483		—			16,052
Non-current derivative liabilities	—		—		3		—			3
Other non-current liabilities	—		11		—		—			11
Other non-current liabilities—affiliate	—		25		—		—			25
Partners’ equity	725		2,308		204		(2,512		)	725
Total liabilities and partners’ equity	$	3,337	$	2,505	$	14,253	$	(2,630	)	$	17,465

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

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,015		$	—		$	1,015
LNG revenues—affiliate	—			—			503			—			503
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			64			—			(64		)	—
Other revenues	—			10			—			—			10
Other revenues—affiliate	—			55			—			(55		)	—
Total revenues	—			194			1,518			(119		)	1,593
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			838			(1		)	837
Cost of sales—affiliate	—			—			8			(8		)	—
Operating and maintenance expense	—			17			78			—			95
Operating and maintenance expense—affiliate	—			32			103			(109		)	26
General and administrative expense	1			1			2			—			4
General and administrative expense—affiliate	3			4			12			(1		)	18
Depreciation and amortization expense	1			18			86			—			105
Total operating costs and expenses	5			72			1,127			(119		)	1,085
Income (loss) from operations	(5		)	122			391			—			508
Other income (expense)
Interest expense, net of capitalized interest	(34		)	—			(151		)	—			(185		)
Derivative gain, net	8			—			—			—			8
Equity earnings of subsidiaries	363			242			—			(605		)	—
Other income (expense)	3			(1		)	2			—			4
Total other income (expense)	340			241			(149		)	(605		)	(173		)
Net income	$	335		$	363		$	242		$	(605	)	$	335

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	492		$	—		$	492
LNG revenues—affiliate	—			—			331			—			331
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			33			—			(33		)	—
Other revenues	—			2			—			—			2
Other revenues—affiliate	—			51			—			(50		)	1
Total revenues	—			151			823			(83		)	891
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			510			3			513
Cost of sales—affiliate	—			—			4			(4		)	—
Operating and maintenance expense	1			10			39			—			50
Operating and maintenance expense—affiliate	—			34			59			(75		)	18
General and administrative expense	1			—			2			—			3
General and administrative expense—affiliate	3			3			17			(1		)	22
Depreciation and amortization expense	—			19			47			—			66
Total operating costs and expenses	5			66			678			(77		)	672
Income (loss) from operations	(5		)	85			145			(6		)	219
Other income (expense)
Interest expense, net of capitalized interest	(25		)	—			(105		)	—			(130		)
Loss on early extinguishment of debt	—			—			(42		)	—			(42		)
Derivative gain (loss), net	2			—			(2		)	—			—
Equity earnings (losses) of subsidiaries	75			(4		)	—			(71		)	—
Total other income (expense)	52			(4		)	(149		)	(71		)	(172		)
Net income (loss)	$	47		$	81		$	(4	)	$	(77	)	$	47

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(10	)	$	135		$	206		$	—		$	331
Cash flows from investing activities
Property, plant and equipment, net	—			(5		)	(189		)	—			(194		)
Investments in subsidiaries	(38		)	—			—			38			—
Distributions received from affiliates, net	167			—			—			(167		)	—
Net cash provided by (used in) investing activities	129			(5		)	(189		)	(129		)	(194		)
Cash flows from financing activities
Distributions to parent	—			(167		)	—			167			—
Contributions from parent	—			38			—			(38		)	—
Distributions to owners	(249		)	—			—			—			(249		)
Net cash used in financing activities	(249		)	(129		)	—			129			(249		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(130		)	1			17			—			(112		)
Cash, cash equivalents and restricted cash—beginning of period	1,033			12			544			—			1,589
Cash, cash equivalents and restricted cash—end of period	$	903		$	13		$	561		$	—		$	1,477

Balances per Condensed Consolidating Balance Sheet:

	March 31, 2018
	Parent Issuer		Guarantors		Non-Guarantor		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Restricted cash	903		13		561		—		1,477
Total cash, cash equivalents and restricted cash	$	903	$	13	$	561	$	—	$	1,477

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(29	)	$	32		$	116		$	(4	)	$	115
Cash flows from investing activities
Property, plant and equipment, net	—			—			(528		)	4			(524		)
Investments in subsidiaries	(127		)	—			—			127			—
Distributions received from affiliates, net	159			—			—			(159		)	—
Net cash provided by (used in) investing activities	32			—			(528		)	(28		)	(524		)
Cash flows from financing activities
Proceeds from issuances of debt	—			—			2,314			—			2,314
Repayments of debt	—			—			(703		)	—			(703		)
Debt issuance and deferred financing costs	—			—			(26		)	—			(26		)
Distributions to parent	—			(159		)	—			159			—
Contributions from parent	—			127			—			(127		)	—
Distributions to owners	(25		)	—			—			—			(25		)
Net cash provided by (used in) financing activities	(25		)	(32		)	1,585			32			1,560
Net increase (decrease) in cash, cash equivalents and restricted cash	(22		)	—			1,173			—			1,151
Cash, cash equivalents and restricted cash—beginning of period	234			13			358			—			605
Cash, cash equivalents and restricted cash—end of period	$	212		$	13		$	1,531		$	—		$	1,756

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Nature of Operations and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

Basis of Presentation

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

Income Taxes, Policy

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

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Restricted Cash (Tables)

3 Months Ended

Mar. 31, 2018

Restricted Cash [Abstract]

Schedule of Restricted Cash

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

	March 31,		December 31,
	2018		2017
Current restricted cash
Liquefaction Project	$	561	$	544
CQP and cash held by guarantor subsidiaries	916		1,045
Total current restricted cash	$	1,477	$	1,589

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Accounts and Other Receivables (Tables)

3 Months Ended

Mar. 31, 2018

Receivables [Abstract]

Schedule of Accounts and Other Receivables

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

	March 31,		December 31,
	2018		2017
SPL trade receivable	$	232	$	185
Other accounts receivable	8		6
Total accounts and other receivables	$	240	$	191

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Inventory (Tables)

3 Months Ended

Mar. 31, 2018

Inventory Disclosure [Abstract]

Schedule of Inventory

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

	March 31,		December 31,
	2018		2017
Natural gas	$	16	$	17
LNG	14		26
Materials and other	53		52
Total inventory	$	83	$	95

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

	March 31,			December 31,
	2018			2017
LNG terminal costs
LNG terminal	$	12,690		$	12,703
LNG terminal construction-in-process	3,431			3,310
Accumulated depreciation	(982		)	(880		)
Total LNG terminal costs, net	15,139			15,133
Fixed assets
Fixed assets	23			23
Accumulated depreciation	(17		)	(17		)
Total fixed assets, net	6			6
Property, plant and equipment, net	$	15,145		$	15,139

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

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

	Fair Value Measurements as of
	March 31, 2018								December 31, 2017
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
CQP Interest Rate Derivatives asset	$	—	$	27	$	—	$	27	$	—	$	21	$	—	$	21
Liquefaction Supply Derivatives asset	—		—		10		10		2		10		43		55

Fair Value Inputs, Assets, Quantitative Information

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

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

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

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

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

Derivative Net Presentation on Consolidated Balance Sheets

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of March 31, 2018
CQP Interest Rate Derivatives	$	27		$	—		$	27
Liquefaction Supply Derivatives	25			(8		)	17
Liquefaction Supply Derivatives	(9		)	2			(7		)
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of March 31, 2018, we had the following Interest Rate Derivatives outstanding:

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

Fair Value of Derivative Instruments by Balance Sheet Location

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

	March 31,		December 31,
Balance Sheet Location	2018		2017
Other current assets	$	12	$	7
Non-current derivative assets	15		14
Total derivative assets	$	27	$	21

Derivative Instruments, Gain (Loss)

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

	Three Months Ended March 31,
	2018		2017
CQP Interest Rate Derivatives gain	$	8	$	2
SPL Interest Rate Derivatives loss	—		(2		)

Liquefaction Supply Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Instruments by Balance Sheet Location

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

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

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

Derivative Instruments, Gain (Loss)

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

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

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

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

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Other Non-Current Assets (Tables)

3 Months Ended

Mar. 31, 2018

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

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

	March 31,		December 31,
	2018		2017
Advances made under EPC and non-EPC contracts	$	18	$	26
Advances made to municipalities for water system enhancements	93		93
Advances and other asset conveyances to third parties to support LNG terminals	29		30
Tax-related payments and receivables	25		25
Information technology service assets	23		24
Other	9		8
Total other non-current assets, net	$	197	$	206

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Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

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

	March 31,		December 31,
	2018		2017
Interest costs and related debt fees	$	186	$	253
Sabine Pass LNG terminal and related pipeline costs	319		384
Other accrued liabilities	4		—
Total accrued liabilities	$	509	$	637

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Debt (Tables)

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Schedule of Debt Instruments

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

	March 31,			December 31,
	2018			2017
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $5 and $6	$	2,005		$	2,006
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 $5	1,505			1,505
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 $1	1,349			1,349
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
2016 CQP Credit Facilities	1,090			1,090
Unamortized debt issuance costs	(197		)	(204		)
Total long-term debt, net	16,052			16,046
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	16,052		$	16,046

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2018 (in millions):

	SPL Working Capital Facility		2016 CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Less:
Outstanding balance	—		1,090
Commitments prepaid or terminated	—		1,470
Letters of credit issued	706		20
Available commitment	$	494	$	220
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 principal payments due quarterly commencing on March 31, 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,
	2018			2017
Total interest cost	$	232		$	211
Capitalized interest	(47		)	(81		)
Total interest expense, net	$	185		$	130

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	March 31, 2018				December 31, 2017
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	14,359	$	15,116	$	14,360	$	15,485
2037 SPL Senior Notes (2)	800		838		800		871
Credit facilities (3)	1,090		1,090		1,090		1,090

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

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

(3) Includes SPL Working Capital Facility and 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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Revenues from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended March 31,
	2018		2017
LNG revenues	$	996	$	485
LNG revenues—affiliate	503		331
Regasification revenues	65		65
Other revenues	10		2
Other revenues—affiliate	—		1
Total revenues from customers	1,574		884
Revenues from derivative instruments	19		7
Total revenues	$	1,593	$	891

Contract Balances Reconciliation

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

	Three Months Ended March 31,
	2018			2017
Deferred revenues, beginning of period	$	111		$	73
Cash received but not yet recognized	95			61
Revenue recognized from prior period deferral	(111		)	(71		)
Deferred revenues, end of period	$	95		$	63

Transaction Price Allocated to Future Performance Obligations

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

	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	55.2	10.0
Regasification revenues	2.8		5.6
Total revenues	$	58.0

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

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

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

	Three Months Ended March 31,
	2018		2017
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	503	$	331
Other revenues—affiliate
Terminal Marine Services Agreement	—		1
Operating and maintenance expense—affiliate
Services Agreements	26		18
General and administrative expense—affiliate
Services Agreements	18		22

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Net Income (Loss) per Common Unit (Tables)

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Schedule of Net Income (Loss) per Common Unit

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

			Limited Partner Units
	Total		Common Units			Class B Units		Subordinated Units			General Partner Units		IDR
Three Months Ended March 31, 2018
Net income	$	335
Declared distributions	278		192			—		74			6		6
Assumed allocation of undistributed net income (1)	$	57	40			—		16			1		—
Assumed allocation of net income			$	232		$	—	$	90		$	7	$	6
Weighted average units outstanding			348.6			—		135.4
Net income per unit (2)			$	0.67				$	0.67
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			$	(46	)	$	235	$	(143	)	$	1	$	—
Weighted average units outstanding			57.1			145.3		135.4
Net loss per unit (2)			$	(0.80	)			$	(1.06	)

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

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

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Customer Concentration (Tables)

3 Months Ended

Mar. 31, 2018

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

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

	Percentage of Total Third-Party Revenues		Percentage of Accounts Receivable from Third Parties
	Three Months Ended March 31,		March 31,	December 31,
	2018	2017	2018	2017
Customer A	31%	54%	33%	39%
Customer B	25%	29%	19%	32%
Customer C	25%	—%	19%	26%
Customer D	*	—%	26%	—%

* Less than 10%

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Three Months Ended March 31,
	2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	242	$	175

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Recent Accounting Standards (Tables)

3 Months Ended

Mar. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent Accounting Standards, Not Yet Adopted

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

Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and 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. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we anticipate a material impact from the requirement to recognize all leases 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. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

Recent Accounting Standards, Adopted

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

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

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Supplemental Guarantor Information (Tables)

3 Months Ended

Mar. 31, 2018

Supplemental Guarantor Financial Information [Abstract]

Condensed Consolidating Balance Sheets

Condensed Consolidating Balance Sheet
March 31, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantor		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	903		13		561		—			1,477
Accounts and other receivables	1		1		238		—			240
Accounts receivable—affiliate	—		26		114		(26		)	114
Advances to affiliate	—		76		91		(70		)	97
Inventory	—		11		72		—			83
Other current assets	13		3		38		—			54
Other current assets—affiliate	—		—		22		(22		)	—
Total current assets	917		130		1,136		(118		)	2,065
Property, plant and equipment, net	79		2,157		12,933		(24		)	15,145
Debt issuance costs, net	18		—		16		—			34
Non-current derivative assets	15		—		9		—			24
Investments in subsidiaries	2,308		180		—		(2,488		)	—
Other non-current assets, net	—		38		159		—			197
Total assets	$	3,337	$	2,505	$	14,253	$	(2,630	)	$	17,465
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4	$	7	$	—		$	11
Accrued liabilities	43		15		451		—			509
Due to affiliates	—		94		32		(96		)	30
Deferred revenue	—		26		69		—			95
Deferred revenue—affiliate	—		22		—		(22		)	—
Derivative liabilities	—		—		4		—			4
Total current liabilities	43		161		563		(118		)	649
Long-term debt, net	2,569		—		13,483		—			16,052
Non-current derivative liabilities	—		—		3		—			3
Other non-current liabilities	—		11		—		—			11
Other non-current liabilities—affiliate	—		25		—		—			25
Partners’ equity	725		2,308		204		(2,512		)	725
Total liabilities and partners’ equity	$	3,337	$	2,505	$	14,253	$	(2,630	)	$	17,465

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

Condensed Consolidating Statements of Operations

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,015		$	—		$	1,015
LNG revenues—affiliate	—			—			503			—			503
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			64			—			(64		)	—
Other revenues	—			10			—			—			10
Other revenues—affiliate	—			55			—			(55		)	—
Total revenues	—			194			1,518			(119		)	1,593
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			838			(1		)	837
Cost of sales—affiliate	—			—			8			(8		)	—
Operating and maintenance expense	—			17			78			—			95
Operating and maintenance expense—affiliate	—			32			103			(109		)	26
General and administrative expense	1			1			2			—			4
General and administrative expense—affiliate	3			4			12			(1		)	18
Depreciation and amortization expense	1			18			86			—			105
Total operating costs and expenses	5			72			1,127			(119		)	1,085
Income (loss) from operations	(5		)	122			391			—			508
Other income (expense)
Interest expense, net of capitalized interest	(34		)	—			(151		)	—			(185		)
Derivative gain, net	8			—			—			—			8
Equity earnings of subsidiaries	363			242			—			(605		)	—
Other income (expense)	3			(1		)	2			—			4
Total other income (expense)	340			241			(149		)	(605		)	(173		)
Net income	$	335		$	363		$	242		$	(605	)	$	335

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	492		$	—		$	492
LNG revenues—affiliate	—			—			331			—			331
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			33			—			(33		)	—
Other revenues	—			2			—			—			2
Other revenues—affiliate	—			51			—			(50		)	1
Total revenues	—			151			823			(83		)	891
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			510			3			513
Cost of sales—affiliate	—			—			4			(4		)	—
Operating and maintenance expense	1			10			39			—			50
Operating and maintenance expense—affiliate	—			34			59			(75		)	18
General and administrative expense	1			—			2			—			3
General and administrative expense—affiliate	3			3			17			(1		)	22
Depreciation and amortization expense	—			19			47			—			66
Total operating costs and expenses	5			66			678			(77		)	672
Income (loss) from operations	(5		)	85			145			(6		)	219
Other income (expense)
Interest expense, net of capitalized interest	(25		)	—			(105		)	—			(130		)
Loss on early extinguishment of debt	—			—			(42		)	—			(42		)
Derivative gain (loss), net	2			—			(2		)	—			—
Equity earnings (losses) of subsidiaries	75			(4		)	—			(71		)	—
Total other income (expense)	52			(4		)	(149		)	(71		)	(172		)
Net income (loss)	$	47		$	81		$	(4	)	$	(77	)	$	47

Condensed Consolidating Statements of Cash Flows

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2018
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(10	)	$	135		$	206		$	—		$	331
Cash flows from investing activities
Property, plant and equipment, net	—			(5		)	(189		)	—			(194		)
Investments in subsidiaries	(38		)	—			—			38			—
Distributions received from affiliates, net	167			—			—			(167		)	—
Net cash provided by (used in) investing activities	129			(5		)	(189		)	(129		)	(194		)
Cash flows from financing activities
Distributions to parent	—			(167		)	—			167			—
Contributions from parent	—			38			—			(38		)	—
Distributions to owners	(249		)	—			—			—			(249		)
Net cash used in financing activities	(249		)	(129		)	—			129			(249		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(130		)	1			17			—			(112		)
Cash, cash equivalents and restricted cash—beginning of period	1,033			12			544			—			1,589
Cash, cash equivalents and restricted cash—end of period	$	903		$	13		$	561		$	—		$	1,477

Balances per Condensed Consolidating Balance Sheet:

	March 31, 2018
	Parent Issuer		Guarantors		Non-Guarantor		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Restricted cash	903		13		561		—		1,477
Total cash, cash equivalents and restricted cash	$	903	$	13	$	561	$	—	$	1,477

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2017
(in millions)
	Parent Issuer			Guarantors			Non-Guarantor			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(29	)	$	32		$	116		$	(4	)	$	115
Cash flows from investing activities
Property, plant and equipment, net	—			—			(528		)	4			(524		)
Investments in subsidiaries	(127		)	—			—			127			—
Distributions received from affiliates, net	159			—			—			(159		)	—
Net cash provided by (used in) investing activities	32			—			(528		)	(28		)	(524		)
Cash flows from financing activities
Proceeds from issuances of debt	—			—			2,314			—			2,314
Repayments of debt	—			—			(703		)	—			(703		)
Debt issuance and deferred financing costs	—			—			(26		)	—			(26		)
Distributions to parent	—			(159		)	—			159			—
Contributions from parent	—			127			—			(127		)	—
Distributions to owners	(25		)	—			—			—			(25		)
Net cash provided by (used in) financing activities	(25		)	(32		)	1,585			32			1,560
Net increase (decrease) in cash, cash equivalents and restricted cash	(22		)	—			1,173			—			1,151
Cash, cash equivalents and restricted cash—beginning of period	234			13			358			—			605
Cash, cash equivalents and restricted cash—end of period	$	212		$	13		$	1,531		$	—		$	1,756

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Nature of Operations and Basis of Presentation (Details)	3 Months Ended
	Mar. 31, 2018 mi customer trains
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	6
CTPL [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length Of Natural Gas Pipeline | mi	94
SPLNG [Member] | Customer Concentration Risk [Member] | TUA Customers [Member]
Nature of Operations and Basis of Presentation [Line Items]
Concentration Risk, Number Of Significant Customers | customer	2

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Unitholders' Equity (Details)	3 Months Ended
	Mar. 31, 2018 $ / shares
Maximum [Member]
Other Ownership Interests [Line Items]
Number of days after quarter end distribution is paid	45 days
Common Units [Member]
Other Ownership Interests [Line Items]
Distributions Per Limited Partnership Unit Outstanding, Basic	$ 0.425
General Partner [Member] | Minimum [Member]
Other Ownership Interests [Line Items]
Distributions entitled by General Partner, Percentage	2.00%
Incentive Distribution, Quarterly Distribution Additional Target Percentage	15.00%
General Partner [Member] | Maximum [Member]
Other Ownership Interests [Line Items]
Incentive Distribution, Quarterly Distribution Additional Target Percentage	50.00%
Cheniere Holdings [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	48.60%
Blackstone [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	40.30%
Public [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	9.10%

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Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 1,477	$ 1,589
Liquefaction Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	561	544
CQP and cash held by guarantor subsidiaries [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	916	$ 1,045
2016 CQP Credit Facilities [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Line Of Credit Facility, Original Borrowing Capacity	$ 2,800

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Accounts and Other Receivables (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Receivables [Abstract]
SPL trade receivable	$ 232	$ 185
Other accounts receivable	8	6
Total accounts and other receivables	$ 240	$ 191

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Inventory (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Inventory [Line Items]
Inventory	$ 83	$ 95
Natural gas [Member]
Inventory [Line Items]
Inventory	16	17
LNG [Member]
Inventory [Line Items]
Inventory	14	26
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 53	$ 52

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 15,145	$ 15,139
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(982)	(880)
Property, plant and equipment, net	15,139	15,133
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	12,690	12,703
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	3,431	3,310
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	23	23
Accumulated depreciation	(17)	(17)
Property, plant and equipment, net	$ 6	$ 6

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Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 102	$ 64
Offsets to LNG terminal costs	$ 0	$ 124

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Derivative Instruments - Narrative (Details) $ in Millions	1 Months Ended
	Mar. 31, 2017 USD ($)	Mar. 31, 2018 tbtu	Dec. 31, 2017 tbtu
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount | tbtu		1,521	1,520
SPL [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Energy Units Secured Through Natural Gas Supply Contracts | tbtu		2,179	2,214
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, 2018	Dec. 31, 2017
CQP Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 27	$ 21
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	27	21
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	10	55
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	2
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	10
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 10	$ 43

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

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

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Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - CQP Interest Rate Derivatives [Member] $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Derivative [Line Items]
Notional Amount	$ 225
Effective Date	Mar. 22, 2016
Maturity Date	Feb. 29, 2020
Weighted Average Fixed Interest Rate Paid	1.19%
Variable Interest Rate Received	One-month LIBOR
Maximum [Member]
Derivative [Line Items]
Notional Amount	$ 1,300

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Non-current derivative assets		$ 24	$ 31
Derivative liabilities		(4)	0
Non-current derivative liabilities		(3)	(3)
CQP Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		27	21
CQP Interest Rate Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		12	7
CQP Interest Rate Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		15	14
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[1]	17	58
Total derivative liabilities	[1]	(7)	(3)
Derivative asset, net	[1]	10	55
Derivative, collateral call		1	1
Liquefaction Supply Derivatives [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	8	41
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[1]	9	17
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(4)	0
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[1]	$ (3)	$ (3)

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

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
CQP Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 8	$ 2
SPL Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		0	(2)
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	$ (50)	$ (39)

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

[2] Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

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Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
CQP Interest Rate Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 27	$ 21
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Derivative Assets (Liabilities), at Fair Value, Net	27	21
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	25	64
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(8)	(6)
Derivative Assets (Liabilities), at Fair Value, Net	17	58
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(9)	(3)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	2	0
Derivative Assets (Liabilities), at Fair Value, Net	$ (7)	$ (3)

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Other Non-Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Other Assets, Noncurrent [Abstract]
Advances made under EPC and non-EPC contracts	$ 18	$ 26
Advances made to municipalities for water system enhancements	93	93
Advances and other asset conveyances to third parties to support LNG terminals	29	30
Tax-related payments and receivables	25	25
Information technology service assets	23	24
Other	9	8
Other non-current assets, net	$ 197	$ 206

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Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 186	$ 253
Sabine Pass LNG terminal and related pipeline costs	319	384
Other accrued liabilities	4	0
Total accrued liabilities	$ 509	$ 637

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Debt - Schedule of Debt Instruments (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term Debt, Net	$ 16,052,000,000	$ 16,046,000,000
Unamortized debt issuance costs	(197,000,000)	(204,000,000)
Current Debt, Working Capital Facility	0	0
Total Debt, Net	16,052,000,000	16,046,000,000
2021 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 2,005,000,000	2,006,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debt Instrument, Unamortized Premium	$ 5,000,000	6,000,000
2022 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	1,505,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debt Instrument, Unamortized Premium	$ 5,000,000	5,000,000
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	1,349,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.20%
Debt Instrument, Unamortized Discount	$ 1,000,000	1,000,000
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 800,000,000	800,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2025 CQP 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	5.25%
2016 CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Net	$ 1,090,000,000	1,090,000,000
SPL Working Capital Facility [Member]
Debt Instrument [Line Items]
Current Debt, Working Capital Facility	0	$ 0
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,200,000,000.0

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Debt - Credit Facilities Table (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Outstanding balance		$ 16,052	$ 16,046
Outstanding balance, current		0	0
SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size		1,200
Outstanding balance, current		0	0
Commitments prepaid or terminated		0
Letters of credit issued		706
Available commitment		$ 494
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date, Description		December 31, 2020, with various terms for underlying loans
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		1,090	$ 1,090
Commitments prepaid or terminated		1,470
Letters of credit issued		20
Available commitment		$ 220
Debt Instrument, Description of Variable Rate Basis	[1]	LIBOR or base rate
Debt Instrument, Maturity Date, Description		February 25, 2020, with principal payments due quarterly commencing on March 31, 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, 2018	Mar. 31, 2017
Debt Disclosure [Abstract]
Total interest cost	$ 232	$ 211
Capitalized interest	(47)	(81)
Total interest expense, net	$ 185	$ 130

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 16,052	$ 16,046
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]	14,359	14,360
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]	15,116	15,485
2037 SPL Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	800	800
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]	838	871
Credit facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[3]	1,090	1,090
Credit facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facilities, Estimated Fair Value	[3]	$ 1,090	$ 1,090

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

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

[3] Includes SPL Working Capital Facility and 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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Revenues from Contracts with Customers (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($) bcf / d item	Mar. 31, 2017 USD ($)
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
Regasification Capacity | bcf / d	4.0
Operating and maintenance expense | $	$ 95	$ 50
TUA Customers [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d	2.0
Number Of Fixed Price Contracts | item	2
TUA Customer 1 [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d	1.0
Revenue, Performance Obligation, Fixed Consideration | $	$ 125
Long-term Purchase Commitment, Period	20 years
TUA Customer 2 [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | bcf / d	1.0
Revenue, Performance Obligation, Fixed Consideration | $	$ 125
Long-term Purchase Commitment, Period	20 years
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	56.00%
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	100.00%
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	3.00%
Partial TUA Regasification Capacity [Member]
Disaggregation of Revenue [Line Items]
Operating and maintenance expense | $	$ 8	$ 0

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Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	$ 1,574	$ 884
Revenues	1,593	891
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	996	485
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	503	331
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	65	65
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	10	2
Other—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue earned from contracts with customers	0	1
Derivative Instruments [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 19	$ 7

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Revenues from Contracts with Customers - Schedule of Deferred Revenue Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	$ 111	$ 73
Cash received but not yet recognized	95	61
Revenue recognized from prior period deferral	(111)	(71)
Deferred revenues, end of period	$ 95	$ 63

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Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) $ in Billions	3 Months Ended
	Mar. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 58.0
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 55.2
Weighted Average Recognition Timing	10 years	[1]
Regasification [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	$ 2.8
Weighted Average Recognition Timing	5 years 206 days	[1]

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

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 503	$ 331
Other revenues—affiliate	0	1
Operating and maintenance expense—affiliate	26	18
General and administrative expense—affiliate	18	22
Cheniere Marketing SPA and Cheniere Marketing Master SPA [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	503	331
Terminal Marine Services Agreement [Member]
Related Party Transaction [Line Items]
Other revenues—affiliate	0	1
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	26	18
General and administrative expense—affiliate	$ 18	$ 22

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Related Party Transactions - LNG Terminal Capacity Agreements (Details)	3 Months Ended
	Mar. 31, 2018 USD ($) bcf / d $ / MMBTU	Mar. 31, 2017 USD ($)
Related Party Transaction [Line Items]
Regasification Capacity | bcf / d	4.0
Revenues—affiliate	$ 503,000,000	$ 331,000,000
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
Terminal Use Agreement [Member] | SPLNG [Member] | SPL [Member]
Related Party Transaction [Line Items]
Regasification Capacity | bcf / d	2.0
Related Party Transaction, Committed Annual Fee	$ 250,000,000
Related Party Agreement Term	20 years
Amended and Restated Variable Capacity Rights Agreement [Member] | Cheniere Marketing [Member] | Cheniere Investments [Member]
Related Party Transaction [Line Items]
Proceeds (Payments) of Gross Margin Earned, Percentage	80.00%
Revenues—affiliate	$ 0	$ 0
LNG Sale and Purchase Agreement [Member] | Cheniere Marketing [Member] | SPL [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu | $ / MMBTU	3.00

XML

Related Party Transactions - Service Agreements (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 97,000,000	$ 36,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	97,000,000	$ 36,000,000
Cheniere Partners Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Quarterly non-accountable overhead reimbursement charge	3,000,000
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | 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

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Related Party Transactions - Other Agreements (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Revenues—affiliate	$ 503,000,000	$ 331,000,000
Cooperative Endeavor Agreements [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Tax Initiative Agreement Term	10 years
Aggregate commitment under the Agreement	$ 25,000,000
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

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Net Income (Loss) per Common Unit - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
	Apr. 27, 2018	Mar. 31, 2018
Class B Units [Member]
Distribution Made to Limited Partner [Line Items]
Discount upon issuance of Class B units representing beneficial conversion feature		$ 2,130
Cheniere Holdings [Member] | Class B Units [Member] | Effective Yield Method [Member]
Distribution Made to Limited Partner [Line Items]
Amortization of Beneficial Conversion Feature of Class B Units		888.70%
Blackstone [Member] | Class B Units [Member] | Effective Yield Method [Member]
Distribution Made to Limited Partner [Line Items]
Amortization of Beneficial Conversion Feature of Class B Units		966.10%
Subsequent Event [Member] | Common Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.55
Subsequent Event [Member] | Subordinated Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.55

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Net Income (Loss) per Common Unit - Schedule of Net Income (Loss) per Unit and Allocation of Distribution (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2018		Mar. 31, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 335		$ 47
Declared distributions		278		25
Amortization of beneficial conversion feature of Class B units				0
Assumed allocation of undistributed net income		$ 57	[1]	$ 22
Weighted average units outstanding		348.6		57.1
Net income (loss) per unit		$ 0.67		$ (0.80)
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 236
Declared distributions		192		$ 24
Amortization of beneficial conversion feature of Class B units				(70)
Assumed allocation of undistributed net income		40	[1]	0
Assumed allocation of net income		$ 232		$ (46)
Weighted average units outstanding		348.6		57.1
Net income (loss) per unit	[2]	$ 0.67		$ (0.80)
Class B Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions		$ 0		$ 0
Amortization of beneficial conversion feature of Class B units				235
Assumed allocation of undistributed net income		0	[1]	0
Assumed allocation of net income		$ 0		$ 235
Weighted average units outstanding		0.0		145.3
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 92
Declared distributions		74		$ 0
Amortization of beneficial conversion feature of Class B units				(165)
Assumed allocation of undistributed net income		16	[1]	22
Assumed allocation of net income		$ 90		$ (143)
Weighted average units outstanding		135.4		135.4
Net income (loss) per unit	[2]	$ 0.67		$ (1.06)
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 7
Declared distributions		6		$ 1
Amortization of beneficial conversion feature of Class B units				0
Assumed allocation of undistributed net income		1	[1]	0
Assumed allocation of net income		7		1
IDR [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions		6		0
Amortization of beneficial conversion feature of Class B units				0
Assumed allocation of undistributed net income		0	[1]	0
Assumed allocation of net income		$ 6		$ 0

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

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

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Customer Concentration (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Customer A [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	31.00%	54.00%
Customer A [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	33.00%		39.00%
Customer B [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	25.00%	29.00%
Customer B [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%		32.00%
Customer C [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	25.00%	0.00%
Customer C [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%		26.00%
Customer D [Member] | Total Third-Party Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		0.00%
Customer D [Member] | Accounts Receivable from Third-Parties [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	26.00%		0.00%

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 242	$ 175
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 200	$ 316

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Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 0	$ 0
Restricted cash	1,477	1,589
Accounts and other receivables	240	191
Accounts receivable—affiliate	114	163
Advances to affiliate	97	36
Inventory	83	95
Other current assets	54	65
Other current assets—affiliate	0	0
Total current assets	2,065	2,139
Property, plant and equipment, net	15,145	15,139
Debt issuance costs, net	34	38
Non-current derivative assets	24	31
Investments in subsidiaries	0	0
Other non-current assets, net	197	206
Total assets	17,465	17,553
Current liabilities
Accounts payable	11	12
Accrued liabilities	509	637
Due to affiliates	30	68
Deferred revenue	95	111
Deferred revenue—affiliate	0	1
Derivative liabilities	4	0
Other current liabilities—affiliate		0
Total current liabilities	649	829
Long-term debt, net	16,052	16,046
Non-current deferred revenue	0	1
Non-current derivative liabilities	3	3
Other non-current liabilities	11	10
Other non-current liabilities—affiliate	25	25
Partners' equity (deficit)	725	639
Total liabilities and partners’ equity (deficit)	17,465	17,553
Parent Issuer [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	903	1,033
Accounts and other receivables	1	0
Accounts receivable—affiliate	0	0
Advances to affiliate	0	0
Inventory	0	0
Other current assets	13	8
Other current assets—affiliate	0	0
Total current assets	917	1,041
Property, plant and equipment, net	79	80
Debt issuance costs, net	18	20
Non-current derivative assets	15	14
Investments in subsidiaries	2,308	2,076
Other non-current assets, net	0	0
Total assets	3,337	3,231
Current liabilities
Accounts payable	0	0
Accrued liabilities	43	23
Due to affiliates	0	0
Deferred revenue	0	0
Deferred revenue—affiliate	0	0
Derivative liabilities	0
Other current liabilities—affiliate		0
Total current liabilities	43	23
Long-term debt, net	2,569	2,569
Non-current deferred revenue		0
Non-current derivative liabilities	0	0
Other non-current liabilities	0	0
Other non-current liabilities—affiliate	0	0
Partners' equity (deficit)	725	639
Total liabilities and partners’ equity (deficit)	3,337	3,231
Guarantors [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	13	12
Accounts and other receivables	1	2
Accounts receivable—affiliate	26	36
Advances to affiliate	76	20
Inventory	11	10
Other current assets	3	3
Other current assets—affiliate	0	0
Total current assets	130	83
Property, plant and equipment, net	2,157	2,164
Debt issuance costs, net	0	0
Non-current derivative assets	0	0
Investments in subsidiaries	180	(63)
Other non-current assets, net	38	37
Total assets	2,505	2,221
Current liabilities
Accounts payable	4	4
Accrued liabilities	15	8
Due to affiliates	94	47
Deferred revenue	26	27
Deferred revenue—affiliate	22	22
Derivative liabilities	0
Other current liabilities—affiliate		1
Total current liabilities	161	109
Long-term debt, net	0	0
Non-current deferred revenue		1
Non-current derivative liabilities	0	0
Other non-current liabilities	11	10
Other non-current liabilities—affiliate	25	25
Partners' equity (deficit)	2,308	2,076
Total liabilities and partners’ equity (deficit)	2,505	2,221
Non-Guarantor [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	561	544
Accounts and other receivables	238	189
Accounts receivable—affiliate	114	163
Advances to affiliate	91	26
Inventory	72	85
Other current assets	38	54
Other current assets—affiliate	22	21
Total current assets	1,136	1,082
Property, plant and equipment, net	12,933	12,920
Debt issuance costs, net	16	18
Non-current derivative assets	9	17
Investments in subsidiaries	0	0
Other non-current assets, net	159	169
Total assets	14,253	14,206
Current liabilities
Accounts payable	7	8
Accrued liabilities	451	606
Due to affiliates	32	66
Deferred revenue	69	84
Deferred revenue—affiliate	0	0
Derivative liabilities	4
Other current liabilities—affiliate		0
Total current liabilities	563	764
Long-term debt, net	13,483	13,477
Non-current deferred revenue		0
Non-current derivative liabilities	3	3
Other non-current liabilities	0	0
Other non-current liabilities—affiliate	0	0
Partners' equity (deficit)	204	(38)
Total liabilities and partners’ equity (deficit)	14,253	14,206
Eliminations [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	0	0
Accounts and other receivables	0	0
Accounts receivable—affiliate	(26)	(36)
Advances to affiliate	(70)	(10)
Inventory	0	0
Other current assets	0	0
Other current assets—affiliate	(22)	(21)
Total current assets	(118)	(67)
Property, plant and equipment, net	(24)	(25)
Debt issuance costs, net	0	0
Non-current derivative assets	0	0
Investments in subsidiaries	(2,488)	(2,013)
Other non-current assets, net	0	0
Total assets	(2,630)	(2,105)
Current liabilities
Accounts payable	0	0
Accrued liabilities	0	0
Due to affiliates	(96)	(45)
Deferred revenue	0	0
Deferred revenue—affiliate	(22)	(21)
Derivative liabilities	0
Other current liabilities—affiliate		(1)
Total current liabilities	(118)	(67)
Long-term debt, net	0	0
Non-current deferred revenue		0
Non-current derivative liabilities	0	0
Other non-current liabilities	0	0
Other non-current liabilities—affiliate	0	0
Partners' equity (deficit)	(2,512)	(2,038)
Total liabilities and partners’ equity (deficit)	$ (2,630)	$ (2,105)

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Supplemental Guarantor Information - Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues
LNG revenues	$ 1,015	$ 492
LNG revenues—affiliate	503	331
Regasification revenues	65	65
Regasification revenues—affiliate	0	0
Other revenues	10	2
Other revenues—affiliate	0	1
Total revenues	1,593	891
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	837	513
Cost of sales—affiliate	0	0
Operating and maintenance expense	95	50
Operating and maintenance expense—affiliate	26	18
General and administrative expense	4	3
General and administrative expense—affiliate	18	22
Depreciation and amortization expense	105	66
Total operating costs and expenses	1,085	672
Income (loss) from operations	508	219
Other income (expense)
Interest expense, net of capitalized interest	(185)	(130)
Loss on early extinguishment of debt	0	(42)
Derivative gain (loss), net	8	0
Equity earnings (losses) of subsidiaries	0	0
Other income (expense)	4	0
Total other income (expense)	(173)	(172)
Net income (loss)	335	47
Parent Issuer [Member]
Revenues
LNG revenues	0	0
LNG revenues—affiliate	0	0
Regasification revenues	0	0
Regasification revenues—affiliate	0	0
Other revenues	0	0
Other revenues—affiliate	0	0
Total revenues	0	0
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	0	0
Cost of sales—affiliate	0	0
Operating and maintenance expense	0	1
Operating and maintenance expense—affiliate	0	0
General and administrative expense	1	1
General and administrative expense—affiliate	3	3
Depreciation and amortization expense	1	0
Total operating costs and expenses	5	5
Income (loss) from operations	(5)	(5)
Other income (expense)
Interest expense, net of capitalized interest	(34)	(25)
Loss on early extinguishment of debt		0
Derivative gain (loss), net	8	2
Equity earnings (losses) of subsidiaries	363	75
Other income (expense)	3
Total other income (expense)	340	52
Net income (loss)	335	47
Guarantors [Member]
Revenues
LNG revenues	0	0
LNG revenues—affiliate	0	0
Regasification revenues	65	65
Regasification revenues—affiliate	64	33
Other revenues	10	2
Other revenues—affiliate	55	51
Total revenues	194	151
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	0	0
Cost of sales—affiliate	0	0
Operating and maintenance expense	17	10
Operating and maintenance expense—affiliate	32	34
General and administrative expense	1	0
General and administrative expense—affiliate	4	3
Depreciation and amortization expense	18	19
Total operating costs and expenses	72	66
Income (loss) from operations	122	85
Other income (expense)
Interest expense, net of capitalized interest	0	0
Loss on early extinguishment of debt		0
Derivative gain (loss), net	0	0
Equity earnings (losses) of subsidiaries	242	(4)
Other income (expense)	(1)
Total other income (expense)	241	(4)
Net income (loss)	363	81
Non-Guarantor [Member]
Revenues
LNG revenues	1,015	492
LNG revenues—affiliate	503	331
Regasification revenues	0	0
Regasification revenues—affiliate	0	0
Other revenues	0	0
Other revenues—affiliate	0	0
Total revenues	1,518	823
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	838	510
Cost of sales—affiliate	8	4
Operating and maintenance expense	78	39
Operating and maintenance expense—affiliate	103	59
General and administrative expense	2	2
General and administrative expense—affiliate	12	17
Depreciation and amortization expense	86	47
Total operating costs and expenses	1,127	678
Income (loss) from operations	391	145
Other income (expense)
Interest expense, net of capitalized interest	(151)	(105)
Loss on early extinguishment of debt		(42)
Derivative gain (loss), net	0	(2)
Equity earnings (losses) of subsidiaries	0	0
Other income (expense)	2
Total other income (expense)	(149)	(149)
Net income (loss)	242	(4)
Eliminations [Member]
Revenues
LNG revenues	0	0
LNG revenues—affiliate	0	0
Regasification revenues	0	0
Regasification revenues—affiliate	(64)	(33)
Other revenues	0	0
Other revenues—affiliate	(55)	(50)
Total revenues	(119)	(83)
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	(1)	3
Cost of sales—affiliate	(8)	(4)
Operating and maintenance expense	0	0
Operating and maintenance expense—affiliate	(109)	(75)
General and administrative expense	0	0
General and administrative expense—affiliate	(1)	(1)
Depreciation and amortization expense	0	0
Total operating costs and expenses	(119)	(77)
Income (loss) from operations	0	(6)
Other income (expense)
Interest expense, net of capitalized interest	0	0
Loss on early extinguishment of debt		0
Derivative gain (loss), net	0	0
Equity earnings (losses) of subsidiaries	(605)	(71)
Other income (expense)	0
Total other income (expense)	(605)	(71)
Net income (loss)	$ (605)	$ (77)

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Supplemental Guarantor Information - Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	$ 331	$ 115
Cash flows from investing activities
Property, plant and equipment, net	(194)	(524)
Investments in subsidiaries	0	0
Distributions received from affiliates, net	0	0
Net cash provided by (used in) investing activities	(194)	(524)
Cash flows from financing activities
Proceeds from issuances of debt	0	2,314
Repayments of debt	0	(703)
Debt issuance and deferred financing costs	0	(26)
Distributions to parent	0	0
Contributions from parent	0	0
Distributions to owners	(249)	(25)
Net cash provided by (used in) financing activities	(249)	1,560
Net increase (decrease) in cash, cash equivalents and restricted cash	(112)	1,151
Cash, cash equivalents and restricted cash—beginning of period	1,589	605
Cash, cash equivalents and restricted cash—end of period	1,477	1,756
Parent Issuer [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	(10)	(29)
Cash flows from investing activities
Property, plant and equipment, net	0	0
Investments in subsidiaries	(38)	(127)
Distributions received from affiliates, net	167	159
Net cash provided by (used in) investing activities	129	32
Cash flows from financing activities
Proceeds from issuances of debt		0
Repayments of debt		0
Debt issuance and deferred financing costs		0
Distributions to parent	0	0
Contributions from parent	0	0
Distributions to owners	(249)	(25)
Net cash provided by (used in) financing activities	(249)	(25)
Net increase (decrease) in cash, cash equivalents and restricted cash	(130)	(22)
Cash, cash equivalents and restricted cash—beginning of period	1,033	234
Cash, cash equivalents and restricted cash—end of period	903	212
Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	135	32
Cash flows from investing activities
Property, plant and equipment, net	(5)	0
Investments in subsidiaries	0	0
Distributions received from affiliates, net	0	0
Net cash provided by (used in) investing activities	(5)	0
Cash flows from financing activities
Proceeds from issuances of debt		0
Repayments of debt		0
Debt issuance and deferred financing costs		0
Distributions to parent	(167)	(159)
Contributions from parent	38	127
Distributions to owners	0	0
Net cash provided by (used in) financing activities	(129)	(32)
Net increase (decrease) in cash, cash equivalents and restricted cash	1	0
Cash, cash equivalents and restricted cash—beginning of period	12	13
Cash, cash equivalents and restricted cash—end of period	13	13
Non-Guarantor [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	206	116
Cash flows from investing activities
Property, plant and equipment, net	(189)	(528)
Investments in subsidiaries	0	0
Distributions received from affiliates, net	0	0
Net cash provided by (used in) investing activities	(189)	(528)
Cash flows from financing activities
Proceeds from issuances of debt		2,314
Repayments of debt		(703)
Debt issuance and deferred financing costs		(26)
Distributions to parent	0	0
Contributions from parent	0	0
Distributions to owners	0	0
Net cash provided by (used in) financing activities	0	1,585
Net increase (decrease) in cash, cash equivalents and restricted cash	17	1,173
Cash, cash equivalents and restricted cash—beginning of period	544	358
Cash, cash equivalents and restricted cash—end of period	561	1,531
Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	0	(4)
Cash flows from investing activities
Property, plant and equipment, net	0	4
Investments in subsidiaries	38	127
Distributions received from affiliates, net	(167)	(159)
Net cash provided by (used in) investing activities	(129)	(28)
Cash flows from financing activities
Proceeds from issuances of debt		0
Repayments of debt		0
Debt issuance and deferred financing costs		0
Distributions to parent	167	159
Contributions from parent	(38)	(127)
Distributions to owners	0	0
Net cash provided by (used in) financing activities	129	32
Net increase (decrease) in cash, cash equivalents and restricted cash	0	0
Cash, cash equivalents and restricted cash—beginning of period	0	0
Cash, cash equivalents and restricted cash—end of period	$ 0	$ 0

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Supplemental Guarantor Information - Condensed Consolidating Statements of Cash Flows - Balances per Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	$ 0	$ 0
Restricted cash	1,477	1,589
Total cash, cash equivalents and restricted cash	1,477	1,589	$ 1,756	$ 605
Parent Issuer [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	903	1,033
Total cash, cash equivalents and restricted cash	903	1,033	212	234
Guarantors [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	13	12
Total cash, cash equivalents and restricted cash	13	12	13	13
Non-Guarantor [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	561	544
Total cash, cash equivalents and restricted cash	561	544	1,531	358
Eliminations [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	0	0
Total cash, cash equivalents and restricted cash	$ 0	$ 0	$ 0	$ 0