10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2019

or

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

 For the transition period from            to            

Commission file number 001-33366

Cheniere Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware	20-5913059
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

700 Milam Street, Suite 1900

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(713) 375-5000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: 

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	CQP	NYSE American

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  ☒   No  ☐

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

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

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

As of October 25, 2019, the registrant had 348,629,792 common units and 135,383,831 subordinated units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Income	4
	Consolidated Statements of Partners’ Equity	5
	Consolidated Statements of Cash Flows	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47
Item 4.	Controls and Procedures	47
Part II. Other Information
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 6.	Exhibits	49
	Signatures	50

i

DEFINITIONS

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

Common Industry and Other Terms

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

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of September 30, 2019, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

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

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

2

PART I. FINANCIAL INFORMATION 

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS 

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

	September 30,			December 31,
	2019			2018
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	1,707		$	—
Restricted cash	185			1,541
Accounts and other receivables	277			348
Accounts receivable—affiliate	67			114
Advances to affiliate	177			228
Inventory	103			99
Derivative assets	8			6
Other current assets	65			20
Total current assets	2,589			2,356
Property, plant and equipment, net	16,338			15,390
Operating lease assets, net	91			—
Debt issuance costs, net	17			13
Non-current derivative assets	29			31
Other non-current assets, net	157			184
Total assets	$	19,221		$	17,974
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	17		$	15
Accrued liabilities	657			821
Due to affiliates	40			49
Deferred revenue	169			116
Deferred revenue—affiliate	—			1
Current operating lease liabilities	6			—
Derivative liabilities	29			66
Total current liabilities	918			1,068
Long-term debt, net	17,571			16,066
Non-current operating lease liabilities	84			—
Non-current derivative liabilities	32			14
Other non-current liabilities	4			4
Other non-current liabilities—affiliate	20			22
Partners’ equity
Common unitholders’ interest (348.6 million units issued and outstanding at September 30, 2019 and December 31, 2018)	1,692			1,806
Subordinated unitholders’ interest (135.4 million units issued and outstanding at September 30, 2019 and December 31, 2018)	(1,035		)	(990		)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2019 and December 31, 2018)	(65		)	(16		)
Total partners’ equity	592			800
Total liabilities and partners’ equity	$	19,221		$	17,974

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

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per unit data)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues
LNG revenues	$	1,140		$	1,249		$	3,678		$	3,419
LNG revenues—affiliate	257			205			1,017			886
Regasification revenues	66			66			199			196
Other revenues	13			9			36			28
Total revenues	1,476			1,529			4,930			4,529
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	742			756			2,501			2,291
Cost of sales—affiliate	6			—			6			—
Operating and maintenance expense	172			113			472			306
Operating and maintenance expense—affiliate	34			31			100			87
Development expense	—			1			—			2
General and administrative expense	3			3			9			9
General and administrative expense—affiliate	34			18			82			53
Depreciation and amortization expense	138			107			390			318
Impairment expense and loss on disposal of assets	1			8			6			8
Total operating costs and expenses	1,130			1,037			3,566			3,074
Income from operations	346			492			1,364			1,455
Other income (expense)
Interest expense, net of capitalized interest	(231		)	(183		)	(648		)	(552		)
Loss on modification or extinguishment of debt	(13		)	(12		)	(13		)	(12		)
Derivative gain, net	—			2			—			13
Other income	8			8			24			19
Total other expense	(236		)	(185		)	(637		)	(532		)
Net income	$	110		$	307		$	727		$	923
Basic and diluted net income per common unit	$	0.19		$	0.60		$	1.38		$	1.82
Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation	348.6			348.6			348.6			348.6

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

4

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(in millions)

(unaudited)

Three and Nine Months Ended September 30, 2019
	Common Unitholders’ Interest				Subordinated Unitholder’s Interest				General Partner’s Interest				Total Partners’ Equity
	Units	Amount			Units	Amount			Units	Amount
Balance at December 31, 2018	348.6	$	1,806		135.4	$	(990	)	9.9	$	(16	)	$	800
Net income	—	272			—	105			—	8			385
Distributions
Common units, $0.59/unit	—	(206		)	—	—			—	—			(206		)
Subordinated units, $0.59/unit	—	—			—	(80		)	—	—			(80		)
General partner units	—	—			—	—			—	(18		)	(18		)
Balance at March 31, 2019	348.6	1,872			135.4	(965		)	9.9	(26		)	881
Net income	—	164			—	64			—	4			232
Distributions
Common units, $0.60/unit	—	(209		)	—	—			—	—			(209		)
Subordinated units, $0.60/unit	—	—			—	(81		)	—	—			(81		)
General partner units	—	—			—	—			—	(22		)	(22		)
Balance at June 30, 2019	348.6	1,827			135.4	(982		)	9.9	(44		)	801
Net income	—	77			—	30			—	3			110
Distributions
Common units, $0.61/unit	—	(212		)	—	—			—	—			(212		)
Subordinated units, $0.61/unit	—	—			—	(83		)	—	—			(83		)
General partner units	—	—			—	—			—	(24		)	(24		)
Balance at September 30, 2019	348.6	$	1,692		135.4	$	(1,035	)	9.9	$	(65	)	$	592

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

5

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY—CONTINUED

(in millions)

(unaudited)

Three and Nine Months Ended September 30, 2018
	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
Common units, $0.50/unit	—	(175		)	—	—			—	—			(175		)
Subordinated units, $0.50/unit	—	—			—	(68		)	—	—			(68		)
General partner units	—	—			—	—			—	(6		)	(6		)
Balance at March 31, 2018	348.6	1,731			135.4	(1,019		)	9.9	13			725
Net income	—	199			—	77			—	5			281
Distributions
Common units, $0.55/unit	—	(191		)	—	—			—	—			(191		)
Subordinated units, $0.55/unit	—	—			—	(74		)	—	—			(74		)
General partner units	—	—			—	—			—	(13		)	(13		)
Balance at June 30, 2018	348.6	1,739			135.4	(1,016		)	9.9	5			728
Net income	—	216			—	84			—	7			307
Distributions
Common units, $0.56/unit	—	(196		)	—	—			—	—			(196		)
Subordinated units, $0.56/unit	—	—			—	(76		)	—	—			(76		)
General partner units	—	—			—	—			—	(15		)	(15		)
Balance at September 30, 2018	348.6	$	1,759		135.4	$	(1,008	)	9.9	$	(3	)	$	748

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

6

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Nine Months Ended September 30,
	2019			2018
Cash flows from operating activities
Net income	$	727		$	923
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	390			318
Amortization of debt issuance costs, deferred commitment fees, premium and discount	23			24
Loss on modification or extinguishment of debt	13			12
Total losses (gains) on derivatives, net	(30		)	29
Net cash provided by (used for) settlement of derivative instruments	11			—
Impairment expense and loss on disposal of assets	6			8
Other	8			5
Changes in operating assets and liabilities:
Accounts and other receivables	36			(33		)
Accounts receivable—affiliate	47			140
Advances to affiliate	(47		)	(79		)
Inventory	(3		)	6
Accounts payable and accrued liabilities	(209		)	(77		)
Due to affiliates	(3		)	(5		)
Deferred revenue	54			6
Other, net	(42		)	(10		)
Other, net—affiliate	(4		)	(3		)
Net cash provided by operating activities	977			1,264
Cash flows from investing activities
Property, plant and equipment, net	(1,156		)	(578		)
Other	(1		)	—
Net cash used in investing activities	(1,157		)	(578		)
Cash flows from financing activities
Proceeds from issuances of debt	2,230			1,100
Repayments of debt	(730		)	(1,090		)
Debt issuance and deferred financing costs	(33		)	(8		)
Debt extinguishment costs	(4		)	(6		)
Distributions to owners	(935		)	(814		)
Other	3			—
Net cash provided by (used in) financing activities	531			(818		)
Net increase (decrease) in cash, cash equivalents and restricted cash	351			(132		)
Cash, cash equivalents and restricted cash—beginning of period	1,541			1,589
Cash, cash equivalents and restricted cash—end of period	$	1,892		$	1,457

Balances per Consolidated Balance Sheet:

	September 30, 2019
Cash and cash equivalents	$	1,707
Restricted cash	185
Total cash, cash equivalents and restricted cash	$	1,892

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

7

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 in various stages of operating and constructing six natural gas liquefaction Trains (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. Trains 1 through 5 are operational and Train 6 is under construction. The Sabine Pass LNG terminal has operational regasification facilities owned by SPLNG and a 94-mile pipeline owned by CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

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, 2018.

Results of operations for the three and nine months ended September 30, 2019 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2019.

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.

Recent Accounting Standards

We adopted ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard resulted in the recognition of right-of-use assets and lease liabilities for operating leases of approximately $100 million on our Consolidated Balance Sheets, with no material impact on our Consolidated Statements of Income or Consolidated Statements of Cash Flows. We have elected the practical expedients to (1) carryforward prior conclusions related to lease identification and classification for existing leases, (2) combine lease and non-lease components of an arrangement for all classes of leased assets, (3) omit short-term leases with a term of 12 months or less from recognition on the balance sheet and (4) carryforward our existing accounting for land easements not previously accounted for as leases. See Note 11—Leases for additional information on our leases following the adoption of this standard.

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 accumulated 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

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

As of September 30, 2019, Cheniere, Blackstone CQP Holdco and the public owned a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere’s ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.

NOTE 3—RESTRICTED CASH

Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2019 and December 31, 2018, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Current restricted cash
Liquefaction Project	$	185	$	756
Cash held by us and our guarantor subsidiaries	—		785
Total current restricted cash	$	185	$	1,541

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.

The cash held by us and our guarantor subsidiaries was restricted in use under the terms of the previous $2.8 billion credit facilities (the “2016 CQP Credit Facilities”) and the related depositary agreement governing the extension of credit to us, but is no longer restricted following the termination of the 2016 CQP Credit Facilities. Amounts not classified as restricted have been reserved by our general partner under the terms of our partnership agreement.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2019 and December 31, 2018, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
SPL trade receivable	$	261	$	330
Other accounts receivable	16		18
Total accounts and other receivables	$	277	$	348

NOTE 5—INVENTORY

As of September 30, 2019 and December 31, 2018, inventory consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Natural gas	$	15	$	28
LNG	7		6
Materials and other	81		65
Total inventory	$	103	$	99

9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

As of September 30, 2019 and December 31, 2018, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2019			2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	16,807		$	12,760
LNG terminal construction-in-process	1,196			3,913
Accumulated depreciation	(1,671		)	(1,290		)
Total LNG terminal costs, net	16,332			15,383
Fixed assets
Fixed assets	26			26
Accumulated depreciation	(20		)	(19		)
Total fixed assets, net	6			7
Property, plant and equipment, net	$	16,338		$	15,390

 

Depreciation expense was $136 million and $104 million during the three months ended September 30, 2019 and 2018, respectively, and $386 million and $310 million during the nine months ended September 30, 2019 and 2018, respectively.

We realized offsets to LNG terminal costs of $48 million during the nine months ended September 30, 2019 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 Trains of the Liquefaction Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs during the three months ended September 30, 2019 and in the three and nine months ended September 30, 2018.

NOTE 7—DERIVATIVE INSTRUMENTS

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

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

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

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

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2019 and December 31, 2018, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2019												December 31, 2018
	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 (liability)	$	(6	)	$	(10	)	$	(8	)	$	(24	)	$	5	$	(23	)	$	(25	)	$	(43	)

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.

10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of September 30, 2019 and December 31, 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

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 natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2019:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$(8)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.618) - $0.056

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Balance, beginning of period	$	34		$	11		$	(25	)	$	43
Realized and mark-to-market gains (losses):
Included in cost of sales	(42		)	4			(22		)	(5		)
Purchases and settlements:
Purchases	(1		)	4			(4		)	8
Settlements	1			1			43			(27		)
Transfers out of Level 3 (1)	—			(1		)	—			—
Balance, end of period	$	(8	)	$	19		$	(8	)	$	19
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(42	)	$	4		$	(22	)	$	(5	)

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

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. 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, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of netting and any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Interest Rate Derivatives

We previously had interest rate swaps (“CQP Interest Rate Derivatives” and, collectively with the CCH Interest Rate Derivatives and the CCH Interest Rate Forward Start Derivatives, the “Interest Rate Derivatives”) to hedge a portion of the variable interest payments on our credit facilities. In October 2018, we terminated the CQP Interest Rate Derivatives related to the 2016 CQP Credit Facilities and realized a derivative gain of $28 million.

Liquefaction Supply Derivatives

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

SPL had secured up to approximately 4,108 TBtu and 3,464 TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2019 and December 31, 2018, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 3,880 TBtu and 2,978 TBtu as of September 30, 2019 and December 31, 2018, respectively.

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

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	September 30, 2019			December 31, 2018
Derivative assets	$	8		$	6
Non-current derivative assets	29			31
Total derivative assets	37			37
Derivative liabilities	(29		)	(66		)
Non-current derivative liabilities	(32		)	(14		)
Total derivative liabilities	(61		)	(80		)
Derivative liability, net	$	(24	)	$	(43	)

(1) Does not include collateral calls of $10 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018, respectively.

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 and nine months ended September 30, 2019 and 2018 (in millions):

		Three Months Ended September 30,					Nine Months Ended September 30,
	Consolidated Statement of Income Location (1)	2019			2018		2019		2018
Liquefaction Supply Derivatives gain	LNG revenues	$	1		$	—	$	2	$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	(55		)	10		28		(42		)

(1) Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Consolidated Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2019
Liquefaction Supply Derivatives	$	40		$	(3	)	$	37
Liquefaction Supply Derivatives	(63		)	2			(61		)
As of December 31, 2018
Liquefaction Supply Derivatives	$	63		$	(26	)	$	37
Liquefaction Supply Derivatives	(92		)	12			(80		)

NOTE 8—OTHER NON-CURRENT ASSETS

As of September 30, 2019 and December 31, 2018, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Advances made to municipalities for water system enhancements	$	88	$	90
Advances and other asset conveyances to third parties to support LNG terminals	35		36
Tax-related payments and receivables	17		17
Information technology service prepayments	8		20
Advances made under EPC and non-EPC contracts	2		14
Other	7		7
Total other non-current assets, net	$	157	$	184

NOTE 9—ACCRUED LIABILITIES

As of September 30, 2019 and December 31, 2018, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Interest costs and related debt fees	$	217	$	224
Accrued natural gas purchases	254		518
LNG terminal and related pipeline costs	161		79
Other accrued liabilities	25		—
Total accrued liabilities	$	657	$	821

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—DEBT

As of September 30, 2019 and December 31, 2018, our debt consisted of the following (in millions):

	September 30,			December 31,
	2019			2018
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			1,100
4.500% Senior Notes due 2029 (“2029 CQP Senior Notes”)	1,500			—
2016 CQP Credit Facilities	—			—
CQP Credit Facilities entered into in 2019 (“2019 CQP Credit Facilities”)	—			—
Unamortized premium, discount and debt issuance costs, net	(179		)	(184		)
Total long-term debt, net	17,571			16,066
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	17,571		$	16,066

2019 Debt Issuances and Terminations

2029 CQP Senior Notes

In September 2019, we issued an aggregate principal amount of $1.5 billion of the 2029 CQP Senior Notes, which are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (the “CQP Guarantors”). The proceeds of the offering were used to prepay the outstanding balance of the $750 million term loan under the 2019 CQP Credit Facilities (“CQP Term Facility”) and for general corporate purposes, including funding future capital expenditures in connection with the construction of Train 6 at the Liquefaction Project, resulting in the recognition of debt modification and extinguishment costs of $13 million for the three and nine months ended September 30, 2019. As of September 30, 2019, only the $750 million revolving credit facility (“CQP Revolving Facility”), all of which is undrawn, remains as part of the 2019 CQP Credit Facilities.

Borrowings under the 2029 CQP Senior Notes accrue interest at a fixed rate of 4.500% per annum, and interest on the 2029 CQP Senior Notes is payable semi-annually in cash in arrears. The 2029 CQP Senior Notes are governed by the same base indenture as the 2025 CQP Senior Notes and the 2026 CQP Senior Notes (the “CQP Base Indenture”), and are further governed by the Third Supplemental Indenture (together with the CQP Base Indenture, the “2029 CQP Notes Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the 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.

At any time prior to October 1, 2024, we may redeem all or a part of the 2029 CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus the “applicable premium” set forth in the 2029 CQP Notes Indenture, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2022, we may redeem up to 35% of the aggregate principal amount of the 2029 CQP Senior Notes with an amount

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. At any time on or after October 1, 2024 through the maturity date of October 1, 2029, we may redeem the 2029 CQP Senior Notes, in whole or in part, at the redemption prices set forth in the 2029 CQP Notes Indenture.

The 2025 CQP Senior Notes, the 2026 CQP Senior Notes and the 2029 CQP Senior Notes (collectively, the “CQP Senior Notes”) are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

In connection with the closing of the 2029 CQP Senior Notes offering, we and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, we and the CQP Guarantors have agreed to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2029 CQP Senior Notes for a like aggregate principal amount of our debt securities with terms identical in all material respects to the 2029 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after the notes issuance date of September 12, 2019. Under specified circumstances, we and the CQP Guarantors have also agreed to cause to become effective a shelf registration statement relating to resales of the 2029 CQP Senior Notes. We will be obligated to pay additional interest on the 2029 CQP Senior Notes if we fail to comply with our obligation to register the 2029 CQP Senior Notes within the specified time period.

2016 CQP Credit Facilities

In May 2019, the remaining commitments under the 2016 CQP Credit Facilities were terminated. There were no write-offs of discounts, premiums and debt issuance costs associated with the termination of the 2016 CQP Credit Facilities.

2019 CQP Credit Facilities

In May 2019, we entered into the 2019 CQP Credit Facilities, which consisted of the $750 million CQP Term Facility, which was prepaid and terminated upon issuance of the 2029 CQP Senior Notes in September 2019, and the $750 million CQP Revolving Facility. Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the Liquefaction Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit.

Loans under the 2019 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50%, and the adjusted one-month LIBOR plus 1.0%), plus the applicable margin. Under the CQP Term Facility, the applicable margin for LIBOR loans was 1.50% per annum, and the applicable margin for base rate loans was 0.50% per annum. Under the CQP Revolving Facility, the applicable margin for LIBOR loans is 1.25% to 2.125% per annum, and the applicable margin for base rate loans is 0.25% to 1.125% per annum, in each case depending on our then-current rating. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three-month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit our ability to make restricted

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.

The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted encumbrances) on substantially all of our and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2019 (in millions):

	SPL Working Capital Facility (1)		2019 CQP Credit Facilities
Original facility size	$	1,200	$	1,500
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		750
Letters of credit issued	414		—
Available commitment	$	786	$	750
Interest rate on available balance	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Maturity date	December 31, 2020		May 29, 2024

(1) The SPL Working Capital Facility was amended in May 2019 in connection with commercialization and financing of Train 6 of the Liquefaction Project. All terms of the SPL Working Capital Facility substantially remained unchanged.

Restrictive Debt Covenants

As of September 30, 2019, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Total interest cost	$	246		$	235		$	718		$	701
Capitalized interest	(15		)	(52		)	(70		)	(149		)
Total interest expense, net	$	231		$	183		$	648		$	552

Fair Value Disclosures

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

	September 30, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	16,780	$	18,340	$	15,275	$	15,672
2037 SPL Senior Notes (2)	791		909		791		817
Credit facilities (3)	—		—		—		—

(1) Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2026

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

CQP Senior Notes and 2029 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, 2016 CQP Credit Facilities and 2019 CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

NOTE 11—LEASES

Our leased assets consist primarily of tug vessels and land sites, all of which are classified as operating leases.

ASC 842 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. As our leases generally do not provide an implicit rate, in order to calculate the lease liability, we discounted our expected future lease payments using our relevant subsidiary’s incremental borrowing rate at the later of January 1, 2019 or the commencement date of the lease. The incremental borrowing rate is an estimate of the rate of interest that a given subsidiary would have to pay to borrow on a collateralized basis over a similar term to that of the lease term.

Many of our leases contain renewal options exercisable at our sole discretion. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability only to the extent they are reasonably certain to be exercised, such as when necessary to satisfy obligations that existed at the execution of the lease or when the non-renewal would otherwise result in an economic penalty.

We have elected the practical expedient to omit leases with an initial term of 12 months or less (“short-term lease”) from recognition on the balance sheet. We recognize short-term lease payments on a straight-line basis over the lease term and variable payments under short-term leases in the period in which the obligation is incurred.

Certain of our leases contain non-lease components which are not separated from the lease components when calculating the right-of-use asset and lease liability per our use of the practical expedient to combine both components of an arrangement for all classes of leased assets.

Certain of our leases also contain variable payments, such as inflation, that are not included when calculating the right-of-use asset and lease liability unless the payments are in-substance fixed. We recognize lease expense for operating leases on a straight-line basis over the lease term.

The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):

	Consolidated Balance Sheet Location	September 30, 2019
Right-of-use assets—Operating	Operating lease assets, net	$	91
Current operating lease liabilities	Current operating lease liabilities	6
Non-current operating lease liabilities	Non-current operating lease liabilities	84

The following table shows the classification and location of our lease cost on our Consolidated Statements of Income (in millions):

	Consolidated Statement of Income Location	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost (1)	Operating costs and expenses (2)	$	2	$	8

(1)    Includes $1 million of variable lease costs.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

(2) Presented in cost of sales, operating and maintenance expense, general and administrative expense or general and administrative expense—affiliate consistent with the nature of the asset under lease.

Future annual minimum lease payments for operating leases as of September 30, 2019 are as follows (in millions): 

Years Ending December 31,	Operating Leases
2019	$	3
2020	10
2021	10
2022	10
2023	10
Thereafter	125
Total lease payments	168
Less: Interest	(78		)
Present value of lease liabilities	$	90

Future annual minimum lease payments for operating leases as of December 31, 2018, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows (in millions):

Years Ending December 31,	Operating Leases (1)
2019	$	10
2020	10
2021	10
2022	10
2023	10
Thereafter	124
Total	$	174

(1) Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components.

The following table shows the weighted-average remaining lease term (in years) and the weighted-average discount rate for our operating leases:

	September 30, 2019
Weighted-average remaining lease term (in years)	25.9
Weighted-average discount rate	4.8	%

The following table includes other quantitative information for our operating leases (in millions):

	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	7

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 12—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
LNG revenues	$	1,139	$	1,249	$	3,676	$	3,419
LNG revenues—affiliate	257		205		1,017		886
Regasification revenues	66		66		199		196
Other revenues	13		9		36		28
Total revenues from customers	1,475		1,529		4,928		4,529
Net derivative gains (1)	1		—		2		—
Total revenues	$	1,476	$	1,529	$	4,930	$	4,529

(1) See Note 7—Derivative Instruments for additional information about our derivatives.

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):

	Nine Months Ended September 30, 2019
Deferred revenues, beginning of period	$	116
Cash received but not yet recognized	169
Revenue recognized from prior period deferral	(116		)
Deferred revenues, end of period	$	169

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2019 and December 31, 2018:

	September 30, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues (2)	$	55.7	10	$	53.6	10
Regasification revenues	2.4		5	2.6		6
Total revenues	$	58.1		$	56.2

(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.

(2) Includes future consideration from agreement contractually assigned to SPL from Cheniere Marketing.

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

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

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

customers elect to take delivery of their LNG, and adjustments to the consumer price index. Approximately 49% and 55% of our LNG revenues during the three months ended September 30, 2019 and 2018, respectively, and approximately 53% and 55% of our LNG revenues during the nine months ended September 30, 2019 and 2018, respectively, were related to variable consideration received from customers. During each of the three and nine months ended September 30, 2019 and 2018, approximately 3% of our regasification revenues were related to variable consideration received from customers. All of our LNG revenues—affiliate were related to variable consideration received from customers during each of the three and nine months ended September 30, 2019 and 2018.

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.

NOTE 13—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
LNG revenues—affiliate
Cheniere Marketing Agreements	$	255	$	205	$	1,015	$	886
Contracts for Sale and Purchase of Natural Gas and LNG	2		—		2		—
Total LNG revenues—affiliate	257		205		1,017		886
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	6		—		6		—
Operating and maintenance expense—affiliate
Services Agreements	34		31		100		87
General and administrative expense—affiliate
Services Agreements	34		18		82		53

As of September 30, 2019 and December 31, 2018, we had $67 million and $114 million, respectively, of accounts receivable—affiliate, under the agreements described below.

Terminal Use Agreement

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 May 2036.

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

Cheniere Marketing Agreements

Cheniere Marketing SPA

Cheniere Marketing has an SPA (“Base 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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

In May 2019, SPL and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by SPL to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo.

Cheniere Marketing Master SPA

SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement. SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, Train 5 of the Liquefaction Project.

Cheniere Marketing Letter Agreement

In May 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu scheduled for delivery between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu.

Services Agreements

As of September 30, 2019 and December 31, 2018, we had $177 million and $228 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Cheniere Partners Services Agreement

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

Cheniere Investments Information Technology Services Agreement

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

SPLNG O&M Agreement

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

21

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 Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M Agreement are required to be remitted to such subsidiary.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This initiative represented an aggregate commitment of $25 million over 10 years in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to ad valorem tax levied on our LNG terminal in the year the Cameron Parish dollar-for-dollar credit is applied.

22

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 obligations. We had $4 million and $3 million in due to affiliates and $20 million and $22 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing as of September 30, 2019 and December 31, 2018, respectively.

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.

SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas sold and purchased under this agreement is recorded as LNG revenues—affiliate and cost of sales—affiliate, respectively.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. The agreement also provides that Tug Services shall contingently pay the wholly owned subsidiary of Cheniere a portion of its future revenues. Accordingly, Tug Services distributed $2 million during each of the three months ended September 30, 2019 and 2018, respectively, and $5 million and $4 million during the nine months ended September 30, 2019 and 2018, respectively, to the wholly owned subsidiary of Cheniere, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the three and nine months ended September 30, 2019 and 2018.

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

23

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

NOTE 14—NET INCOME PER COMMON UNIT

Net income 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 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 Statements of Partners’ Equity. On October 28, 2019, we declared a $0.62 distribution per common unit and subordinated unit and the related distribution to our general partner and IDR holders to be paid on November 14, 2019 to unitholders of record as of November 7, 2019 for the period from July 1, 2019 to September 30, 2019.

The two-class method dictates that net income 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.

24

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

				Limited Partner Units
	Total			Common Units			Subordinated Units			General Partner Units			IDR
Three Months Ended September 30, 2019
Net income	$	110
Declared distributions	323			217			84			6			16
Assumed allocation of undistributed net loss (1)	$	(213	)	(151		)	(58		)	(4		)	—
Assumed allocation of net income				$	66		$	26		$	2		$	16
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	0.19		$	0.19
Three Months Ended September 30, 2018
Net income	$	307
Declared distributions	297			202			79			5			11
Assumed allocation of undistributed net income (1)	$	10		7			3			—			—
Assumed allocation of net income				$	209		$	82		$	5		$	11
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit (2)				$	0.60		$	0.60
Nine Months Ended September 30, 2019
Net income	$	727
Declared distributions	949			638			248			19			44
Assumed allocation of undistributed net loss (1)	$	(222	)	(157		)	(61		)	(4		)	—
Assumed allocation of net income				$	481		$	187		$	15		$	44
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	1.38		$	1.38
Nine Months Ended September 30, 2018
Net income	$	923
Declared distributions	859			589			229			17			24
Assumed allocation of undistributed net income (1)	$	64		45			18			1			—
Assumed allocation of net income				$	634		$	247		$	18		$	24
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	1.82		$	1.82

(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.

25

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 15—CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers:

	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2019	2018	2019	2018	2019	2018
Customer A	24%	24%	28%	27%	20%	35%
Customer B	18%	21%	19%	22%	17%	23%
Customer C	22%	21%	20%	23%	15%	30%
Customer D	19%	24%	21%	18%	21%	*
Customer E	*	—%	*	—%	14%	—%

* Less than 10%

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2019		2018
Cash paid during the period for interest, net of amounts capitalized	$	624	$	586

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $298 million and $204 million as of September 30, 2019 and 2018, respectively.

NOTE 17—SUPPLEMENTAL GUARANTOR INFORMATION

Our CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the indenture governing the CQP Senior Notes. See Note 10—Debt in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2018 for additional information regarding the CQP Senior Notes.

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

26

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Balance Sheet
September 30, 2019
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	1,701	$	6	$	—	$	—		$	1,707
Restricted cash	—		—		185		—			185
Accounts and other receivables	—		3		274		—			277
Accounts receivable—affiliate	—		35		66		(34		)	67
Advances to affiliate	—		151		154		(128		)	177
Inventory	—		13		90		—			103
Derivative assets	—		—		8		—			8
Other current assets	1		12		52		—			65
Other current assets—affiliate	—		—		22		(22		)	—
Total current assets	1,702		220		851		(184		)	2,589
Property, plant and equipment, net	79		2,454		13,831		(26		)	16,338
Operating lease assets, net	—		86		21		(16		)	91
Debt issuance costs, net	10		—		7		—			17
Non-current derivative assets	—		—		29		—			29
Investments in subsidiaries	2,931		495		—		(3,426		)	—
Other non-current assets, net	—		25		132		—			157
Total assets	$	4,722	$	3,280	$	14,871	$	(3,652	)	$	19,221
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	5	$	12	$	—		$	17
Accrued liabilities	77		36		544		—			657
Due to affiliates	—		158		45		(163		)	40
Deferred revenue	—		21		148		—			169
Deferred revenue—affiliate	—		21		—		(21		)	—
Current operating lease liabilities	—		6		—		—			6
Derivative liabilities	—		—		29		—			29
Total current liabilities	77		247		778		(184		)	918
Long-term debt, net	4,053		—		13,518		—			17,571
Non-current operating lease liabilities	—		79		5		—			84
Non-current derivative liabilities	—		—		32		—			32
Other non-current liabilities	—		3		1		—			4
Other non-current liabilities—affiliate	—		20		16		(16		)	20
Partners’ equity	592		2,931		521		(3,452		)	592
Total liabilities and partners’ equity	$	4,722	$	3,280	$	14,871	$	(3,652	)	$	19,221

27

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	779		6		756		—			1,541
Accounts and other receivables	1		1		346		—			348
Accounts receivable—affiliate	1		40		113		(40		)	114
Advances to affiliate	—		104		210		(86		)	228
Inventory	—		12		87		—			99
Derivative assets	—		—		6		—			6
Other current assets	—		2		18		—			20
Other current assets—affiliate	—		—		21		(21		)	—
Total current assets	781		165		1,557		(147		)	2,356
Property, plant and equipment, net	79		2,128		13,209		(26		)	15,390
Debt issuance costs, net	1		—		12		—			13
Non-current derivative assets	—		—		31		—			31
Investments in subsidiaries	2,544		440		—		(2,984		)	—
Other non-current assets, net	—		26		158		—			184
Total assets	$	3,405	$	2,759	$	14,967	$	(3,157	)	$	17,974
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4	$	11	$	—		$	15
Accrued liabilities	39		14		768		—			821
Due to affiliates	—		127		48		(126		)	49
Deferred revenue	—		25		91		—			116
Deferred revenue—affiliate	—		22		—		(21		)	1
Derivative liabilities	—		—		66		—			66
Total current liabilities	39		192		984		(147		)	1,068
Long-term debt, net	2,566		—		13,500		—			16,066
Non-current derivative liabilities	—		—		14		—			14
Other non-current liabilities	—		1		3		—			4
Other non-current liabilities—affiliate	—		22		—		—			22
Partners’ equity	800		2,544		466		(3,010		)	800
Total liabilities and partners’ equity	$	3,405	$	2,759	$	14,967	$	(3,157	)	$	17,974

28

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Income
Three Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,140		$	—		$	1,140
LNG revenues—affiliate	—			—			257			—			257
Regasification revenues	—			66			—			—			66
Regasification revenues—affiliate	—			65			—			(65		)	—
Other revenues	—			13			—			—			13
Other revenues—affiliate	—			36			—			(36		)	—
Total revenues	—			180			1,397			(101		)	1,476
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			742			—			742
Cost of sales—affiliate	—			6			17			(17		)	6
Operating and maintenance expense	—			22			150			—			172
Operating and maintenance expense—affiliate	—			5			113			(84		)	34
General and administrative expense	1			1			1			—			3
General and administrative expense—affiliate	4			8			28			(6		)	34
Depreciation and amortization expense	1			21			117			(1		)	138
Impairment expense and loss on disposal of assets	—			—			1			—			1
Total operating costs and expenses	6			63			1,169			(108		)	1,130
Income (loss) from operations	(6		)	117			228			7			346
Other income (expense)
Interest expense, net of capitalized interest	(47		)	(1		)	(183		)	—			(231		)
Loss on modification or extinguishment of debt	(13		)	—			—			—			(13		)
Equity earnings of subsidiaries	170			48			—			(218		)	—
Other income (expense)	6			(1		)	3			—			8
Total other income (expense)	116			46			(180		)	(218		)	(236		)
Net income	$	110		$	163		$	48		$	(211	)	$	110

29

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

30

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Income
Nine Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	3,678		$	—		$	3,678
LNG revenues—affiliate	—			—			1,017			—			1,017
Regasification revenues	—			199			—			—			199
Regasification revenues—affiliate	—			196			—			(196		)	—
Other revenues	—			36			—			—			36
Other revenues—affiliate	—			160			—			(160		)	—
Total revenues	—			591			4,695			(356		)	4,930
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			2,501			—			2,501
Cost of sales—affiliate	—			6			35			(35		)	6
Operating and maintenance expense	—			74			398			—			472
Operating and maintenance expense—affiliate	—			76			335			(311		)	100
General and administrative expense	3			2			4			—			9
General and administrative expense—affiliate	10			22			64			(14		)	82
Depreciation and amortization expense	2			58			331			(1		)	390
Impairment expense and loss on disposal of assets	—			—			6			—			6
Total operating costs and expenses	15			238			3,674			(361		)	3,566
Income (loss) from operations	(15		)	353			1,021			5			1,364
Other income (expense)
Interest expense, net of capitalized interest	(120		)	(4		)	(524		)	—			(648		)
Loss on modification or extinguishment of debt	(13		)	—			—			—			(13		)
Equity earnings of subsidiaries	860			506			—			(1,366		)	—
Other income	15			—			9			—			24
Total other income (expense)	742			502			(515		)	(1,366		)	(637		)
Net income	$	727		$	855		$	506		$	(1,361	)	$	727

31

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by operating activities	$	782		$	907		$	656		$	(1,368	)	$	977
Cash flows from investing activities
Property, plant and equipment, net	—			(35		)	(1,123		)	2			(1,156		)
Investments in subsidiaries	(1,109		)	(949		)	—			2,058			—
Return of capital	721			546			—			(1,267		)	—
Other	—			—			(1		)	—			(1		)
Net cash used in investing activities	(388		)	(438		)	(1,124		)	793			(1,157		)
Cash flows from financing activities
Proceeds from issuances of debt	2,230			—			—			—			2,230
Repayments of debt	(730		)	—			—			—			(730		)
Debt issuance and deferred financing costs	(33		)	—			—			—			(33		)
Debt extinguishment costs	(4		)	—			—			—			(4		)
Distributions to parent	—			(1,581		)	(1,052		)	2,633			—
Contributions from parent	—			1,109			949			(2,058		)	—
Distributions to owners	(935		)	—			—			—			(935		)
Other	—			3			—			—			3
Net cash provided by (used in) financing activities	528			(469		)	(103		)	575			531
Net increase (decrease) in cash, cash equivalents and restricted cash	922			—			(571		)	—			351
Cash, cash equivalents and restricted cash—beginning of period	779			6			756			—			1,541
Cash, cash equivalents and restricted cash—end of period	$	1,701		$	6		$	185		$	—		$	1,892

Balances per Condensed Consolidating Balance Sheet:

	September 30, 2019
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	1,701	$	6	$	—	$	—	$	1,707
Restricted cash	—		—		185		—		185
Total cash, cash equivalents and restricted cash	$	1,701	$	6	$	185	$	—	$	1,892

33

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

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

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

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

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

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

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

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

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

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

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

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

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

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

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the

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year ended December 31, 2018. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis includes the following subjects: 

• Overview of Business 

• Overview of Significant Events

• Liquidity and Capital Resources 

• Results of Operations 

• Off-Balance Sheet Arrangements 

• Summary of Critical Accounting Estimates

• Recent Accounting Standards

Overview of Business

We are a publicly traded Delaware limited partnership formed by Cheniere. We provide clean, secure and affordable energy to the world, while responsibly delivering a reliable, competitive and integrated source of LNG, in a safe and rewarding work environment. The liquefaction of natural gas into LNG allows it to be shipped economically from the United States where natural gas is abundant and inexpensive to produce to our international customers in areas where natural gas demand and infrastructure exist. Through our wholly owned subsidiary, SPL, we are in various stages of operating and constructing six natural gas liquefaction Trains (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. Trains 1 through 5 are operational and Train 6 is under construction. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG per Train. Through our wholly owned subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We also own a 94-mile pipeline through our wholly owned subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

Overview of Significant Events

Our significant accomplishments since January 1, 2019 and through the filing date of this Form 10-Q include the following:  

Strategic

• In May 2019, the board of directors of our general partner made a positive final investment decision with respect to Train 6 of the Liquefaction Project and issued a full notice to proceed with construction to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) in June 2019.

Operational

• As of October 25, 2019, approximately 800 cumulative LNG cargoes totaling approximately 55 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

• In March 2019, SPL achieved substantial completion of Train 5 of the Liquefaction Project and commenced operating activities.

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Financial

• In September 2019, we issued an aggregate principal amount of $1.5 billion of 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”) to prepay the outstanding balance under the $750 million term loan under our credit facilities (the “2019 CQP Credit Facilities”), which were entered into in May 2019, and for general corporate purposes, including funding future capital expenditures in connection with the construction of Train 6 at the Liquefaction Project. After applying the proceeds of this offering, only a $750 million revolving credit facility, which is currently undrawn, remains as part of the 2019 CQP Credit Facilities.

• In September 2019, the date of first commercial delivery was reached under the 20-year SPAs with Centrica plc and Total Gas & Power North America, Inc. (“Total”) relating to Train 5 of the Liquefaction Project.

• In March 2019, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC relating to Train 4 of the Liquefaction Project.

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at September 30, 2019 and December 31, 2018 (in millions):

	September 30,		December 31,
	2019		2018
Cash and cash equivalents	$	1,707	$	—
Restricted cash designated for the following purposes:
Liquefaction Project	185		756
Cash held by us and our guarantor subsidiaries	—		785
Available commitments under the following credit facilities:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	786		775
2019 CQP Credit Facilities	750		—
$2.8 billion Credit Facilities (“2016 CQP Credit Facilities”)	—		115

For additional information regarding our debt agreements, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2018.

CQP Senior Notes

In September 2019, we issued an aggregate principal amount of $1.5 billion of the 2029 CQP Senior Notes, which in addition to the existing $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) and $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”), are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (the “CQP Guarantors”). The 2025 CQP Senior Notes, 2026 CQP Senior Notes and 2029 CQP Senior Notes (collectively, the “CQP Senior Notes”) are governed by the same base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture (together with the CQP Base Indenture, the “2025 CQP Notes Indenture”), the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”) and the 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture (together with the CQP Base Indenture, the “2029 CQP Notes Indenture”). The 2025 CQP Notes Indenture, the 2026 CQP Notes Indenture and the 2029 CQP Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the 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.

At any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, we may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, we may redeem up to 35% of the aggregate principal amount of the CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes, 105.625% of the aggregate principal amount

37

of the 2026 CQP Senior Notes and 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. We also may at any time on or after October 1, 2020 through the maturity date of October 1, 2025 for the 2025 CQP Senior Notes, October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes and October 1, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.

The CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

2016 CQP Credit Facilities

In May 2019, the remaining commitments under the 2016 CQP Credit Facilities were terminated. 

2019 CQP Credit Facilities

In May 2019, we entered into the 2019 CQP Credit Facilities, which consisted of the $750 million term loan (“CQP Term Facility”), which was prepaid and terminated upon issuance of the 2029 CQP Senior Notes in September 2019, and the $750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the Liquefaction Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit.

Loans under the 2019 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50%, and the adjusted one-month LIBOR plus 1.0%), plus the applicable margin. Under the CQP Revolving Facility, the applicable margin for LIBOR loans is 1.25% to 2.125% per annum, and the applicable margin for base rate loans is 0.25% to 1.125% per annum, in each case depending on our then-current rating. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three-month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

We pay a commitment fee equal to an annual rate of 30% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit our ability to make restricted payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.

The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted encumbrances) on substantially all of our and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).

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Sabine Pass LNG Terminal 

Liquefaction Facilities

We are in various stages of constructing and operating the Liquefaction Project at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completion of Trains 1, 2, 3, 4 and 5 of the Liquefaction Project and commenced operating activities in May 2016, September 2016, March 2017, October 2017 and March 2019, respectively. The following table summarizes the status of Train 6 of the Liquefaction Project as of September 30, 2019:

	Train 6
Overall project completion percentage	38.1%
Completion percentage of:
Engineering	83.8%
Procurement	54.1%
Subcontract work	34.3%
Construction	5.5%
Date of expected substantial completion	1H 2023

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

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

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

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

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

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

Customers

SPL has entered into fixed price SPAs generally with terms of at least 20 years (plus extension rights) with eight third parties for Trains 1 through 6 of the Liquefaction Project, including an agreement anticipated to be assigned from Cheniere Marketing, to make available an aggregate amount of LNG that is between approximately 75% to 85% of the expected aggregate adjusted nominal production capacity from these Trains. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

39

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.3 billion for Trains 1 through 4 and increasing to $2.9 billion upon the date of first commercial delivery of Train 5, which occurred in September 2019. After giving effect to an SPA that Cheniere has committed to provide to SPL by the end of 2020, the annual fixed fee portion to be paid by the third-party SPA customers would increase to at least $3.3 billion upon the date of first commercial delivery of Train 6.

In addition, Cheniere Marketing has agreements with SPL to purchase: (1) at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers and (2) up to 20 cargoes totaling approximately 70 million MMBtu scheduled for delivery between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu.

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of September 30, 2019, SPL had secured up to approximately 4,108 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts that range up to ten years.

Construction

SPL entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 6 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion, including estimated costs for an optional third marine berth.

Regasification Facilities

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

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 5 of the Liquefaction Project, SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the three months ended September 30, 2019 and 2018, SPL recorded $32 million and $7.5 million, respectively, and during the nine months ended September 30, 2019 and 2018, SPL recorded $72 million and $23 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

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

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Capital Resources

We currently expect that SPL’s capital resources requirements with respect to the Liquefaction Project will be financed through project debt and borrowings, cash flows under the SPAs and equity contributions from us. We believe that with the net proceeds of borrowings, available commitments under the SPL Working Capital Facility, 2019 CQP Credit Facilities, cash flows from operations and equity contributions from us, SPL will have adequate financial resources available to meet its currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the Liquefaction Project. SPL began generating cash flows from operations from the Liquefaction Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2, 3, 4 and 5 subsequently achieved substantial completion in September 2016, March 2017, October 2017 and March 2019, respectively. We realized offsets to LNG terminal costs of $48 million in the nine months ended September 30, 2019 that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of Train 5 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 September 30, 2019 and in the three and nine months ended September 30, 2018. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at September 30, 2019 and December 31, 2018 (in millions):

	September 30,		December 31,
	2019		2018
Senior notes (1)	$	17,750	$	16,250
Credit facilities outstanding balance (2)	—		—
Letters of credit issued (3)	414		425
Available commitments under credit facilities (3)	1,536		775
Total capital resources from borrowings and available commitments	$	19,700	$	17,450

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

(2) Includes outstanding balances under the SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2019 CQP Credit Facilities that may be used for general corporate purposes.

(3) Consists of SPL Working Capital Facility and 2019 CQP Credit Facilities. Balance at December 31, 2018 did not include the letters of credit issued or available commitments under the terminated 2016 CQP Credit Facilities, which were not specifically for the Sabine Pass LNG Terminal.

For additional information regarding our debt agreements related to the Sabine Pass LNG Terminal, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2018.

SPL Senior Notes

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

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

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redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

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

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million. As of September 30, 2019 and December 31, 2018, SPL had $786 million and $775 million of available commitments and $414 million and $425 million aggregate amount of issued letters of credit under the SPL Working Capital Facility, respectively. SPL did not have any outstanding borrowings under the SPL Working Capital Facility as of both September 30, 2019 and December 31, 2018.

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

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

Restrictive Debt Covenants

As of September 30, 2019, we and SPL were in compliance with all covenants related to our respective debt agreements.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the nine months ended September 30, 2019 and 2018 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.

	Nine Months Ended September 30,
	2019			2018
Operating cash flows	$	977		$	1,264
Investing cash flows	(1,157		)	(578		)
Financing cash flows	531			(818		)
Net increase (decrease) in cash, cash equivalents and restricted cash	351			(132		)
Cash, cash equivalents and restricted cash—beginning of period	1,541			1,589
Cash, cash equivalents and restricted cash—end of period	$	1,892		$	1,457

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Operating Cash Flows

Our operating cash net inflows during the nine months ended September 30, 2019 and 2018 were $977 million and $1,264 million, respectively. The $287 million decrease in operating cash inflows in 2019 compared to 2018 was primarily related to increased operating costs and expenses, partially offset by increased cash receipts from the sale of LNG cargoes, as a result of an additional Train that was operating at the Liquefaction Project in 2019. In addition to Trains 1 through 4 of the Liquefaction Project that were operational during both the nine months ended September 30, 2019 and 2018, Train 5 was operational for approximately seven months during the nine months ended September 30, 2019.

Investing Cash Flows

Investing cash net outflows during the nine months ended September 30, 2019 and 2018 were $1,157 million and $578 million, respectively, and were primarily used to fund the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion.

Financing Cash Flows

Financing cash net inflows of $531 million during the nine months ended September 30, 2019 was primarily a result of:

• $730 million of borrowings and repayments under the 2019 CQP Credit Facilities;

• issuance of an aggregate principal amount of $1.5 billion of the 2029 CQP Senior Notes, which was used to prepay the outstanding balance of the term loan under the 2019 CQP Credit Facilities;

• $33 million of debt issuance costs related to the up-front fees paid upon the issuance of the 2019 CQP Credit Facilities and 2029 CQP Senior Notes; and

• $935 million of distributions to unitholders.

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

• issuance of an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which was used to prepay $1.1billion of the outstanding borrowings under the 2016 CQP Credit Facilities;

• $8 million of debt issuance costs related to up-front fees paid upon the issuance of the 2026 CQP Senior Notes;

• $6 million in debt extinguishment costs related to the prepayment of the 2016 CQP Credit Facilities; and

• $814 million in distributions to unitholders.

Cash Distributions to Unitholders

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus. The following provides a summary of distributions paid by us during the nine months ended September 30, 2019 and 2018:

						Total Distribution (in millions)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Subordinated Units		General Partner Units		Incentive Distribution Rights
August 14, 2019	April 1 - June 30, 2019	$	0.61	$	0.61	$	213	$	83	$	6	$	15
May 15, 2019	January 1 - March 31, 2019	0.60		0.60		209		81		6		13
February 14, 2019	October 1 - December 31, 2018	0.59		0.59		206		80		6		12
August 14, 2018	April 1 - June 30, 2018	0.56		0.56		195		76		6		7
May 15, 2018	January 1 - March 31, 2018	0.55		0.55		192		74		5		6
February 14, 2018	October 1 - December 31, 2017	0.50		0.50		174		68		5		1

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On October 28, 2019, we declared a $0.62 distribution per common unit and subordinated unit and the related distribution to our general partner and incentive distribution right holders to be paid on November 14, 2019 to unitholders of record as of November 7, 2019 for the period from July 1, 2019 to September 30, 2019.

The subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distributions requirement for our common unitholders and general partner along with certain reserves. Such available cash could be generated through new business development.

Results of Operations

Our consolidated net income was $110 million, or $0.19 per common unit (basic and diluted), in the three months ended September 30, 2019, compared to $307 million, or $0.60 per common unit (basic and diluted), in the three months ended September 30, 2018. This $197 million decrease in net income was primarily a result of increased operating and maintenance expense, increased depreciation and amortization expense, and decreased margins due to decreased pricing on LNG but higher volumes of LNG sold, and increased interest expense, net of capitalized interest, due to a decrease in the portion of total interest costs that could be capitalized as Train 5 of the Liquefaction Project completed construction in March 2019.

Our consolidated net income was $727 million, or $1.38 per common unit (basic and diluted), in the nine months ended September 30, 2019, compared to $923 million, or $1.82 per common unit (basic and diluted), in the nine months ended September 30, 2018. This $196 million decrease in net income was primarily a result of increased operating and maintenance expense, increased interest expense, net of capitalized interest and increased depreciation and amortization expense, partially offset by increased margins due to higher volumes of LNG sold but decreased pricing on LNG.

We enter into derivative instruments to manage our exposure to changing interest rates and commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions economically hedged receive accrual accounting treatment, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.

Revenues

	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions, except volumes)	2019		2018		Change			2019		2018		Change
LNG revenues	$	1,140	$	1,249	$	(109	)	$	3,678	$	3,419	$	259
LNG revenues—affiliate	257		205		52			1,017		886		131
Regasification revenues	66		66		—			199		196		3
Other revenues	13		9		4			36		28		8
Total revenues	$	1,476	$	1,529	$	(53	)	$	4,930	$	4,529	$	401
LNG volumes recognized as revenues (in TBtu)	277		228		49			845		691		154

We begin recognizing LNG revenues from the Liquefaction Project following the substantial completion and the commencement of operating activities of the respective Trains. In addition to Trains 1 through 4 of the Liquefaction Project that were operational during both the nine months ended September 30, 2019 and 2018, Train 5 of the Liquefaction Project was operational for approximately seven months during the nine months ended September 30, 2019. The decrease in revenues during the three months ended September 30, 2019 from the comparable period in 2018 was primarily attributable to the decreased revenues per MMBtu, which was partially offset by the increased volumes of LNG sold following the achievement of substantial completion of Train 5 of the Liquefaction Project. The increase in revenues during the nine months ended September 30, 2019 from the nine months ended September 30, 2018 was primarily attributable to the increased volumes of LNG, partially offset by decreased revenues per MMBtu. We expect our LNG revenues to increase in the future upon Train 6 of the Liquefaction Project becoming operational.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. We realized offsets to LNG terminal costs of $48 million corresponding to 10 TBtu of LNG in the nine

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months ended September 30, 2019 that related to the sale of commissioning cargoes from the Liquefaction Project. We did not realize any offsets to LNG terminal costs in the three months ended September 30, 2019 and in the three and nine months ended September 30, 2018.

Also included in LNG revenues are gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery, and the sale of natural gas procured for the liquefaction process. During the three months ended September 30, 2019 and 2018, we realized $35 million and $67 million, respectively, of gains and other revenues from these transactions. During the nine months ended September 30, 2019 and 2018, we realized $114 million and $127 million, respectively, of gains and other revenues from these transactions.

Operating costs and expenses

	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions)	2019		2018		Change			2019		2018		Change
Cost of sales	$	742	$	756	$	(14	)	$	2,501	$	2,291	$	210
Cost of sales—affiliate	6		—		6			6		—		6
Operating and maintenance expense	172		113		59			472		306		166
Operating and maintenance expense—affiliate	34		31		3			100		87		13
Development expense	—		1		(1		)	—		2		(2		)
General and administrative expense	3		3		—			9		9		—
General and administrative expense—affiliate	34		18		16			82		53		29
Depreciation and amortization expense	138		107		31			390		318		72
Impairment expense and loss on disposal of assets	1		8		(7		)	6		8		(2		)
Total operating costs and expenses	$	1,130	$	1,037	$	93		$	3,566	$	3,074	$	492

Our total operating costs and expenses increased during the three and nine months ended September 30, 2019 from the three and nine months ended September 30, 2018, primarily as a result of an additional Train that was operating between each of the periods and increased third-party service and maintenance costs from additional maintenance and related activities at the Liquefaction Project.

Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. Cost of sales decreased during the three months ended September 30, 2019 from the three months ended September 30, 2018 due to decreased pricing of natural gas feedstock between the quarterly periods, partially offset by increased volumes of natural gas feedstock for our LNG sales as a result of substantial completion of Train 5 of the Liquefaction Project. Additionally, there was a decrease in costs associated with a portion of derivative instruments that settle through physical delivery. Partially offsetting these decreases was increased derivative losses from a decrease in fair value of the derivatives associated with economic hedges to secure natural gas feedstock for the Liquefaction Project. Cost of sales increased during the nine months ended September 30, 2019 from the nine months ended September 30, 2018 due to increased volumes of natural gas feedstock for our LNG sales as a result of substantial completion of Train 5 of the Liquefaction Project, partially offset by decreased pricing of natural gas feedstock between the periods. Partially offsetting the increase in cost of natural gas feedstock was decreased derivative losses from an increase in fair value of the derivatives associated with hedges to secure natural gas feedstock for the Liquefaction Project, due to a favorable shift in the long-term forward prices. Cost of sales also includes variable transportation and storage costs and other costs to convert natural gas into LNG.

Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Project. The increase in operating and maintenance expense (including affiliates) during the three and nine months ended September 30, 2019 from the three and nine months ended September 30, 2018 was primarily related to: (1) increased cost of turnaround and related activities at the Liquefaction Project, (2) increased TUA reservation charges paid to Total from payments under the partial TUA assignment agreement and (3) increased natural gas transportation and storage capacity demand charges paid to third parties from operating Train 5 of the Liquefaction Project following its substantial completion. Operating and maintenance expense (including affiliates) also includes payroll and benefit costs of operations personnel, insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the three and nine months ended September 30, 2019 from the three and nine months ended September 30, 2018 as a result of commencing operations of Train 5 of the Liquefaction Project, as the related assets began depreciating upon reaching substantial completion.

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Other expense (income)

	Three Months Ended September 30,								Nine Months Ended September 30,
(in millions)	2019			2018			Change		2019			2018			Change
Interest expense, net of capitalized interest	$	231		$	183		$	48	$	648		$	552		$	96
Loss on modification or extinguishment of debt	13			12			1		13			12			1
Derivative gain, net	—			(2		)	2		—			(13		)	13
Other income	(8		)	(8		)	—		(24		)	(19		)	(5		)
Total other expense	$	236		$	185		$	51	$	637		$	532		$	105

Interest expense, net of capitalized interest, increased during the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018, primarily as a result of a decrease in the portion of total interest costs that could be capitalized as an additional Train of the Liquefaction Project completed construction between the periods. For the three months ended September 30, 2019 and 2018, we incurred $246 million and $235 million of total interest cost, respectively, of which we capitalized $15 million and $52 million, respectively, which was primarily related to the construction of the Liquefaction Project. For the nine months ended September 30, 2019 and 2018, we incurred $718 million and $701 million of total interest cost, respectively, of which we capitalized $70 million and $149 million, respectively, which was primarily related to the construction of the Liquefaction Project.

Loss on modification or extinguishment of debt during the three and nine months ended September 30, 2019 increased from the comparable periods in 2018. The loss on modification or extinguishment of debt in 2019 of $13 million was related to the termination of $750 million of commitments under the 2019 CQP Credit Facilities in connection with the issuance of the 2029 CQP Senior Notes. Loss on modification or extinguishment of debt recognized in 2018 was attributable to the incurrence of third party fees and write off of unamortized debt issuance costs in September 2018 as a result of the termination of approximately $1.2 billion of commitments under the 2016 CQP Credit Facilities in connection with the issuance of the 2026 CQP Senior Notes.

Derivative gain, net decreased during the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018, as we no longer held interest rate swaps used to hedge a portion of the variable interest payments on our credit facilities, as they were terminated in October 2018.

Off-Balance Sheet Arrangements

As of September 30, 2019, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results. 

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the year ended December 31, 2018.

Recent Accounting Standards 

For descriptions of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation of our Notes to Consolidated Financial Statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Marketing and Trading Commodity Price Risk

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

	September 30, 2019					December 31, 2018
	Fair Value			Change in Fair Value		Fair Value			Change in Fair Value
Liquefaction Supply Derivatives	$	(24	)	$	6	$	(43	)	$	7

ITEM 4.     CONTROLS AND PROCEDURES

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

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

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PART II.    OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. There have been no material changes to the legal proceedings disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018 and in our Quarterly Report on Form 10-Q for the period ended June 30, 2019.

ITEM 1A. RISK FACTORS 

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2018.

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ITEM 6.     EXHIBITS

Exhibit No.	Description
1.1	Purchase Agreement, dated as of September 9, 2019, among the Partnership, the guarantors party thereto and RBC Capital Markets, LLC (Incorporated by reference to Exhibit 1.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on September 12, 2019)
4.1	Third Supplemental Indenture, dated as of September 12, 2019, among the Partnership, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on September 12, 2019)
10.1	Registration Rights Agreement, dated as of September 12, 2019, among the Partnership, the guarantors party thereto and RBC Capital Markets, LLC (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on September 12, 2019)
10.2*	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00002 Fuel Provisional Sum Closure, dated July 8, 2019, (ii) the Change Order CO-00003 Currency Provisional Sum Closure, dated July 8, 2019, (iii) the Change Order CO-00004 Foreign Trade Zone, dated July 2, 2019, (iv) the Change Order CO-00005 NGPL Gate Access Security Coordination Provisional Sum, dated July 17, 2019, (v) the Change Order CO-00006 Alternate to Adams Valves, dated August 14, 2019, (vi) the Change Order CO-00007 E-1503 to HRU Permanent Drain Piping, dated August 14, 2019, (vii) the Change Order CO-00008 Differing Subsurface Soil Conditions - Train 6 ISBL, dated August 27, 2019, (viii) the Change Order CO-00009 LNG Berth 3, dated September 25, 2019 and (iv) the Change Order CO-00010 Cold Box Redesign and Addition of Inspection Boxes on Methane Cold Box, dated September 16, 2019
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	Inline XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*	Filed herewith.
**	Furnished herewith.

49

SIGNATURES

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

		CHENIERE ENERGY PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC,
			its general partner
Date:	October 31, 2019	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	October 31, 2019	By:	/s/ Leonard E. Travis
			Leonard E. Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

50

EX-10.2

Exhibit 10.2

[***] indicates certain identified information has been excluded because it is both (a) not material and (b) would be competitively harmful if publicly disclosed.

CHANGE ORDER FORM

Fuel Provisional Sum Closure Change Order

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00002 DATE OF CHANGE ORDER: July 8, 2019

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

1. The Fuel Provisional Sum in Article 1.2 of Attachment EE, Schedule EE-1 of the Agreement prior to this Change Order was Nine Million, Two Hundred Twenty-One Thousand, Seven Hundred Seventy-Four U.S. Dollars (U.S. $9,221,774). The Provisional Sum is hereby increased by Three Hundred Eighty-Nine Thousand Two Hundred Fifty-Seven U.S. Dollars (U.S. $389,257), and the final value as amended by this Change Order shall be Nine Million, Six Hundred Eleven Thousand Thirty-One U.S. Dollars (U.S. $9,611,031). This Change Order closes the Fuel Provisional Sum in accordance with Article 1.2 of Attachment EE, Schedule EE-1 of the Agreement.

2. Pursuant to instructions in Article 1.2 of Attachment EE, Schedule EE-1 of the Agreement, Exhibit A to this Change Order illustrates the calculation of the final fuel costs in the Agreement.

3. Schedules C-1 and C-2 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit B of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,016,892,573
Net change by previously authorized Change Orders (CO-00001)...................................................................	$	—
The Contract Price prior to this Change Order was...........................................................................................	$	2,016,892,573
The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	389,257
The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order in the amount of	$	—
The Provisional Sum will be increased by this Change Order in the amount of...............................................	$	389,257
The Contract Price will be increased by this Change Order in the amount of...................................................	$	389,257
The new Contract Price including this Change Order will be...........................................................................	$	2,017,281,830

Adjustment to dates in Project Schedule for Subproject 6(a)

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

Adjustment to other Changed Criteria for Subproject 6(a): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes. See Exhibit B.

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

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

Adjustment to other Changed Criteria for Subproject 6(b): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

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

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

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

/s/ David Craft	/s/ Maurissa D. Rogers
Owner	Contractor
David Craft	Maurissa D. Rogers
Name	Name
SVP E&C	Sr Project Manager, PVP
Title	Title
July 8, 2019	July 8, 2019
Date of Signing	Date of Signing

CHANGE ORDER FORM

Currency Provisional Sum Closure Change Order

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00003 DATE OF CHANGE ORDER: July 8, 2019

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

1. The Currency Provisional Sum in Article 1.1 of Attachment EE, Schedule EE-1 of the Agreement prior to this Change Order was One Hundred Ninety-Six Million, Three Hundred Twenty-Five Thousand, Four Hundred Thirty-Nine U.S. Dollars (U.S. $196,325,439). The Currency Provisional Sum is hereby decreased by Six Million, Nine Hundred Fifty-Four Thousand, Five Hundred Seventy-Nine U.S. Dollars (U.S. $6,954,579) and the final value as amended by this Change Order shall be One Hundred Eighty-Nine Million, Three Hundred Seventy Thousand, Eight Hundred Sixty U.S. Dollars (U.S. $189,370,860). This Change Order closes the Currency Provisional Sum in accordance with Article 1.1 of Attachment EE, Schedule EE-1 of the Agreement.

2. Pursuant to instructions in Article 1.1 of Attachment EE, Schedule EE-1 of the Agreement, Exhibit A to this Change Order illustrates the calculation of the final currency costs in the Agreement.

3. Exhibit C of this Change Order includes the detailed spot and forward trades used to calculate the final currency costs in the Agreement.

4. Schedules C-1 and C-2 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit B of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,016,892,573
Net change by previously authorized Change Orders (00001-00002)...............................................................	$	389,257
The Contract Price prior to this Change Order was...........................................................................................	$	2,017,281,830
The Contract Price Applicable to Subproject 6(a) will be decreased by this Change Order in the amount of..	$	(6,954,579	)
The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order in the amount of	$	—
The Provisional Sum will be decreased by this Change Order in the amount of..............................................	$	(6,954,579	)
The Contract Price will be decreased by this Change Order in the amount of..................................................	$	(6,954,579	)
The new Contract Price including this Change Order will be...........................................................................	$	2,010,327,251

Adjustment to dates in Project Schedule for Subproject 6(a)

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

Adjustment to other Changed Criteria for Subproject 6(a): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes. See Exhibit B.

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

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

Adjustment to other Changed Criteria for Subproject 6(b): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

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

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

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

/s/ David Craft	/s/ Maurissa D. Rogers
Owner	Contractor
David Craft	Maurissa D. Rogers
Name	Name
SVP E&C	Sr Project Manager, PVP
Title	Title
July 17, 2019	July 8, 2019
Date of Signing	Date of Signing

CHANGE ORDER FORM

Foreign Trade Zone Change Order

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00004 DATE OF CHANGE ORDER: July 2, 2019

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

1. The purpose of this CO-00004 (the “Change Order”) is, subject to the terms of the Agreement and those described herein, to grant Contractor the use of Foreign-Trade Zone No. 291 in Cameron, Louisiana (the “FTZ”), which is more specifically defined in Exhibit A, (the “Zone Site”). The Cameron Port Commission was awarded a grant of authority by the United States Foreign-Trade Zones Board (the “FTZ Board”) to establish, operate and maintain the FTZ and has designated Cheniere Energy Partners, LP (“Cheniere”) to oversee the operations of the Zone Site as the Zone Operator, withinthe meaning of the Foreign Trade Zones Act of 1934, 19 U.S.C. Sec. 81 et. seq., as amended, and 19 C.F.R. Section 146.4, and with respect to procedures and activities occurring at the Zone Site. Owner is authorized to use the FTZ pursuant to the FTZ user agreement by and between Cheniere and Owner, which also expressly authorizes Owner to permit Contractor to use the FTZ.

2. Compliance with Laws: Subject to Section 6.2A.1 and 6.9 of the Agreement if a Change in Law occurs after the date of this Change Order, each Party shall perform its obligations under this Change Order in a manner consistent with good business practices and in full compliance with the Foreign-Trade Zones Act and any regulations adopted by the FTZ Board thereunder, the laws, and regulations governing the U.S. Customs and Border Protection (the “CBP”), and any applicable laws of the State of Louisiana and the United States of America, as in existence, or enacted, or amended during the term of the Agreement (collectively, “Applicable Authority”).

3. Contractor Responsibilities: Contractor’s responsibilities with respect to the FTZ operations at the Zone Site include, but are not limited to:

• Zone Site maintenance of an inventory control and recordkeeping system that meets the requirements of Applicable Authority;

• Preparation and submission of the in-bond filing to move imported materials from the Port of Arrival to the Zone Site;

• Within four (4) Business Days of the departure date of any shipment of materials destined for the FTZ, provision of copies of the in-bond filing and supporting documentation to the Owner and/or Owner’s tax consultant, including, but not limited to the bill of lading for such shipment;

• Preparation and submission of all FTZ-related forms with CBP (including admissions, transfers, and removals to or from the Zone Site), ensuring accurate and complete reporting of information;

• Provision of copies of all filings with CBP and supporting documentation, including, but not limited to, the following:

◦ For materials placed into commerce at frontier (i.e., materials admitted for consumption):

▪ Contractor shall provide Owner and/or Owner’s tax consultant with copies of CBP Form 7501 on or before the fourth (4th) business day following the entry date of any such shipment reported on CBP Form 7501;

◦ For any shipment of materials transported in-bond:

▪ Contractor shall provide Owner and/or Owner’s tax consultant with copies of CBP Form 7512 on or before the fourth (4th) business day following the entry date of any such shipment reported on CBP Form 7512

▪ Contractor shall provide Owner and/or Owner’s tax consultant with copies of CBP Form 214 on or before the tenth (10th) business day following the entry date of any such shipment reported on CBP Form 214

◦ For any materials in foreign-privilege status subsequently admitted into commerce for consumption:

▪ Contractor shall provide Owner and/or Owner’s tax consultant with copies of CBP Form 7501 on or before the fourth (4th) business day following the entry date of any such admitted materials as reported on CBP Form 7501

• Following removal of materials from the Zone Site, payment to CBP of all import duties and tariffs due on such removal;

• On a weekly basis, provision of inventory reports for all materials located at the Zone Site, including designation of materials admitted for consumption and materials admitted in foreign status;

• Provision of necessary information to Owner for its preparation and filing of the annual report to the FTZ Board; and

• Assistance during any compliance review from CBP, as requested by Owner.

4. US Customs and Border Protection: Contractor and Owner acknowledge and agree that a good working relationship with CBP is essential to an effective operation of a Foreign-Trade Zone and each Party shall use reasonable commercials efforts to maintain such a relationship. Contractor agrees to perform its duties and responsibilities in full cooperation with CBP.

5. Records: Parties shall maintain all books and records in connection with their responsibilities under this Change Order for a minimum term of five (5) years. Owner shall maintain its books and records for five (5) years after the materials have been removed from the Zones Site. Contractor shall keep and make available to Owner such books and records during the term of this Agreement and for a period of two (2) years thereafter or such greater period as may be required under Applicable Authority. The record keeping requirements shall survive the termination or expiration of the Agreement.

6. Documentation upon Expiration or Termination: At the expiration or termination of Contractor’s use of the FTZ for any reason, Contractor shall promptly provide to Owner all pertinent records and documents maintained by Contractor and needed by Owner in connection with the operation of the Zone Site. In addition, Contractor, shall provide assistance and information as reasonably requested by Owner in order to ensure a compliant transition of all documentation and reporting requirement under Applicable Authority. This provision shall survive the expiration or termination of the Contractor’s right to use the FTZ.

7. Additional Cost for Complying with FTZ: Owner agrees that Contractor shall have the right to recover additional, reasonable costs associated with compliance with the FTZ requirements.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,016,892,573
Net change by previously authorized Change Orders (CO-00003)...................................................................	$	(6,565,322	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,010,327,251
The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of........................................................................................................................................................................	$	—
The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order in the amount of	$	—
The Provisional Sum will be unchanged by this Change Order in the amount of.............................................	$	—
The Contract Price will be unchanged by this Change Order in the amount of................................................	$	—
The new Contract Price including this Change Order will be...........................................................................	$	2,010,327,251

Adjustment to dates in Project Schedule for Subproject 6(a)

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

Adjustment to other Changed Criteria for Subproject 6(a): (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule for Subproject 6(a): N/A

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

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

Adjustment to other Changed Criteria for Subproject 6(b): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

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

[B] This Change Ordershall notconstitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria andshall notbe deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

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

/s/ David Craft	/s/ Maurissa D. Rogers
Owner	Contractor
David Craft	Maurissa D. Rogers
Name	Name
SVP E&C	Sr Project Mgr, PVP
Title	Title
July 30, 2019	July 2, 2019
Date of Signing	Date of Signing

CHANGE ORDER FORM

NGPL Gate Access Security Coordination Provisional Sum Change Order

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00005 DATE OF CHANGE ORDER: July 17, 2019

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

1. In accordance with Article 6.1.B (Change Orders Requested by Owner), the Parties agree this Change Order implements a new Provisional Sum for Contractor to provide twenty-four (24) hours a day, seven (7) days a Week perimeter security and access coordination of the Duck Blind Road entrance to support Natural Gas Pipeline Company of America (“NGPL”) work at the Stage 4 Liquefaction Facility for an estimated duration of one (1) year upon commencement of the work by NGPL.

A. Owner’s original request for Contractor to provide gate access security for NGPL, including the scope of work, is documented under Owner Correspondence No. SPL4-BE-C19-009, Subject: Cooperation and Coordination with NGPL Work, dated 6 May 2019, is attached to this Change Order as Exhibit C.

B. Owner’s subsequent request for increased gate access security for a one-year duration is documented under Owner email correspondence Subject: NGPL Project - Bechtel 24/7 Security, dated 26 June 2019, is attached to this Change Order as Exhibit D.

C. Contractor’s acknowledgement of Owner’s request is documented under Contractor Correspondence No. 26012-100-T19-GAM-00021, Subject: Cooperation and Coordination with NGPL Work, dated 8 May 2019, is attached to this Change Order as Exhibit E.

2. Section EE-2 (Provisional Sums to be Adjusted during Project Execution) of Attachment EE (Provisional Sums) of the Agreement shall be amended by adding the new Provisional Sum under Section 2.4 as, “NGPL Security Coordination Provisional Sum” as follows:

2.4 NGPL Gate Access Security Coordination Provisional Sum

The Aggregate Provisional Sum contains a Provisional Sum of Two Hundred Thirty-Two Thousand, One Hundred Fifty-Eight U.S. Dollars (U.S. $232,158) (“NGPL Gate Access Security Coordination Provisional Sum”) for the cost for Contractor to provide twenty-four (24) hours a day, seven (7) days a Week security coordination of the Duck Blind Road access entrance to support work undertaken by Natural Gas Pipeline Company of America (“NGPL”) at the Stage 4 Liquefaction Facility. If the actual NGPL Gate Access Security Coordination costs under this Agreement is less than the NGPL Gate Access Security Coordination Provisional Sum, Owner shall be entitled to a Change Order reducing the Contract Price by such difference plus six percent (6%) of such difference. If the actual NGPL Gate Access Security Coordination costs under this Agreement is greater than the NGPL Gate Access Security Coordination Provisional Sum, Contractor shall be entitled to a Change Order increasing the Contract Price by such difference plus six percent (6%) of such difference.

3. The estimate basis for this new Provisional Sum is detailed in Exhibit A of this Change Order.

4. Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order. The final value will be trued-up on a separate Change Order based on the actual costs to close the NGPL Gate Access Security Provisional Sum.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,016,892,573
Net change by previously authorized Change Orders (00001-00004)...............................................................	$	(6,565,322	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,010,327,251
The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of........................................................................................................................................................................	$	232,158
The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order in the amount of	$	—
The Provisional Sum will be increased by this Change Order in the amount of...............................................	$	232,158
The Contract Price will be increased by this Change Order in the amount of...................................................	$	232,158
The new Contract Price including this Change Order will be...........................................................................	$	2,010,559,409

Adjustment to dates in Project Schedule for Subproject 6(a)

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

Adjustment to other Changed Criteria for Subproject 6(a): (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes, see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

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

Adjustment to other Changed Criteria for Subproject 6(b): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

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

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

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

/s/ David Craft	/s/ Maurissa Douglas Rogers
Owner	Contractor
David Craft	Maurissa Douglas Rogers
Name	Name
SVP Engineering & Construction	Sr Project Mgr, PVP
Title	Title
August 4, 2019	July 17, 2019
Date of Signing	Date of Signing

CHANGE ORDER FORM

Alternate to Adams Valves

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00006 DATE OF CHANGE ORDER: August 14, 2019

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

1. In accordance with Article 6.1.B (Change Orders Requested by Owner), the Parties agree this Change Order includes costs for Contractor to purchase the 600# Triple Offset Manual and Automated On/Off Valves from Emerson Vanessa in lieu of Adams Valves Inc. Direction provided in Owner’s Letter No. SPL4-BE-C19-007, dated March 25, 2019.

2. The detailed cost summary for this Change Order is included in Exhibit A of this Change Order.

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

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,016,892,573
Net change by previously authorized Change Orders (00001-00005)...............................................................	$	(6,333,164	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,010,559,409
The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of........................................................................................................................................................................	$	289,111
The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order in the amount of	$	—
The Provisional Sum will be increased by this Change Order in the amount of...............................................	$	—
The Contract Price will be increased by this Change Order in the amount of...................................................	$	289,111
The new Contract Price including this Change Order will be...........................................................................	$	2,010,848,520

Adjustment to dates in Project Schedule for Subproject 6(a)

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

Adjustment to other Changed Criteria for Subproject 6(a): (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes, see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

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

Adjustment to other Changed Criteria for Subproject 6(b): (insert N/A if no changes or impact; attach additional documentation

if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

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

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

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

/s/ David Craft	/s/ Maurissa Douglas Rogers
Owner	Contractor
David Craft	Maurissa Douglas Rogers
Name	Name
SVP E&C	Sr Project Mgr, PVP
Title	Title
August 28, 2019	August 14, 2019
Date of Signing	Date of Signing

CHANGE ORDER FORM

E-1503 to HRU Permanent Drain Piping

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00007 DATE OF CHANGE ORDER: August 14, 2019

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

1. In accordance with Article 6.1.B (Change Orders Requested by Owner), the Parties agree this Change Order includes costs for Contractor to add a permanent drain pipe from E-1503 to Heavies Removal Unit (HRU) as requested by Owner in Letter No. SPL4-BE-C19-005, dated March 14, 2019.

2. The detailed cost summary for this Change Order is included in Exhibit A of this Change Order.

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

4. The updated Piping & Instrumentation Diagram (P&ID) is provided in Exhibit C of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,016,892,573
Net change by previously authorized Change Orders (00001-00006)...............................................................	$	(6,044,053	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,010,848,520
The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of........................................................................................................................................................................	$	1,205,234
The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order in the amount of	$	—
The Provisional Sum will be increased by this Change Order in the amount of...............................................	$	—
The Contract Price will be increased by this Change Order in the amount of...................................................	$	1,205,234
The new Contract Price including this Change Order will be...........................................................................	$	2,012,053,754

Adjustment to dates in Project Schedule for Subproject 6(a)

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

Adjustment to other Changed Criteria for Subproject 6(a): (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes, see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

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

Adjustment to other Changed Criteria for Subproject 6(b): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

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

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

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

/s/ David Craft	/s/ Maurissa D. Rogers
Owner	Contractor
David Craft	Maurissa D. Rogers
Name	Name
SVP E&C	Sr Project Mgr, PVP
Title	Title
August 28, 2019	August 14, 2019
Date of Signing	Date of Signing

CHANGE ORDER FORM

Differing Subsurface Soil Conditions - Train 6 ISBL

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00008 DATE OF CHANGE ORDER: August 27, 2019

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

1. In accordance with Article 6 of the Agreement, Parties agree Contractor will be compensated for the costs associated with the additional piling Works due to encountered Subsurface Soil Conditions in Train 6 ISBL area that differ from the Design Basis of the Agreement.

A. Contractor analyzed the differing subsurface soil conditions in Train 6 ISBL areas. This Change order captures the cost impacts associated with the additional testing required to support analysis, resulting remediation work throughout Train 6 ISBL and the piles and tension connectors added to the following Train 6 ISBL areas: A01, B01, D01, F01, G01, H01, K01, L01 and N02. Refer to Exhibit C of this Change Order for the ISBL Plot Plan highlighting areas with additional piles.

B. The piling Works scope is complete in the Train 6 ISBL at the time of this Change Order. Should additional differing Subsurface Soil Conditions be encountered in Train 6 ISBL areas unrelated to the piling Works, or should differing Subsurface Soil Conditions be encountered outside the Train 6 ISBL areas, such conditions will be addressed in a future Change Order in accordance with the terms of the Agreement.

2. The detailed cost summary for this Change Order is included in Exhibit A of this Change Order.

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

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,016,892,573
Net change by previously authorized Change Orders (00001-00007)...............................................................	$	(4,838,819	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,012,053,754
The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of........................................................................................................................................................................	$	1,467,978
The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order in the amount of	$	—
The Provisional Sum will be increased by this Change Order in the amount of...............................................	$	—
The Contract Price will be increased by this Change Order in the amount of...................................................	$	1,467,978
The new Contract Price including this Change Order will be...........................................................................	$	2,013,521,732

Adjustment to dates in Project Schedule for Subproject 6(a)

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

Adjustment to other Changed Criteria for Subproject 6(a): (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes, see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

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

Adjustment to other Changed Criteria for Subproject 6(b): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

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

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

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

/s/ David Craft	/s/ Maurissa D. Rogers
Owner	Contractor
David Craft	Maurissa D. Rogers
Name	Name
SVP E&C	Sr Project Mgr, PVP
Title	Title
September 4, 2019	August 27, 2019
Date of Signing	Date of Signing

LNG BERTH 3 CHANGE ORDER

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00009 DATE OF CHANGE ORDER: September 25, 2019

The Agreement between the Parties listed above is changed as follows:

1. Per Section 4.10 of the Agreement, the Parties agree this LNG Berth 3 Change Order (“Change Order”) constitutes Owner’s Option for Contractor to perform the engineering, procurement, construction, pre-commissioning, commissioning, testing and startup of Subproject 6(b).

2. This Change Order is based on Owner’s issuance of the LNTPs and NTP as follows:

a. LNTP No. 1 for Subproject 6(b): Owner released Contractor to perform home office services through an initial Limited Notice to Proceed (“LNTP No. 1 for Subproject 6(b)”), under a Request for Services dated April 1, 2019 (“RFS No. 129378”), pursuant to the Technical Services Agreement dated February 28, 2018, between Sabine Pass Liquefaction, LLC and Contractor. This work is focused on engineering and other home office activities required to prepare for the necessary commitments under LNTP No. 2 for Subproject 6(b) and post-NTP for Subproject 6(b).

The scope of LNTP No. 1 for Subproject 6(b) requires a total cost and commitment to Owner of Fifteen Million U.S. Dollars (U.S.$15,000,000). Payment of such amount shall be within the time specified in LNTP No. 1 for Subproject 6(b). Without limitation, any services performed by Contractor pursuant to the scope of LNTP No. 1 under RFS No. 129378 are deemed to have been performed under the Agreement and all amounts paid by Owner to Contractor pursuant to the scope of LNTP No. 1 shall be credited against the Contract Price Applicable to Subproject 6(b). Notwithstanding anything to the contrary, this Change Order shall supersede RFS No. 129378 in its entirety with respect to Subproject 6(b).

b. LNTP No. 2 for Subproject 6(b): No later than October 1, 2019, Owner will release Contractor to perform pre-NTP activities for Subproject 6(b) through a second LNTP (“LNTP No. 2 for Subproject 6(b)”) in the form of Schedule H-7, as attached hereto. The scope under this LNTP No. 2 for Subproject 6(b) shall consist of the procurement of key Equipment (including bulk materials) and release of key Subcontracts, as further described in Schedule H-7. If Owner does not issue LNTP No. 2 for Subproject 6(b) on or before October 1, 2019, then Contractor shall be entitled to an adjustment to the Contract Price Applicable to Subproject 6(b) and the Guaranteed Substantial Completion Date for Subproject 6(b) if and to the extent caused by such delayed issuance of LNTP No. 2 for Subproject 6(b). Such adjustment shall include cost impacts caused by, for example, closing of vendor shops, unavailability of materials, labor unavailability, impacts on ability to attract and/or retain qualified labor, as well as escalation and loss of synergies with Contractor’s performance of Work for Subproject 6(a). For the avoidance of doubt, any adjustment to the Contract Price Applicable to Subproject 6(b) or the Project Schedule for Subproject 6(b) shall not be based on Contractor’s errors or omissions, a change in technology, or a change in material or Equipment quantities (except where the unavailability of materials, vendors or labor caused by such delayed issuance of LNTP No. 2 for Subproject 6(b) results in necessary changes to Equipment specifications). Contractor shall use commercially reasonable efforts and GECP to mitigate (i) the increase to the Contract Price Applicable to Subproject 6(b) and (ii) any adverse impact to the Project Schedule for Subproject 6(b). Such agreed-upon adjustment will be set forth in a Change Order.

The LNTP No. 2 for Subproject 6(b) scope will require an additional cost to Owner of Fifteen Million U.S. Dollars (U.S. $15,000,000). This amount is in addition to the Fifteen Million U.S. Dollars (U.S. $15,000,000) released under LNTP No. 1 for Subproject 6(b). Owner shall pay Contractor for Work performed pursuant to LNTP No. 2 for Subproject 6(b) in accordance with LNTP No. 2 for Subproject 6(b) once issued by Owner in accordance with this Section 2.b.

All Work performed under LNTP No. 1 for Subproject 6(b) and LNTP No. 2 for Subproject 6(b) shall be performed in accordance with the terms and conditions of the Agreement, and all payment for Work under LNTP No. 1 for

Subproject 6(b) and LNTP No. 2 for Subproject 6(b) shall be credited against the Contract Price Applicable to Subproject 6(b) and the first payments to become due hereunder if NTP for Subproject 6(b) is issued.

c. NTP for Subproject 6(b): No later than January 31, 2020, Owner shall issue NTP for Subproject 6(b) to Contractor for all remaining Work for the LNG Berth 3 in the form of Schedule H-3 to the Agreement. On or before issuance of NTP for Subproject 6(b), Contractor shall deliver to Owner a Letter of Credit for Subproject 6(b) in accordance with Section 9.2 of the Agreement. If Owner does not issue NTP for Subproject 6(b) on or before January 31, 2020, then Contractor shall be entitled to an adjustment to the Contract Price Applicable to Subproject 6(b) and the Guaranteed Substantial Completion Date for Subproject 6(b) if and to the extent caused by such delayed issuance of NTP for Subproject 6(b). Such adjustment shall be in accordance with Section 5.2C.2 of the Agreement.

3. The Contract Price Applicable to Subproject 6(b) is Four Hundred Fifty-Seven Million Six Hundred Ninety-Six Thousand U.S. Dollars (U.S.$457,696,000). The breakdown of the Contract Price Applicable to Subproject 6(b) is detailed in Exhibit 1 of this Change Order. The Contract Price Applicable to Subproject 6(b) includes any Provisional Sums applicable to Subproject 6(b).

4. The Parties hereby delete Section 20.2A of the Agreement in its entirety and replace it with the following:

“ A.    Delay Liquidated Damages. Subject to Section 20.2C, Contractor’s maximum liability to Owner for (i) Subproject 6(a) Delay Liquidated Damages is Ninety Million U.S. Dollars (U.S.$90,000,000), in the aggregate, and (ii) Subproject 6(b) Delay Liquidated Damages is Twenty Million Five Hundred Ninety-Six Thousand Three Hundred Twenty U.S. Dollars (U.S.$20,596,320), in the aggregate.”

5. Per Section 13.2C of the Agreement, the Schedule Bonus Date for SP6(b)” and “Schedule Bonus for SP6(b)” shall be as follows:

a. The “Schedule Bonus Date for SP6(b)” shall be either: (i) April 16, 2023, provided Owner issues NTP for Subproject 6(b) on or before January 31, 2020; or (ii) the date that is one thousand one hundred seventy-two (1172) Days from NTP for Subproject 6(b) if Owner issues NTP for Subproject 6(b) after January 31, 2020.

b. If Substantial Completion of Subproject 6(b) occurs before the Guaranteed Substantial Completion Date for SP6(b), and Contractor achieves Ready for Reduced Ship Loading prior to the Schedule Bonus Date for SP6(b), then Owner shall pay Contractor a bonus as set forth in this Section 5 (the “Schedule Bonus for SP6(b)”).

c. Notwithstanding anything to the contrary, the aggregate amount payable by Owner to Contractor under the Agreement for such Schedule Bonus for SP6(b) shall not exceed Fifteen Million U.S. Dollars (U.S.$15,000,000).

d. “Ready for Reduced Ship Loading” means that Subproject 6(b): (i) has achieved on average over a period of ten (10) continuous hours, a ship loading rate of at least 8,000m³ per hour for the transfer of LNG to an LNG Tanker (and return of vapor and boil-off gas to the LNG Tanks) using a single berth only and in accordance with the Ship Loading Time Conditions and testing procedures in Section 3.11.3 of Attachment S of the Agreement; and (ii) fully loaded such LNG Tanker (unless otherwise instructed by Owner).

e. Contractor shall give Owner one hundred eighty (180) Days’ prior written notice specifying the date on which Contractor expects Subproject 6(b) to be Ready for Reduced Ship Loading. Contractor shall give Owner a second written notice specifying the date on which Contractor expects Subproject 6(b) to be Ready for Reduced Ship Loading, which notice shall be given no later than one hundred twenty (120) Days prior to such date. Contractor shall give Owner a third written notice specifying the date on which Contractor expects Subproject 6(b) to be Ready for Reduced Ship Loading, which notice shall be given no later than sixty (60) Days prior to such date. Owner shall use commercially reasonable efforts to provide an LNG Tanker no earlier than seven (7) Days prior to and no later than seven (7) Days after the date in such third written notice. Owner shall also use commercially reasonable efforts to provide LNG for Contractor to load onto the LNG Tanker.

f. Contractor shall have forty-eight (48) hours after the LNG Tanker is “all fast” at LNG Berth 3 to achieve Ready for Reduced Ship Loading (“First Try”). If Contractor achieves Ready for Reduced Ship Loading on the First Try, Owner shall pay Contractor a Schedule Bonus for SP6(b) in the amount of Sixty Thousand U.S. Dollars (U.S. $60,000) for each Day occurring after the date that Ready for Reduced Ship Loading occurs and before the Schedule Bonus Date for SP6(b), subject to the aggregate limit set forth in Section 5.c above.

g. If Contractor does not achieve Ready for Reduced Ship Loading on the First Try, Contractor will receive no Schedule Bonus for SP6(b) for the First Try (except as set forth below) and Contractor shall give Owner a fourth written notice specifying the date on which Contractor expects Subproject 6(b) to be Ready for Reduced Ship Loading, which fourth notice shall be given no later than thirty (30) Days prior to such date. Owner shall use commercially reasonable efforts to provide LNG and a second LNG Tanker on the date that is no earlier than seven (7) Days prior to and not later than seven (7) Days after the date in such fourth written notice. Contractor shall have forty-eight (48) hours from the time that the second LNG Tanker is “all fast” at LNG Berth 3 to achieve Ready for Reduced Ship Loading (“Second Try”). Provided the date Contractor noticed Owner for the First Try was on or after two hundred fifty (250) Days prior to the Schedule Bonus Date for SP6(b) and Contractor achieves Ready for Reduced Ship Loading on the Second Try, Owner will pay Contractor a Schedule Bonus for SP6(b) in the amount of Thirty Thousand U.S. Dollars (U.S. $30,000) for each Day occurring from the date that the first LNG Tanker was “all fast” at LNG Berth 3 for the First Try until the date that Contractor achieves Ready for Reduced Ship Loading on the Second Try and Owner shall pay Contractor a Schedule Bonus for SP6(b) in the amount of Sixty Thousand U.S. Dollars (U.S. $60,000) for each Day occurring after the date Contractor achieves Ready for Reduced Ship Loading on the Second Try and before the Schedule Bonus Date for SP6(b), subject to the aggregate limit set forth in Section 5.c above. If Contractor fails to achieve Ready for Reduced Ship Loading on the Second Try, Owner shall have no obligation to pay Contractor the Schedule Bonus for SP6(b) and Contractor’s eligibility for the Schedule Bonus for SP6(b) shall terminate.

h. Owner’s obligations to provide an LNG Tanker and LNG shall be subject and subordinate to commercial and operational considerations involving the operation of the Sabine Liquefaction Facility and the marketing of LNG, including but not limited to LNG production or storage outages, lower than projected inventory, the priority of SPL’s LNG buyer needs, delay of the LNG Vessel, refusal of the owner, charterer or manager of the LNG Tanker to load at LNG Berth 3 and limitations on loading at a single berth. In such events, Owner shall have the right to suspend or cancel Ready for Reduced Ship Loading at its sole discretion without liability to Contractor. In the event of suspension, the time period to achieve Ready for Reduced Ship Loading will be tolled until loading can resume. In the event of cancellation, Owner and Contractor shall agree to reschedule and upon Contractor’s achievement of Ready for Reduced Ship Loading, Owner shall pay Contractor a Schedule Bonus for SP6(b) in the amount of Thirty Thousand U.S. Dollars (U.S. $30,000) for each Day occurring after the date in Contractor’s third written notice until the date that Contractor achieves Ready for Reduced Ship Loading and Owner shall pay Contractor a Schedule Bonus for SP6(b) in the amount of Sixty Thousand U.S. Dollars (U.S. $60,000) for each Day occurring after the date Contractor achieves Ready for Reduced Ship Loading and before the Schedule Bonus Date for SP6(b), subject to the aggregate limit set forth in Section 5.c above. Owner is not required to schedule such LNG Tanker until (i) there is sufficient LNG in storage in the LNG Tanks to evidence Ready for Reduced Ship Loading and (ii) Owner has an economic reason to export such LNG.

i. If Contractor is entitled to the Schedule Bonus for SP6(b) in accordance with Section 5.b of this Change Order No. 00009, Contractor shall invoice Owner the Schedule Bonus for SP6(b) upon achievement of Ready for Reduced Ship Loading; provided that, notwithstanding anything to the contrary, Contractor shall only be entitled to payment of the Schedule Bonus for SP6(b) if Contractor later achieves Substantial Completion of Subproject 6(b) prior to the Guaranteed Substantial Completion Date for SP6(b). Owner shall hold payment of such invoice in escrow until such time Contractor successfully completes the Ship Loading Time Test in accordance with Section 3.11.3 of Attachment S.

j. For the avoidance of doubt, Contractor shall not be entitled to a Schedule Bonus for SP6(b) should Ready for Reduced Ship Loading be achieved on or after the Schedule Bonus Date for SP6(b).

k. The Schedule Bonus Date for SP6(b) shall be subject to adjustment solely at the discretion of the President and Chief Executive Officer of Cheniere and any such adjustment shall be implemented by Change Order.

6. Replace Table A-2 of Schedule A-2 of Attachment A to the Agreement in its entirety with Table A-2 as attached to this Change Order, which incorporates the updated FEED deliverables for LNG Berth 3.

7. Add Schedule A-3 (“LNG Berth 3 Scope of Work”), as attached to this Change Order, to Attachment A to the Agreement.

8. Add Schedule C-3 (“Milestone Payment Schedule for Subproject 6(b)”), as attached to this Change Order, to Attachment C to the Agreement.

9. Add Schedule C-4 (“Monthly Payment Schedule for Subproject 6(b)”), as attached to this Change Order, to Attachment C to the Agreement.

10. Replace Attachment E to the Agreement in its entirety with Attachment E as attached to this Change Order.

11. Add Schedule H-7 (“Limited Notice to Proceed No. 2 for Subproject 6(b)”), as attached to this Change Order, to Attachment H to the Agreement.

12. Replace Attachment T to the Agreement in its entirety with Attachment T as attached to this Change Order, which incorporates the Subproject 6(b) Delay Liquidated Damages.

13. Replace Attachment U to the Agreement in its entirety with Attachment U as attached to this Change Order.

14. Replace Attachment Z to the Agreement in its entirety with Attachment Z as attached to this Change Order.

15. Add Schedule EE-3 (“Provisional Sums to be Fixed Based on Notice to Proceed for Subproject 6(b)”), as attached to this Change Order, to Attachment EE to the Agreement.

16. Add Schedule EE-4 (“Provisional Sums to be Adjusted during Project Execution for Subproject 6(b)”), as attached to this Change Order, to Attachment EE to the Agreement.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was................................................................	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#00001-00008)..........................................................................................................................................	$	(3,370,841	)
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was...................................	$	2,013,521,732
4.	The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of...................................................................................................................................................	$	—
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order................	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be...........................	$	2,013,521,732

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) was................................................................	$	—
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders.	$	—
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was..................................	$	—
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order in the amount of...................................................................................................................................................	$	457,696,000
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be..........................	$	457,696,000

Adjustment to Contract Price

13.	The original Contract Price was (add lines 1 and 7)..................................................................................	$	2,016,892,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)....................................................	$	2,013,521,732
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4 and 10)..........	$	457,696,000
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,471,217,732

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a): N/A

Adjustment to Payment Schedule for Subproject 6(a): N/A

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

• The Guaranteed Substantial Completion Date for Subproject 6(b) is One Thousand Four Hundred Seventy-Six (1,476) Days after issuance of LNTP No. 1 for Subproject 6(b).

• The Target Substantial Completion Date for Subproject 6(b) is One Hundred Sixty-Seven (167) Days before the Guaranteed Substantial Completion Date for Subproject 6(b).

Adjustment to other Changed Criteria for Subproject 6(b): See Attachment T as attached to this Change Order.

Adjustment to Payment Schedule for Subproject 6(b): See Schedule C-3 and Schedule C-4 as attached to this Change Order.

Adjustment to Design Basis for Subproject 6(b): See Table A-2 of Attachment A as attached to this Change Order.

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: See Attachment T as attached to this Change Order and Attachment U as attached to this Change Order.

Select either A or B:

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

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

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

/s/ David Craft	/s/ Maurissa D. Rogers
Owner	Contractor
David Craft	Maurissa D. Rogers
Name	Name
SVP E&C	Sr Project Manager, PVP
Title	Title
September 25, 2019	September 25, 2019
Date of Signing	Date of Signing

CHANGE ORDER FORM

Cold Box Redesign and Addition of Inspection Boxes on Methane Cold Box

PROJECT NAME:  Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00010 DATE OF CHANGE ORDER: September 16, 2019

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

1. In accordance with Article 6.1.B (Change Orders Requested by Owner), the Parties agree this Change Order includes costs associated with Owner’s request for Contractor to engage with the cold box Supplier (Linde) for a potential re-design of the Train 6 cold boxes to minimize the number of transition joints. This Change Order is in accordance with the approved Trend No. S4-0008, which includes the following:

i. Ethylene Cold Box, E-1504 A/B: Supplier to relocate transition joints from the vertical position to the horizontal position in the shop prior to shipment.

ii. Ethylene Cold Box, E-1504 A/B: Add an additional level transmitter. Supplier to add taps in the shop prior to shipment. Top tap will be outside the cold box (common with the existing level transmitter), and bottom tap to be added to piping below vessel (outside cold box). Level transmitter will be used to confirm there is no liquid remaining in the core prior to restart.

iii. Methane Cold Box: Supplier to remove individual transition joints on E-1605 ‘A’ pass inlet & outlet and replace with a single transition joint on inlet header for ‘A’ pass and aluminum flange on outlet of ‘A’ pass at PV-16002 in the shop prior to shipment.

The following P&IDs and design drawings will be revised to reflect this change (i through iii) upon execution of this Change Order:

•P&ID 26012-100-M6-4615-00004, Rev 000

•P&ID 26012-100-M6-4616-00001, Rev 000

•P&ID 26012-100-M6-4616-00026, Rev 000

•Linde Design Documents (Multiple)

2. In accordance with Article 6.1.B (Change Orders Requested by Owner), the Parties agree this Change Order includes costs associated with Owner’s request for Contractor to engage with the cold box Supplier (Linde) for the addition of inspection boxes on the Methane Cold Box. This Change Order is in accordance with the approved Trend No. S4-0036, which includes the following:

i. Methane Cold Box: Supplier to provide five (5) external inspection boxes around relocated transition joints on P11, N18, N20, N40 and flange on S13, in order to provide protection for the transition joint / flange and aluminum piping. All Work to be performed in Supplier’s shop prior to shipment.

The following P&IDs will be revised to reflect this change upon execution of this Change Order:

•P&ID 26012-100-M6-4616-00001, Rev 000

•P&ID 26012-100-M6-4616-00026, Rev 000

3. The detailed cost breakdown for the Train 6 Cold Box Redesign Scope of Work (Section 1 Above) of this Change Order is detailed in Exhibit A of this Change Order.

4. The detailed cost breakdown for the Addition of Inspection Boxes on Methane Cold Box Scope of Work (Section 2 Above) of this Change Order is detailed in Exhibit B of this Change Order

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

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,016,892,573
Net change by previously authorized Change Orders Applicable to Subproject 6(a) (00001-00008)..............	$	(3,370,841	)
The Contract Price prior to this Change Order was...........................................................................................	$	2,013,521,732
The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of........................................................................................................................................................................	$	1,956,641
The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order in the amount of	$	—
The Provisional Sum will be increased by this Change Order in the amount of...............................................	$	—
The Contract Price will be increased by this Change Order in the amount of...................................................	$	1,956,641
The new Contract Price including this Change Order will be...........................................................................	$	2,015,478,373

Adjustment to dates in Project Schedule for Subproject 6(a)

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

Adjustment to other Changed Criteria for Subproject 6(a): (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes, see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a): N/A

Adjustment to Design Basis for Subproject 6(a): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

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

Adjustment to other Changed Criteria for Subproject 6(b): (insert N/A if no changes or impact; attach additional documentation if necessary)N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

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

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

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this

and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Maurissa D. Rogers
Owner	Contractor
David Craft	Maurissa D. Rogers
Name	Name
SVP E&C	Sr Project Mgr, PVP
Title	Title
September 19, 2019	September 16, 2019
Date of Signing	Date of Signing

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

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

I, Jack A. Fusco, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: October 31, 2019

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

I, Michael J. Wortley, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: October 31, 2019

/s/ Michael J. Wortley

Michael J. Wortley

Chief Financial Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: October 31, 2019

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Wortley, Chief Financial Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: October 31, 2019

/s/ Michael J. Wortley

Michael J. Wortley

Chief Financial Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

XML

Unitholders' Equity (Details)	9 Months Ended
	Sep. 30, 2019 $ / 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]
Initial Quarterly Distributions Per Limited Partnership Unit Outstanding	$ 0.425
General Partner [Member] | Minimum [Member]
Other Ownership Interests [Line Items]
Distributions entitled by General Partner, Percentage	2.00%
Incentive Distribution, Quarterly Distribution Additional Target Percentage	15.00%
General Partner [Member] | Maximum [Member]
Other Ownership Interests [Line Items]
Incentive Distribution, Quarterly Distribution Additional Target Percentage	50.00%
Cheniere [Member] | Cheniere Energy Partners, LP [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	48.60%
Blackstone [Member] | Cheniere Energy Partners, LP [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	40.30%
Public [Member] | Cheniere Energy Partners, LP [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	9.10%

XML

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
Depreciation	$ 136	$ 104	$ 386	$ 310
Offsets to LNG terminal costs	$ 0	$ 0	$ 48	$ 0

XML

Leases - Future Minimum Payments Table (Details) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Operating Leases, Future Minimum Payments [Abstract]
Remainder of 2019		$ 3
2019	[1]		$ 10
2020		10	10	[1]
2021		10	10	[1]
2022		10	10	[1]
2023		10	10	[1]
Thereafter		125	124	[1]
Total lease payments		168	$ 174	[1]
Less: Interest		(78)
Present value of lease liabilities		$ 90

[1] Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components.

XML

Debt - Credit Facilities Table (Details) - USD ($)	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Outstanding balance, current	$ 0	$ 0
SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	1,200,000,000
Outstanding balance, current	0	0
Commitments prepaid or terminated	0
Letters of credit issued	414,000,000
Available commitment	$ 786,000,000
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Debt Instrument, Maturity Date	Dec. 31, 2020
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%
2019 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Original facility size	$ 1,500,000,000
Outstanding balance	0	$ 0
Commitments prepaid or terminated	750,000,000
Letters of credit issued	0
Available commitment	$ 750,000,000
Debt Instrument, Description of Variable Rate Basis	LIBOR or the base rate
Debt Instrument, Maturity Date	May 29, 2024
2019 CQP Credit Facilities - CQP Term Facility [Member]
Line of Credit Facility [Line Items]
Commitments prepaid or terminated	$ 750,000,000
2019 CQP Credit Facilities - CQP Term Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
2019 CQP Credit Facilities - CQP Term Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
2019 CQP Credit Facilities - CQP Revolving Facility [Member]
Line of Credit Facility [Line Items]
Outstanding balance	$ 0
2019 CQP Credit Facilities - CQP Revolving Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.25%
2019 CQP Credit Facilities - CQP Revolving Facility [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.25%
2019 CQP Credit Facilities - CQP Revolving Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.125%
2019 CQP Credit Facilities - CQP Revolving Facility [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.125%

XML

Revenues from Contracts with Customers - Schedule of Deferred Revenue Reconciliation (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	$ 116
Cash received but not yet recognized	169
Revenue recognized from prior period deferral	(116)
Deferred revenues, end of period	$ 169

XML

Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 1,707	$ 0
Restricted cash	185	1,541
Total cash, cash equivalents and restricted cash	$ 1,892	$ 1,541	$ 1,457	$ 1,589

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended					9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues
Revenues	$ 1,476			$ 1,529		$ 4,930	$ 4,529
Revenues from contracts with customers	1,475			1,529		4,928	4,529
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	742			756		2,501	2,291
Cost of sales—affiliate	6			0		6	0
Operating and maintenance expense	172			113		472	306
Operating and maintenance expense—affiliate	34			31		100	87
Development expense	0			1		0	2
General and administrative expense	3			3		9	9
General and administrative expense—affiliate	34			18		82	53
Depreciation and amortization expense	138			107		390	318
Impairment expense and loss on disposal of assets	1			8		6	8
Total operating costs and expenses	1,130			1,037		3,566	3,074
Income (loss) from operations	346			492		1,364	1,455
Other income (expense)
Interest expense, net of capitalized interest	(231)			(183)		(648)	(552)
Loss on modification or extinguishment of debt	(13)			(12)		(13)	(12)
Derivative gain, net	0			2		0	13
Other income	8			8		24	19
Total other income (expense)	(236)			(185)		(637)	(532)
Net income	$ 110	$ 232	$ 385	$ 307	$ 335	$ 727	$ 923
Basic and diluted net income per common unit	$ 0.19			$ 0.60		$ 1.38	$ 1.82
Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation	348.6			348.6		348.6	348.6
LNG [Member]
Revenues
Revenues	$ 1,140			$ 1,249		$ 3,678	$ 3,419
Revenues from contracts with customers	1,139			1,249		3,676	3,419
LNG—affiliate [Member]
Revenues
Revenues from contracts with customers	257			205		1,017	886
Regasification [Member]
Revenues
Revenues from contracts with customers	66			66		199	196
Other [Member]
Revenues
Revenues from contracts with customers	$ 13			$ 9		$ 36	$ 28

XML

Nature of Operations and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2019

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, 2018.

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.

Recent Accounting Standards

Recent Accounting Standards

We adopted ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard resulted in the recognition of right-of-use assets and lease liabilities for operating leases of approximately $100 million on our Consolidated Balance Sheets, with no material impact on our Consolidated Statements of Income or Consolidated Statements of Cash Flows. We have elected the practical expedients to (1) carryforward prior conclusions related to lease identification and classification for existing leases, (2) combine lease and non-lease components of an arrangement for all classes of leased assets, (3) omit short-term leases with a term of 12 months or less from recognition on the balance sheet and (4) carryforward our existing accounting for land easements not previously accounted for as leases. See Note 11—Leases for additional information on our leases following the adoption of this standard.

XML

Net Income per Common Unit

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Net Income per Common Unit

NET INCOME PER COMMON UNIT

Net income 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 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 Statements of Partners’ Equity. On October 28, 2019, we declared a $0.62 distribution per common unit and subordinated unit and the related distribution to our general partner and IDR holders to be paid on November 14, 2019 to unitholders of record as of November 7, 2019 for the period from July 1, 2019 to September 30, 2019.

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

				Limited Partner Units
	Total			Common Units			Subordinated Units			General Partner Units			IDR
Three Months Ended September 30, 2019
Net income	$	110
Declared distributions	323			217			84			6			16
Assumed allocation of undistributed net loss (1)	$	(213	)	(151		)	(58		)	(4		)	—
Assumed allocation of net income				$	66		$	26		$	2		$	16
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	0.19		$	0.19
Three Months Ended September 30, 2018
Net income	$	307
Declared distributions	297			202			79			5			11
Assumed allocation of undistributed net income (1)	$	10		7			3			—			—
Assumed allocation of net income				$	209		$	82		$	5		$	11
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit (2)				$	0.60		$	0.60
Nine Months Ended September 30, 2019
Net income	$	727
Declared distributions	949			638			248			19			44
Assumed allocation of undistributed net loss (1)	$	(222	)	(157		)	(61		)	(4		)	—
Assumed allocation of net income				$	481		$	187		$	15		$	44
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	1.38		$	1.38
Nine Months Ended September 30, 2018
Net income	$	923
Declared distributions	859			589			229			17			24
Assumed allocation of undistributed net income (1)	$	64		45			18			1			—
Assumed allocation of net income				$	634		$	247		$	18		$	24
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	1.82		$	1.82

(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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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

As of September 30, 2019 and December 31, 2018, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2019			2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	16,807		$	12,760
LNG terminal construction-in-process	1,196			3,913
Accumulated depreciation	(1,671		)	(1,290		)
Total LNG terminal costs, net	16,332			15,383
Fixed assets
Fixed assets	26			26
Accumulated depreciation	(20		)	(19		)
Total fixed assets, net	6			7
Property, plant and equipment, net	$	16,338		$	15,390

 

Depreciation expense was $136 million and $104 million during the three months ended September 30, 2019 and 2018, respectively, and $386 million and $310 million during the nine months ended September 30, 2019 and 2018, respectively.

We realized offsets to LNG terminal costs of $48 million during the nine months ended September 30, 2019 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 Trains of the Liquefaction Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs during the three months ended September 30, 2019 and in the three and nine months ended September 30, 2018.

XML

Unitholders' Equity

9 Months Ended

Sep. 30, 2019

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 accumulated 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.

As of September 30, 2019, Cheniere, Blackstone CQP Holdco and the public owned a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere’s ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.

XML

Debt

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Debt

DEBT

As of September 30, 2019 and December 31, 2018, our debt consisted of the following (in millions):

	September 30,			December 31,
	2019			2018
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			1,100
4.500% Senior Notes due 2029 (“2029 CQP Senior Notes”)	1,500			—
2016 CQP Credit Facilities	—			—
CQP Credit Facilities entered into in 2019 (“2019 CQP Credit Facilities”)	—			—
Unamortized premium, discount and debt issuance costs, net	(179		)	(184		)
Total long-term debt, net	17,571			16,066
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	17,571		$	16,066

2019 Debt Issuances and Terminations

2029 CQP Senior Notes

In September 2019, we issued an aggregate principal amount of $1.5 billion of the 2029 CQP Senior Notes, which are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (the “CQP Guarantors”). The proceeds of the offering were used to prepay the outstanding balance of the $750 million term loan under the 2019 CQP Credit Facilities (“CQP Term Facility”) and for general corporate purposes, including funding future capital expenditures in connection with the construction of Train 6 at the Liquefaction Project, resulting in the recognition of debt modification and extinguishment costs of $13 million for the three and nine months ended September 30, 2019. As of September 30, 2019, only the $750 million revolving credit facility (“CQP Revolving Facility”), all of which is undrawn, remains as part of the 2019 CQP Credit Facilities.

Borrowings under the 2029 CQP Senior Notes accrue interest at a fixed rate of 4.500% per annum, and interest on the 2029 CQP Senior Notes is payable semi-annually in cash in arrears. The 2029 CQP Senior Notes are governed by the same base indenture as the 2025 CQP Senior Notes and the 2026 CQP Senior Notes (the “CQP Base Indenture”), and are further governed by the Third Supplemental Indenture (together with the CQP Base Indenture, the “2029 CQP Notes Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the 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.

At any time prior to October 1, 2024, we may redeem all or a part of the 2029 CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus the “applicable premium” set forth in the 2029 CQP Notes Indenture, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2022, we may redeem up to 35% of the aggregate principal amount of the 2029 CQP Senior Notes with an amount

of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. At any time on or after October 1, 2024 through the maturity date of October 1, 2029, we may redeem the 2029 CQP Senior Notes, in whole or in part, at the redemption prices set forth in the 2029 CQP Notes Indenture.

The 2025 CQP Senior Notes, the 2026 CQP Senior Notes and the 2029 CQP Senior Notes (collectively, the “CQP Senior Notes”) are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

In connection with the closing of the 2029 CQP Senior Notes offering, we and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, we and the CQP Guarantors have agreed to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2029 CQP Senior Notes for a like aggregate principal amount of our debt securities with terms identical in all material respects to the 2029 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after the notes issuance date of September 12, 2019. Under specified circumstances, we and the CQP Guarantors have also agreed to cause to become effective a shelf registration statement relating to resales of the 2029 CQP Senior Notes. We will be obligated to pay additional interest on the 2029 CQP Senior Notes if we fail to comply with our obligation to register the 2029 CQP Senior Notes within the specified time period.

2016 CQP Credit Facilities

In May 2019, the remaining commitments under the 2016 CQP Credit Facilities were terminated. There were no write-offs of discounts, premiums and debt issuance costs associated with the termination of the 2016 CQP Credit Facilities.

2019 CQP Credit Facilities

In May 2019, we entered into the 2019 CQP Credit Facilities, which consisted of the $750 million CQP Term Facility, which was prepaid and terminated upon issuance of the 2029 CQP Senior Notes in September 2019, and the $750 million CQP Revolving Facility. Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the Liquefaction Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit.

Loans under the 2019 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50%, and the adjusted one-month LIBOR plus 1.0%), plus the applicable margin. Under the CQP Term Facility, the applicable margin for LIBOR loans was 1.50% per annum, and the applicable margin for base rate loans was 0.50% per annum. Under the CQP Revolving Facility, the applicable margin for LIBOR loans is 1.25% to 2.125% per annum, and the applicable margin for base rate loans is 0.25% to 1.125% per annum, in each case depending on our then-current rating. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three-month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit our ability to make restricted

payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.

The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted encumbrances) on substantially all of our and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2019 (in millions):

	SPL Working Capital Facility (1)		2019 CQP Credit Facilities
Original facility size	$	1,200	$	1,500
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		750
Letters of credit issued	414		—
Available commitment	$	786	$	750
Interest rate on available balance	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Maturity date	December 31, 2020		May 29, 2024

(1) The SPL Working Capital Facility was amended in May 2019 in connection with commercialization and financing of Train 6 of the Liquefaction Project. All terms of the SPL Working Capital Facility substantially remained unchanged.

Restrictive Debt Covenants

As of September 30, 2019, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Total interest cost	$	246		$	235		$	718		$	701
Capitalized interest	(15		)	(52		)	(70		)	(149		)
Total interest expense, net	$	231		$	183		$	648		$	552

Fair Value Disclosures

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

	September 30, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	16,780	$	18,340	$	15,275	$	15,672
2037 SPL Senior Notes (2)	791		909		791		817
Credit facilities (3)	—		—		—		—

(1) Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2026

CQP Senior Notes and 2029 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, 2016 CQP Credit Facilities and 2019 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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Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2019

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

As of September 30, 2019 and December 31, 2018, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Interest costs and related debt fees	$	217	$	224
Accrued natural gas purchases	254		518
LNG terminal and related pipeline costs	161		79
Other accrued liabilities	25		—
Total accrued liabilities	$	657	$	821

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2019

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
LNG revenues—affiliate
Cheniere Marketing Agreements	$	255	$	205	$	1,015	$	886
Contracts for Sale and Purchase of Natural Gas and LNG	2		—		2		—
Total LNG revenues—affiliate	257		205		1,017		886
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	6		—		6		—
Operating and maintenance expense—affiliate
Services Agreements	34		31		100		87
General and administrative expense—affiliate
Services Agreements	34		18		82		53

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Other Non-Current Assets (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Other Assets, Noncurrent [Abstract]
Advances made to municipalities for water system enhancements	$ 88	$ 90
Advances and other asset conveyances to third parties to support LNG terminals	35	36
Tax-related payments and receivables	17	17
Information technology service prepayments	8	20
Advances made under EPC and non-EPC contracts	2	14
Other	7	7
Other non-current assets, net	$ 157	$ 184

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Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ 34	$ 11	$ (25)	$ 43
Realized and mark-to-market gains (losses):
Included in cost of sales		(42)	4	(22)	(5)
Purchases and settlements:
Purchases		(1)	4	(4)	8
Settlements		1	1	43	(27)
Transfers out of Level 3	[1]	0	(1)	0	0
Balance, end of period		(8)	19	(8)	19
Change in unrealized gains (losses) relating to instruments still held at end of period		$ (42)	$ 4	$ (22)	$ (5)

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

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Supplemental Guarantor Information - Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended					9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues
Revenues	$ 1,476			$ 1,529		$ 4,930	$ 4,529
Revenues from contracts with customers	1,475			1,529		4,928	4,529
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	742			756		2,501	2,291
Cost of sales—affiliate	6			0		6	0
Operating and maintenance expense	172			113		472	306
Operating and maintenance expense—affiliate	34			31		100	87
Research and Development Expense	0			1		0	2
General and administrative expense	3			3		9	9
General and administrative expense—affiliate	34			18		82	53
Depreciation and amortization expense	138			107		390	318
Impairment expense and loss on disposal of assets	1			8		6	8
Total operating costs and expenses	1,130			1,037		3,566	3,074
Income (loss) from operations	346			492		1,364	1,455
Other income (expense)
Interest expense, net of capitalized interest	(231)			(183)		(648)	(552)
Loss on modification or extinguishment of debt	(13)			(12)		(13)	(12)
Derivative gain, net	0			2		0	13
Equity earnings of subsidiaries	0			0		0	0
Other income (expense)	8			8		24	19
Total other income (expense)	(236)			(185)		(637)	(532)
Net income	110	$ 232	$ 385	307	$ 335	727	923
LNG [Member]
Revenues
Revenues	1,140			1,249		3,678	3,419
Revenues from contracts with customers	1,139			1,249		3,676	3,419
LNG—affiliate [Member]
Revenues
Revenues from contracts with customers	257			205		1,017	886
Regasification [Member]
Revenues
Revenues from contracts with customers	66			66		199	196
Regasification—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Other [Member]
Revenues
Revenues from contracts with customers	13			9		36	28
Other—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Parent Issuer [Member]
Revenues
Revenues	0			0		0	0
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	0			0		0	0
Cost of sales—affiliate	0			0		0	0
Operating and maintenance expense	0			0		0	0
Operating and maintenance expense—affiliate	0			0		0	0
Research and Development Expense				0			0
General and administrative expense	1			1		3	3
General and administrative expense—affiliate	4			3		10	9
Depreciation and amortization expense	1			1		2	2
Impairment expense and loss on disposal of assets	0			0		0	0
Total operating costs and expenses	6			5		15	14
Income (loss) from operations	(6)			(5)		(15)	(14)
Other income (expense)
Interest expense, net of capitalized interest	(47)			(36)		(120)	(104)
Loss on modification or extinguishment of debt	(13)			(12)		(13)	(12)
Derivative gain, net				2			13
Equity earnings of subsidiaries	170			354		860	1,030
Other income (expense)	6			4		15	10
Total other income (expense)	116			312		742	937
Net income	110			307		727	923
Parent Issuer [Member] | LNG [Member]
Revenues
Revenues	0			0		0	0
Parent Issuer [Member] | LNG—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Parent Issuer [Member] | Regasification [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Parent Issuer [Member] | Regasification—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Parent Issuer [Member] | Other [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Parent Issuer [Member] | Other—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Guarantors [Member]
Revenues
Revenues	180			187		591	601
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	0			0		0	2
Cost of sales—affiliate	6			0		6	0
Operating and maintenance expense	22			17		74	48
Operating and maintenance expense—affiliate	5			39		76	113
Research and Development Expense				1			1
General and administrative expense	1			1		2	2
General and administrative expense—affiliate	8			6		22	17
Depreciation and amortization expense	21			19		58	56
Impairment expense and loss on disposal of assets	0			8		0	8
Total operating costs and expenses	63			91		238	247
Income (loss) from operations	117			96		353	354
Other income (expense)
Interest expense, net of capitalized interest	(1)			(1)		(4)	(3)
Loss on modification or extinguishment of debt	0			0		0	0
Derivative gain, net				0			0
Equity earnings of subsidiaries	48			243		506	678
Other income (expense)	(1)			(1)		0	0
Total other income (expense)	46			241		502	675
Net income	163			337		855	1,029
Guarantors [Member] | LNG [Member]
Revenues
Revenues	0			0		0	0
Guarantors [Member] | LNG—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Guarantors [Member] | Regasification [Member]
Revenues
Revenues from contracts with customers	66			66		199	196
Guarantors [Member] | Regasification—affiliate [Member]
Revenues
Revenues from contracts with customers	65			64		196	194
Guarantors [Member] | Other [Member]
Revenues
Revenues from contracts with customers	13			9		36	28
Guarantors [Member] | Other—affiliate [Member]
Revenues
Revenues from contracts with customers	36			48		160	183
Non-Guarantors [Member]
Revenues
Revenues	1,397			1,454		4,695	4,305
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	742			758		2,501	2,291
Cost of sales—affiliate	17			8		35	23
Operating and maintenance expense	150			96		398	258
Operating and maintenance expense—affiliate	113			107		335	317
Research and Development Expense				0			1
General and administrative expense	1			1		4	4
General and administrative expense—affiliate	28			12		64	36
Depreciation and amortization expense	117			88		331	261
Impairment expense and loss on disposal of assets	1			0		6	0
Total operating costs and expenses	1,169			1,070		3,674	3,191
Income (loss) from operations	228			384		1,021	1,114
Other income (expense)
Interest expense, net of capitalized interest	(183)			(146)		(524)	(445)
Loss on modification or extinguishment of debt	0			0		0	0
Derivative gain, net				0			0
Equity earnings of subsidiaries	0			0		0	0
Other income (expense)	3			5		9	9
Total other income (expense)	(180)			(141)		(515)	(436)
Net income	48			243		506	678
Non-Guarantors [Member] | LNG [Member]
Revenues
Revenues	1,140			1,249		3,678	3,419
Non-Guarantors [Member] | LNG—affiliate [Member]
Revenues
Revenues from contracts with customers	257			205		1,017	886
Non-Guarantors [Member] | Regasification [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Non-Guarantors [Member] | Regasification—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Non-Guarantors [Member] | Other [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Non-Guarantors [Member] | Other—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Eliminations [Member]
Revenues
Revenues	(101)			(112)		(356)	(377)
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	0			(2)		0	(2)
Cost of sales—affiliate	(17)			(8)		(35)	(23)
Operating and maintenance expense	0			0		0	0
Operating and maintenance expense—affiliate	(84)			(115)		(311)	(343)
Research and Development Expense				0			0
General and administrative expense	0			0		0	0
General and administrative expense—affiliate	(6)			(3)		(14)	(9)
Depreciation and amortization expense	(1)			(1)		(1)	(1)
Impairment expense and loss on disposal of assets	0			0		0	0
Total operating costs and expenses	(108)			(129)		(361)	(378)
Income (loss) from operations	7			17		5	1
Other income (expense)
Interest expense, net of capitalized interest	0			0		0	0
Loss on modification or extinguishment of debt	0			0		0	0
Derivative gain, net				0			0
Equity earnings of subsidiaries	(218)			(597)		(1,366)	(1,708)
Other income (expense)	0			0		0	0
Total other income (expense)	(218)			(597)		(1,366)	(1,708)
Net income	(211)			(580)		(1,361)	(1,707)
Eliminations [Member] | LNG [Member]
Revenues
Revenues	0			0		0	0
Eliminations [Member] | LNG—affiliate [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Eliminations [Member] | Regasification [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Eliminations [Member] | Regasification—affiliate [Member]
Revenues
Revenues from contracts with customers	(65)			(64)		(196)	(194)
Eliminations [Member] | Other [Member]
Revenues
Revenues from contracts with customers	0			0		0	0
Eliminations [Member] | Other—affiliate [Member]
Revenues
Revenues from contracts with customers	$ (36)			$ (48)		$ (160)	$ (183)

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Supplemental Guarantor Information - Condensed Consolidating Cash Flows - Balances per Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	$ 1,707	$ 0
Restricted cash	185	1,541
Total cash, cash equivalents and restricted cash	1,892	1,541	$ 1,457	$ 1,589
Parent Issuer [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	1,701	0
Restricted cash	0	779
Total cash, cash equivalents and restricted cash	1,701	779	799	1,033
Guarantors [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	6	0
Restricted cash	0	6
Total cash, cash equivalents and restricted cash	6	6	9	12
Non-Guarantors [Member]
Balances per Consolidated Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	185	756
Total cash, cash equivalents and restricted cash	185	756	649	544
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

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Related Party Transactions - LNG Terminal Capacity Agreements (Details) MMBTU in Millions	1 Months Ended	9 Months Ended
	May 31, 2019 USD ($) MMBTU Cargo	Sep. 30, 2019 USD ($) bcf / d	Dec. 31, 2018 USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate		$ 67,000,000	$ 114,000,000
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
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		$ 3.00
Letter Agreement [Member] | Cheniere Marketing [Member] | SPL [Member]
Related Party Transaction [Line Items]
Contract Volumes | MMBTU	70
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 2.00
Letter Agreement [Member] | Cheniere Marketing [Member] | SPL [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	20

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Net Income per Common Unit - Schedule of Net Income per Unit and Allocation of Distribution (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended							9 Months Ended
		Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018		Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 110	$ 232	$ 385	$ 307			$ 335	$ 727	$ 923
Declared distributions		323			297				949	859
Assumed allocation of undistributed net income (loss)	[1]	$ (213)			$ 10				$ (222)	$ 64
Weighted average units outstanding		348.6			348.6				348.6	348.6
Basic and diluted net income per unit		$ 0.19			$ 0.60				$ 1.38	$ 1.82
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 77	164	272	$ 216		$ 199	236
Declared distributions		217			202				$ 638	$ 589
Assumed allocation of undistributed net income (loss)	[1]	(151)			7				(157)	45
Assumed allocation of net income		$ 66			$ 209				$ 481	$ 634
Weighted average units outstanding		348.6			348.6				348.6	348.6
Basic and diluted net income per unit		$ 0.19			$ 0.60	[2]			$ 1.38	$ 1.82
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 30	64	105	$ 84		77	92
Declared distributions		84			79				$ 248	$ 229
Assumed allocation of undistributed net income (loss)	[1]	(58)			3				(61)	18
Assumed allocation of net income		$ 26			$ 82				$ 187	$ 247
Weighted average units outstanding		135.4			135.4				135.4	135.4
Basic and diluted net income per unit		$ 0.19			$ 0.60	[2]			$ 1.38	$ 1.82
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 3	$ 4	$ 8	$ 7		$ 5	$ 7
Declared distributions		6			5				$ 19	$ 17
Assumed allocation of undistributed net income (loss)	[1]	(4)			0				(4)	1
Assumed allocation of net income		2			5				15	18
IDR [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions		16			11				44	24
Assumed allocation of undistributed net income (loss)	[1]	0			0				0	0
Assumed allocation of net income		$ 16			$ 11				$ 44	$ 24

[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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Leases

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Leases

LEASES

Our leased assets consist primarily of tug vessels and land sites, all of which are classified as operating leases.

ASC 842 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. As our leases generally do not provide an implicit rate, in order to calculate the lease liability, we discounted our expected future lease payments using our relevant subsidiary’s incremental borrowing rate at the later of January 1, 2019 or the commencement date of the lease. The incremental borrowing rate is an estimate of the rate of interest that a given subsidiary would have to pay to borrow on a collateralized basis over a similar term to that of the lease term.

Many of our leases contain renewal options exercisable at our sole discretion. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability only to the extent they are reasonably certain to be exercised, such as when necessary to satisfy obligations that existed at the execution of the lease or when the non-renewal would otherwise result in an economic penalty.

We have elected the practical expedient to omit leases with an initial term of 12 months or less (“short-term lease”) from recognition on the balance sheet. We recognize short-term lease payments on a straight-line basis over the lease term and variable payments under short-term leases in the period in which the obligation is incurred.

Certain of our leases contain non-lease components which are not separated from the lease components when calculating the right-of-use asset and lease liability per our use of the practical expedient to combine both components of an arrangement for all classes of leased assets.

Certain of our leases also contain variable payments, such as inflation, that are not included when calculating the right-of-use asset and lease liability unless the payments are in-substance fixed. We recognize lease expense for operating leases on a straight-line basis over the lease term.

The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):

	Consolidated Balance Sheet Location	September 30, 2019
Right-of-use assets—Operating	Operating lease assets, net	$	91
Current operating lease liabilities	Current operating lease liabilities	6
Non-current operating lease liabilities	Non-current operating lease liabilities	84

The following table shows the classification and location of our lease cost on our Consolidated Statements of Income (in millions):

	Consolidated Statement of Income Location	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost (1)	Operating costs and expenses (2)	$	2	$	8

(1)    Includes $1 million of variable lease costs.

(2) Presented in cost of sales, operating and maintenance expense, general and administrative expense or general and administrative expense—affiliate consistent with the nature of the asset under lease.

Future annual minimum lease payments for operating leases as of September 30, 2019 are as follows (in millions): 

Years Ending December 31,	Operating Leases
2019	$	3
2020	10
2021	10
2022	10
2023	10
Thereafter	125
Total lease payments	168
Less: Interest	(78		)
Present value of lease liabilities	$	90

Future annual minimum lease payments for operating leases as of December 31, 2018, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows (in millions):

Years Ending December 31,	Operating Leases (1)
2019	$	10
2020	10
2021	10
2022	10
2023	10
Thereafter	124
Total	$	174

(1) Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components.

The following table shows the weighted-average remaining lease term (in years) and the weighted-average discount rate for our operating leases:

	September 30, 2019
Weighted-average remaining lease term (in years)	25.9
Weighted-average discount rate	4.8	%

The following table includes other quantitative information for our operating leases (in millions):

	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	7

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Derivative Instruments

9 Months Ended

Sep. 30, 2019

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 or fair value hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Income to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2019 and December 31, 2018, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2019												December 31, 2018
	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 (liability)	$	(6	)	$	(10	)	$	(8	)	$	(24	)	$	5	$	(23	)	$	(25	)	$	(43	)

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 observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of September 30, 2019 and December 31, 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

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 natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2019:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$(8)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.618) - $0.056

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Balance, beginning of period	$	34		$	11		$	(25	)	$	43
Realized and mark-to-market gains (losses):
Included in cost of sales	(42		)	4			(22		)	(5		)
Purchases and settlements:
Purchases	(1		)	4			(4		)	8
Settlements	1			1			43			(27		)
Transfers out of Level 3 (1)	—			(1		)	—			—
Balance, end of period	$	(8	)	$	19		$	(8	)	$	19
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(42	)	$	4		$	(22	)	$	(5	)

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

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. 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, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of netting and any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

Interest Rate Derivatives

We previously had interest rate swaps (“CQP Interest Rate Derivatives” and, collectively with the CCH Interest Rate Derivatives and the CCH Interest Rate Forward Start Derivatives, the “Interest Rate Derivatives”) to hedge a portion of the variable interest payments on our credit facilities. In October 2018, we terminated the CQP Interest Rate Derivatives related to the 2016 CQP Credit Facilities and realized a derivative gain of $28 million.

Liquefaction Supply Derivatives

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

SPL had secured up to approximately 4,108 TBtu and 3,464 TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2019 and December 31, 2018, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 3,880 TBtu and 2,978 TBtu as of September 30, 2019 and December 31, 2018, respectively.

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

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	September 30, 2019			December 31, 2018
Derivative assets	$	8		$	6
Non-current derivative assets	29			31
Total derivative assets	37			37
Derivative liabilities	(29		)	(66		)
Non-current derivative liabilities	(32		)	(14		)
Total derivative liabilities	(61		)	(80		)
Derivative liability, net	$	(24	)	$	(43	)

(1) Does not include collateral calls of $10 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018, respectively.

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 and nine months ended September 30, 2019 and 2018 (in millions):

		Three Months Ended September 30,					Nine Months Ended September 30,
	Consolidated Statement of Income Location (1)	2019			2018		2019		2018
Liquefaction Supply Derivatives gain	LNG revenues	$	1		$	—	$	2	$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	(55		)	10		28		(42		)

(1) Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

Consolidated Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2019
Liquefaction Supply Derivatives	$	40		$	(3	)	$	37
Liquefaction Supply Derivatives	(63		)	2			(61		)
As of December 31, 2018
Liquefaction Supply Derivatives	$	63		$	(26	)	$	37
Liquefaction Supply Derivatives	(92		)	12			(80		)

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Restricted Cash

9 Months Ended

Sep. 30, 2019

Restricted Cash [Abstract]

Restricted Cash

RESTRICTED CASH

Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2019 and December 31, 2018, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Current restricted cash
Liquefaction Project	$	185	$	756
Cash held by us and our guarantor subsidiaries	—		785
Total current restricted cash	$	185	$	1,541

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.

The cash held by us and our guarantor subsidiaries was restricted in use under the terms of the previous $2.8 billion credit facilities (the “2016 CQP Credit Facilities”) and the related depositary agreement governing the extension of credit to us, but is no longer restricted following the termination of the 2016 CQP Credit Facilities. Amounts not classified as restricted have been reserved by our general partner under the terms of our partnership agreement.

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Other Non-Current Assets (Tables)

9 Months Ended

Sep. 30, 2019

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

As of September 30, 2019 and December 31, 2018, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Advances made to municipalities for water system enhancements	$	88	$	90
Advances and other asset conveyances to third parties to support LNG terminals	35		36
Tax-related payments and receivables	17		17
Information technology service prepayments	8		20
Advances made under EPC and non-EPC contracts	2		14
Other	7		7
Total other non-current assets, net	$	157	$	184

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Revenues from Contracts with Customers (Tables)

9 Months Ended

Sep. 30, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
LNG revenues	$	1,139	$	1,249	$	3,676	$	3,419
LNG revenues—affiliate	257		205		1,017		886
Regasification revenues	66		66		199		196
Other revenues	13		9		36		28
Total revenues from customers	1,475		1,529		4,928		4,529
Net derivative gains (1)	1		—		2		—
Total revenues	$	1,476	$	1,529	$	4,930	$	4,529

(1) See Note 7—Derivative Instruments for additional information about our derivatives.

Contract Balances Reconciliation

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

	Nine Months Ended September 30, 2019
Deferred revenues, beginning of period	$	116
Cash received but not yet recognized	169
Revenue recognized from prior period deferral	(116		)
Deferred revenues, end of period	$	169

Transaction Price Allocated to Future Performance Obligations

The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2019 and December 31, 2018:

	September 30, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues (2)	$	55.7	10	$	53.6	10
Regasification revenues	2.4		5	2.6		6
Total revenues	$	58.1		$	56.2

(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.

(2) Includes future consideration from agreement contractually assigned to SPL from Cheniere Marketing.

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Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 217	$ 224
Accrued natural gas purchases	254	518
LNG terminal and related pipeline costs	161	79
Other accrued liabilities	25	0
Total accrued liabilities	$ 657	$ 821

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative assets		$ 8	$ 6
Non-current derivative assets		29	31
Derivative liabilities		(29)	(66)
Non-current derivative liabilities		(32)	(14)
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[1]	37	37
Total derivative liabilities	[1]	(61)	(80)
Derivative asset (liability), net	[1]	(24)	(43)
Derivative, collateral call		10	1
Liquefaction Supply Derivatives [Member] | Derivative assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	8	6
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[1]	29	31
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(29)	(66)
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[1]	$ (32)	$ (14)

[1] Does not include collateral calls of $10 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018, respectively.

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Supplemental Guarantor Information - Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	$ 977	$ 1,264
Cash flows from investing activities
Property, plant and equipment, net	(1,156)	(578)
Investments in subsidiaries	0	0
Return of capital	0
Distributions received from affiliates, net		0
Other	(1)	0
Net cash used in investing activities	(1,157)	(578)
Cash flows from financing activities
Proceeds from issuances of debt	2,230	1,100
Repayments of debt	(730)	(1,090)
Debt issuance and deferred financing costs	(33)	(8)
Debt extinguishment costs	(4)	(6)
Distributions to parent	0	0
Contributions from parent	0	0
Distributions to owners	(935)	(814)
Other	3	0
Net cash provided by (used in) financing activities	531	(818)
Net increase (decrease) in cash, cash equivalents and restricted cash	351	(132)
Cash, cash equivalents and restricted cash—beginning of period	1,541	1,589
Cash, cash equivalents and restricted cash—end of period	1,892	1,457
Parent Issuer [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	782	339
Cash flows from investing activities
Property, plant and equipment, net	0	0
Investments in subsidiaries	(1,109)	(202)
Return of capital	721
Distributions received from affiliates, net		447
Other	0
Net cash used in investing activities	(388)	245
Cash flows from financing activities
Proceeds from issuances of debt	2,230	1,100
Repayments of debt	(730)	(1,090)
Debt issuance and deferred financing costs	(33)	(8)
Debt extinguishment costs	(4)	(6)
Distributions to parent	0	0
Contributions from parent	0	0
Distributions to owners	(935)	(814)
Other	0
Net cash provided by (used in) financing activities	528	(818)
Net increase (decrease) in cash, cash equivalents and restricted cash	922	(234)
Cash, cash equivalents and restricted cash—beginning of period	779	1,033
Cash, cash equivalents and restricted cash—end of period	1,701	799
Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	907	408
Cash flows from investing activities
Property, plant and equipment, net	(35)	(24)
Investments in subsidiaries	(949)	(81)
Return of capital	546
Distributions received from affiliates, net		350
Other	0
Net cash used in investing activities	(438)	245
Cash flows from financing activities
Proceeds from issuances of debt	0	0
Repayments of debt	0	0
Debt issuance and deferred financing costs	0	0
Debt extinguishment costs	0	0
Distributions to parent	(1,581)	(858)
Contributions from parent	1,109	202
Distributions to owners	0	0
Other	3
Net cash provided by (used in) financing activities	(469)	(656)
Net increase (decrease) in cash, cash equivalents and restricted cash	0	(3)
Cash, cash equivalents and restricted cash—beginning of period	6	12
Cash, cash equivalents and restricted cash—end of period	6	9
Non-Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	656	928
Cash flows from investing activities
Property, plant and equipment, net	(1,123)	(554)
Investments in subsidiaries	0	0
Return of capital	0
Distributions received from affiliates, net		0
Other	(1)
Net cash used in investing activities	(1,124)	(554)
Cash flows from financing activities
Proceeds from issuances of debt	0	0
Repayments of debt	0	0
Debt issuance and deferred financing costs	0	0
Debt extinguishment costs	0	0
Distributions to parent	(1,052)	(350)
Contributions from parent	949	81
Distributions to owners	0	0
Other	0
Net cash provided by (used in) financing activities	(103)	(269)
Net increase (decrease) in cash, cash equivalents and restricted cash	(571)	105
Cash, cash equivalents and restricted cash—beginning of period	756	544
Cash, cash equivalents and restricted cash—end of period	185	649
Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	(1,368)	(411)
Cash flows from investing activities
Property, plant and equipment, net	2	0
Investments in subsidiaries	2,058	283
Return of capital	(1,267)
Distributions received from affiliates, net		(797)
Other	0
Net cash used in investing activities	793	(514)
Cash flows from financing activities
Proceeds from issuances of debt	0	0
Repayments of debt	0	0
Debt issuance and deferred financing costs	0	0
Debt extinguishment costs	0	0
Distributions to parent	2,633	1,208
Contributions from parent	(2,058)	(283)
Distributions to owners	0	0
Other	0
Net cash provided by (used in) financing activities	575	925
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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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 257	$ 205	$ 1,017	$ 886
Cost of sales—affiliate	6	0	6	0
Operating and maintenance expense—affiliate	34	31	100	87
General and administrative expense—affiliate	34	18	82	53
Cheniere Marketing SPA and Cheniere Marketing Master SPA [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	255	205	1,015	886
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	34	31	100	87
General and administrative expense—affiliate	34	18	82	53
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	2	0	2	0
Cost of sales—affiliate	$ 6	$ 0	$ 6	$ 0

XML

Net Income per Common Unit - Narrative (Details) - Subsequent Event [Member]	Oct. 28, 2019 $ / shares
Common Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.62
Subordinated Units [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.62

XML

Supplemental Guarantor Information - Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 1,707			$ 0
Restricted cash	185			1,541
Accounts and other receivables	277			348
Accounts receivable—affiliate	67			114
Advances to affiliate	177			228
Inventory	103			99
Derivative assets	8			6
Other current assets	65			20
Other current assets—affiliate	0			0
Total current assets	2,589			2,356
Property, plant and equipment, net	16,338			15,390
Operating lease assets, net	91			0
Debt issuance costs, net	17			13
Non-current derivative assets	29			31
Investments in subsidiaries	0			0
Other non-current assets, net	157			184
Total assets	19,221			17,974
Current liabilities
Accounts payable	17			15
Accrued liabilities	657			821
Due to affiliates	40			49
Deferred revenue	169			116
Deferred revenue—affiliate	0			1
Current operating lease liabilities	6			0
Derivative liabilities	29			66
Total current liabilities	918			1,068
Long-term debt, net	17,571			16,066
Non-current operating lease liabilities	84			0
Non-current derivative liabilities	32			14
Other non-current liabilities	4			4
Other non-current liabilities—affiliate	20			22
Partners’ equity	592	$ 801	$ 881	800	$ 748	$ 728	$ 725	$ 639
Total liabilities and partners’ equity	19,221			17,974
Parent Issuer [Member]
Current assets
Cash and cash equivalents	1,701			0
Restricted cash	0			779
Accounts and other receivables	0			1
Accounts receivable—affiliate	0			1
Advances to affiliate	0			0
Inventory	0			0
Derivative assets	0			0
Other current assets	1			0
Other current assets—affiliate	0			0
Total current assets	1,702			781
Property, plant and equipment, net	79			79
Operating lease assets, net	0
Debt issuance costs, net	10			1
Non-current derivative assets	0			0
Investments in subsidiaries	2,931			2,544
Other non-current assets, net	0			0
Total assets	4,722			3,405
Current liabilities
Accounts payable	0			0
Accrued liabilities	77			39
Due to affiliates	0			0
Deferred revenue	0			0
Deferred revenue—affiliate	0			0
Current operating lease liabilities	0
Derivative liabilities	0			0
Total current liabilities	77			39
Long-term debt, net	4,053			2,566
Non-current operating lease liabilities	0
Non-current derivative liabilities	0			0
Other non-current liabilities	0			0
Other non-current liabilities—affiliate	0			0
Partners’ equity	592			800
Total liabilities and partners’ equity	4,722			3,405
Guarantors [Member]
Current assets
Cash and cash equivalents	6			0
Restricted cash	0			6
Accounts and other receivables	3			1
Accounts receivable—affiliate	35			40
Advances to affiliate	151			104
Inventory	13			12
Derivative assets	0			0
Other current assets	12			2
Other current assets—affiliate	0			0
Total current assets	220			165
Property, plant and equipment, net	2,454			2,128
Operating lease assets, net	86
Debt issuance costs, net	0			0
Non-current derivative assets	0			0
Investments in subsidiaries	495			440
Other non-current assets, net	25			26
Total assets	3,280			2,759
Current liabilities
Accounts payable	5			4
Accrued liabilities	36			14
Due to affiliates	158			127
Deferred revenue	21			25
Deferred revenue—affiliate	21			22
Current operating lease liabilities	6
Derivative liabilities	0			0
Total current liabilities	247			192
Long-term debt, net	0			0
Non-current operating lease liabilities	79
Non-current derivative liabilities	0			0
Other non-current liabilities	3			1
Other non-current liabilities—affiliate	20			22
Partners’ equity	2,931			2,544
Total liabilities and partners’ equity	3,280			2,759
Non-Guarantors [Member]
Current assets
Cash and cash equivalents	0			0
Restricted cash	185			756
Accounts and other receivables	274			346
Accounts receivable—affiliate	66			113
Advances to affiliate	154			210
Inventory	90			87
Derivative assets	8			6
Other current assets	52			18
Other current assets—affiliate	22			21
Total current assets	851			1,557
Property, plant and equipment, net	13,831			13,209
Operating lease assets, net	21
Debt issuance costs, net	7			12
Non-current derivative assets	29			31
Investments in subsidiaries	0			0
Other non-current assets, net	132			158
Total assets	14,871			14,967
Current liabilities
Accounts payable	12			11
Accrued liabilities	544			768
Due to affiliates	45			48
Deferred revenue	148			91
Deferred revenue—affiliate	0			0
Current operating lease liabilities	0
Derivative liabilities	29			66
Total current liabilities	778			984
Long-term debt, net	13,518			13,500
Non-current operating lease liabilities	5
Non-current derivative liabilities	32			14
Other non-current liabilities	1			3
Other non-current liabilities—affiliate	16			0
Partners’ equity	521			466
Total liabilities and partners’ equity	14,871			14,967
Eliminations [Member]
Current assets
Cash and cash equivalents	0			0
Restricted cash	0			0
Accounts and other receivables	0			0
Accounts receivable—affiliate	(34)			(40)
Advances to affiliate	(128)			(86)
Inventory	0			0
Derivative assets	0			0
Other current assets	0			0
Other current assets—affiliate	(22)			(21)
Total current assets	(184)			(147)
Property, plant and equipment, net	(26)			(26)
Operating lease assets, net	(16)
Debt issuance costs, net	0			0
Non-current derivative assets	0			0
Investments in subsidiaries	(3,426)			(2,984)
Other non-current assets, net	0			0
Total assets	(3,652)			(3,157)
Current liabilities
Accounts payable	0			0
Accrued liabilities	0			0
Due to affiliates	(163)			(126)
Deferred revenue	0			0
Deferred revenue—affiliate	(21)			(21)
Current operating lease liabilities	0
Derivative liabilities	0			0
Total current liabilities	(184)			(147)
Long-term debt, net	0			0
Non-current operating lease liabilities	0
Non-current derivative liabilities	0			0
Other non-current liabilities	0			0
Other non-current liabilities—affiliate	(16)			0
Partners’ equity	(3,452)			(3,010)
Total liabilities and partners’ equity	$ (3,652)			$ (3,157)

XML

Nature of Operations and Basis of Presentation (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($) mi trains	Jan. 01, 2019 USD ($)	Dec. 31, 2018 USD ($)
Nature of Operations and Basis of Presentation [Line Items]
Right-of-use assets—Operating	$ 91		$ 0
Operating Lease, Liability	$ 90
Accounting Standards Update 2016-02 [Member]
Nature of Operations and Basis of Presentation [Line Items]
Right-of-use assets—Operating		$ 100
Operating Lease, Liability		$ 100
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains | trains	6
CTPL [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length of Natural Gas Pipeline | mi	94

XML

Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Inventory [Line Items]
Inventory	$ 103	$ 99
Natural gas [Member]
Inventory [Line Items]
Inventory	15	28
LNG [Member]
Inventory [Line Items]
Inventory	7	6
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 81	$ 65

XML

Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Sep. 30, 2019	Dec. 31, 2018
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 58.1	$ 56.2
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	[1]	$ 55.7	$ 53.6
Weighted Average Recognition Timing	[1],[2]	10 years	10 years
Regasification [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 2.4	$ 2.6
Weighted Average Recognition Timing	[2]	5 years	6 years

[1] Includes future consideration from agreement contractually assigned to SPL from Cheniere Marketing.

[2] 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.

XML

Leases - Other Quantitative Information (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Leases [Abstract]
Weighted-average remaining lease term	25 years 10 months 24 days
Weighted-average discount rate	4.80%
Operating cash flows for operating leases	$ 7

XML

Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Debt Disclosure [Abstract]
Total interest cost	$ 246	$ 235	$ 718	$ 701
Capitalized interest	(15)	(52)	(70)	(149)
Total interest expense, net	$ 231	$ 183	$ 648	$ 552

XML

Consolidated Statements of Partners' Equity - 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
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	335	236	92	$ 7
Distributions		$ (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
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
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	923
Units, Outstanding, end of period at Sep. 30, 2018		348.6	135.4
Partners' equity, end of period at Sep. 30, 2018	748	$ 1,759	$ (1,008)	$ (3)
General partner units, Outstanding, end of period at Sep. 30, 2018				9.9
Units, Outstanding, beginning of period at Mar. 31, 2018		348.6	135.4
Partners' equity, beginning of period at Mar. 31, 2018	725	$ 1,731	$ (1,019)	$ 13
General partner units, Outstanding, beginning of period at Mar. 31, 2018				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income		199	77	$ 5
Distributions		$ (191)	$ (74)	(13)
Units, Outstanding, end of period at Jun. 30, 2018		348.6	135.4
Partners' equity, end of period at Jun. 30, 2018	728	$ 1,739	$ (1,016)	$ 5
General partner units, Outstanding, end of period at Jun. 30, 2018				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	307	216	84	$ 7
Distributions		$ (196)	$ (76)	(15)
Units, Outstanding, end of period at Sep. 30, 2018		348.6	135.4
Partners' equity, end of period at Sep. 30, 2018	748	$ 1,759	$ (1,008)	$ (3)
General partner units, Outstanding, end of period at Sep. 30, 2018				9.9
Units, Outstanding, beginning of period at Dec. 31, 2018		348.6	135.4
Partners' equity, beginning of period at Dec. 31, 2018	$ 800	$ 1,806	$ (990)	$ (16)
General partner units, Outstanding, beginning of period at Dec. 31, 2018	9.9			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 385	272	105	$ 8
Distributions		$ (206)	$ (80)	(18)
Units, Outstanding, end of period at Mar. 31, 2019		348.6	135.4
Partners' equity, end of period at Mar. 31, 2019	881	$ 1,872	$ (965)	$ (26)
General partner units, Outstanding, end of period at Mar. 31, 2019				9.9
Units, Outstanding, beginning of period at Dec. 31, 2018		348.6	135.4
Partners' equity, beginning of period at Dec. 31, 2018	$ 800	$ 1,806	$ (990)	$ (16)
General partner units, Outstanding, beginning of period at Dec. 31, 2018	9.9			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 727
Units, Outstanding, end of period at Sep. 30, 2019		348.6	135.4
Partners' equity, end of period at Sep. 30, 2019	$ 592	$ 1,692	$ (1,035)	$ (65)
General partner units, Outstanding, end of period at Sep. 30, 2019	9.9			9.9
Units, Outstanding, beginning of period at Mar. 31, 2019		348.6	135.4
Partners' equity, beginning of period at Mar. 31, 2019	$ 881	$ 1,872	$ (965)	$ (26)
General partner units, Outstanding, beginning of period at Mar. 31, 2019				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	232	164	64	$ 4
Distributions		$ (209)	$ (81)	(22)
Units, Outstanding, end of period at Jun. 30, 2019		348.6	135.4
Partners' equity, end of period at Jun. 30, 2019	801	$ 1,827	$ (982)	$ (44)
General partner units, Outstanding, end of period at Jun. 30, 2019				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	110	77	30	$ 3
Distributions		$ (212)	$ (83)	(24)
Units, Outstanding, end of period at Sep. 30, 2019		348.6	135.4
Partners' equity, end of period at Sep. 30, 2019	$ 592	$ 1,692	$ (1,035)	$ (65)
General partner units, Outstanding, end of period at Sep. 30, 2019	9.9			9.9

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2019	Oct. 25, 2019
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
Document Transition Report	false
Entity File Number	001-33366
Entity Registrant Name	Cheniere Energy Partners, L.P.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-5913059
Entity Address, Address Line One	700 Milam Street
Entity Address, Address Line Two	Suite 1900
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	375-5000
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	CQP
Security Exchange Name	NYSEAMER
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Central Index Key	0001383650
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Common Units [Member]
Entity Information [Line Items]
Entity Units, Units Outstanding		348,629,792
Subordinated Units [Member]
Entity Information [Line Items]
Entity Units, Units Outstanding		135,383,831

XML

Nature of Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2019

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 in various stages of operating and constructing six natural gas liquefaction Trains (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. Trains 1 through 5 are operational and Train 6 is under construction. The Sabine Pass LNG terminal has operational regasification facilities owned by SPLNG and a 94-mile pipeline owned by CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

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, 2018.

Results of operations for the three and nine months ended September 30, 2019 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2019.

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.

Recent Accounting Standards

We adopted ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard resulted in the recognition of right-of-use assets and lease liabilities for operating leases of approximately $100 million on our Consolidated Balance Sheets, with no material impact on our Consolidated Statements of Income or Consolidated Statements of Cash Flows. We have elected the practical expedients to (1) carryforward prior conclusions related to lease identification and classification for existing leases, (2) combine lease and non-lease components of an arrangement for all classes of leased assets, (3) omit short-term leases with a term of 12 months or less from recognition on the balance sheet and (4) carryforward our existing accounting for land easements not previously accounted for as leases. See Note 11—Leases for additional information on our leases following the adoption of this standard.

XML

Restricted Cash (Tables)

9 Months Ended

Sep. 30, 2019

Restricted Cash [Abstract]

Schedule of Restricted Cash

As of September 30, 2019 and December 31, 2018, restricted cash consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Current restricted cash
Liquefaction Project	$	185	$	756
Cash held by us and our guarantor subsidiaries	—		785
Total current restricted cash	$	185	$	1,541

XML

Customer Concentration

9 Months Ended

Sep. 30, 2019

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers:

	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2019	2018	2019	2018	2019	2018
Customer A	24%	24%	28%	27%	20%	35%
Customer B	18%	21%	19%	22%	17%	23%
Customer C	22%	21%	20%	23%	15%	30%
Customer D	19%	24%	21%	18%	21%	*
Customer E	*	—%	*	—%	14%	—%

* Less than 10%

XML

Net Income per Common Unit (Tables)

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Schedule of Net Income per Common Unit

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

				Limited Partner Units
	Total			Common Units			Subordinated Units			General Partner Units			IDR
Three Months Ended September 30, 2019
Net income	$	110
Declared distributions	323			217			84			6			16
Assumed allocation of undistributed net loss (1)	$	(213	)	(151		)	(58		)	(4		)	—
Assumed allocation of net income				$	66		$	26		$	2		$	16
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	0.19		$	0.19
Three Months Ended September 30, 2018
Net income	$	307
Declared distributions	297			202			79			5			11
Assumed allocation of undistributed net income (1)	$	10		7			3			—			—
Assumed allocation of net income				$	209		$	82		$	5		$	11
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit (2)				$	0.60		$	0.60
Nine Months Ended September 30, 2019
Net income	$	727
Declared distributions	949			638			248			19			44
Assumed allocation of undistributed net loss (1)	$	(222	)	(157		)	(61		)	(4		)	—
Assumed allocation of net income				$	481		$	187		$	15		$	44
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	1.38		$	1.38
Nine Months Ended September 30, 2018
Net income	$	923
Declared distributions	859			589			229			17			24
Assumed allocation of undistributed net income (1)	$	64		45			18			1			—
Assumed allocation of net income				$	634		$	247		$	18		$	24
Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	1.82		$	1.82

(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.

XML

Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

As of September 30, 2019 and December 31, 2018, property, plant and equipment, net consisted of the following (in millions):

	September 30,			December 31,
	2019			2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	16,807		$	12,760
LNG terminal construction-in-process	1,196			3,913
Accumulated depreciation	(1,671		)	(1,290		)
Total LNG terminal costs, net	16,332			15,383
Fixed assets
Fixed assets	26			26
Accumulated depreciation	(20		)	(19		)
Total fixed assets, net	6			7
Property, plant and equipment, net	$	16,338		$	15,390

XML

Debt (Tables)

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Schedule of Debt Instruments

As of September 30, 2019 and December 31, 2018, our debt consisted of the following (in millions):

	September 30,			December 31,
	2019			2018
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)	1,500			1,500
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			1,100
4.500% Senior Notes due 2029 (“2029 CQP Senior Notes”)	1,500			—
2016 CQP Credit Facilities	—			—
CQP Credit Facilities entered into in 2019 (“2019 CQP Credit Facilities”)	—			—
Unamortized premium, discount and debt issuance costs, net	(179		)	(184		)
Total long-term debt, net	17,571			16,066
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			—
Total debt, net	$	17,571		$	16,066

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2019 (in millions):

	SPL Working Capital Facility (1)		2019 CQP Credit Facilities
Original facility size	$	1,200	$	1,500
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		750
Letters of credit issued	414		—
Available commitment	$	786	$	750
Interest rate on available balance	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Maturity date	December 31, 2020		May 29, 2024

(1)

The SPL Working Capital Facility was amended in May 2019 in connection with commercialization and financing of Train 6 of the Liquefaction Project. All terms of the SPL Working Capital Facility substantially remained unchanged.

Schedule of Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Total interest cost	$	246		$	235		$	718		$	701
Capitalized interest	(15		)	(52		)	(70		)	(149		)
Total interest expense, net	$	231		$	183		$	648		$	552

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	September 30, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	16,780	$	18,340	$	15,275	$	15,672
2037 SPL Senior Notes (2)	791		909		791		817
Credit facilities (3)	—		—		—		—

(1) Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2026

CQP Senior Notes and 2029 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, 2016 CQP Credit Facilities and 2019 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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Accrued Liabilities

9 Months Ended

Sep. 30, 2019

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

As of September 30, 2019 and December 31, 2018, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Interest costs and related debt fees	$	217	$	224
Accrued natural gas purchases	254		518
LNG terminal and related pipeline costs	161		79
Other accrued liabilities	25		—
Total accrued liabilities	$	657	$	821

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Inventory

9 Months Ended

Sep. 30, 2019

Inventory Disclosure [Abstract]

Inventory

INVENTORY

As of September 30, 2019 and December 31, 2018, inventory consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Natural gas	$	15	$	28
LNG	7		6
Materials and other	81		65
Total inventory	$	103	$	99

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Related Party Transactions - Service Agreements (Details) - USD ($)	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 177,000,000	$ 228,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	177,000,000	$ 228,000,000
Cheniere Partners Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Quarterly non-accountable overhead reimbursement charge	$ 3,000,000
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | SPL [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	0.60%
Related Party Transaction, Committed Monthly Fee	$ 83,333
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 130,000
Related Party Transaction, Bonus Percentage of Salary Entitled Upon Meeting Certain Criteria	50.00%
Management Services Agreement [Member] | Cheniere Terminals [Member] | SPL [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	2.40%
Related Party Transaction, Committed Monthly Fee	$ 541,667
Management Services Agreement [Member] | Cheniere Terminals [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 520,000

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Customer Concentration (Details)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	24.00%	24.00%	28.00%	27.00%
Customer A [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			20.00%		35.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	21.00%	19.00%	22.00%
Customer B [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			17.00%		23.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	22.00%	21.00%	20.00%	23.00%
Customer C [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			15.00%		30.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%	24.00%	21.00%	18.00%
Customer D [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			21.00%
Customer E [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		0.00%		0.00%
Customer E [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			14.00%		0.00%

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Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 40	$ 63
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(3)	(26)
Derivative Assets (Liabilities), at Fair Value, Net	37	37
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(63)	(92)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	2	12
Derivative Assets (Liabilities), at Fair Value, Net	$ (61)	$ (80)

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	9 Months Ended
	Sep. 30, 2019 USD ($)
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability	$ (8,000,000)
Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	(0.618)
Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	$ 0.056

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Debt - Issuances and Terminations (Details) - USD ($)	1 Months Ended	9 Months Ended
	May 31, 2019	Sep. 30, 2019
CQP Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Monetary Amount		$ 1,500,000,000
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Percentage of Net Tangible Assets		10.00%
2029 CQP Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount		$ 1,500,000,000
Loss on early extinguishment of debt		$ 13,000,000
Debt Instrument, Interest Rate, Stated Percentage		4.50%
Debt Instrument, Redemption Price, Percentage		100.00%
Debt Instrument, Redemption Price, Percentage Price For Amount Which May Be Redeemed With Cash Proceeds From Certain Equity Offerings		104.50%
Debt Instrument Registration Period		360 days
2029 CQP Senior Notes [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Redemption Amount, Percentage of Principal Amount Which May Be Redeemed With Cash Proceeds From Certain Equity Offerings		35.00%
2016 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Loss on early extinguishment of debt	$ 0
2019 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Commitments prepaid or terminated		$ 750,000,000
Debt Instrument, Description of Variable Rate Basis		LIBOR or the base rate
2019 CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility, Number Of Months Period Within LIBOR Period Interest Due		3 months
2019 CQP Credit Facilities [Member] | Base Rate Determination Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
2019 CQP Credit Facilities [Member] | Base Rate Determination LIBOR [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
2019 CQP Credit Facilities - CQP Term Facility [Member]
Line of Credit Facility [Line Items]
Commitments prepaid or terminated		$ 750,000,000
Line of Credit Facility, Maximum Borrowing Capacity	750,000,000
2019 CQP Credit Facilities - CQP Term Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.50%
2019 CQP Credit Facilities - CQP Term Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
2019 CQP Credit Facilities - CQP Revolving Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 750,000,000
2019 CQP Credit Facilities - CQP Revolving Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.25%
2019 CQP Credit Facilities - CQP Revolving Facility [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.25%
2019 CQP Credit Facilities - CQP Revolving Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.125%
2019 CQP Credit Facilities - CQP Revolving Facility [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.125%

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Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 1,475	$ 1,529	$ 4,928	$ 4,529
Net derivative gains	[1]	1	0	2	0
Total revenues		1,476	1,529	4,930	4,529
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		1,139	1,249	3,676	3,419
Total revenues		1,140	1,249	3,678	3,419
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		257	205	1,017	886
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		66	66	199	196
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 13	$ 9	$ 36	$ 28

[1] See Note 7—Derivative Instruments for additional information about our derivatives.

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Leases - Financial Statement Location Tables (Details) - USD ($) $ in Millions		3 Months Ended	9 Months Ended
		Sep. 30, 2019	Sep. 30, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Right-of-use assets—Operating		$ 91	$ 91	$ 0
Current operating lease liabilities		6	6	0
Non-current operating lease liabilities		84	84	$ 0
Variable Lease, Cost		1	1
Operating costs and expenses [Member]
Lessee, Lease, Description [Line Items]
Operating lease cost	[1],[2]	2	8
Operating lease assets, net [Member]
Lessee, Lease, Description [Line Items]
Right-of-use assets—Operating		91	91
Current operating lease liabilities [Member]
Lessee, Lease, Description [Line Items]
Current operating lease liabilities		6	6
Non-current operating lease liabilities [Member]
Lessee, Lease, Description [Line Items]
Non-current operating lease liabilities		$ 84	$ 84

[1] Presented in cost of sales, operating and maintenance expense, general and administrative expense or general and administrative expense—affiliate consistent with the nature of the asset under lease.

[2] Includes $1 million of variable lease costs.

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 16,338	$ 15,390
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(1,671)	(1,290)
Property, plant and equipment, net	16,332	15,383
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	16,807	12,760
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,196	3,913
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	26	26
Accumulated depreciation	(20)	(19)
Property, plant and equipment, net	$ 6	$ 7

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2019

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Nine Months Ended September 30,
	2019		2018
Cash paid during the period for interest, net of amounts capitalized	$	624	$	586

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Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 185	$ 1,541
2016 CQP Credit Facilities [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		2,800
Liquefaction Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	185	756
Cash held by us and our guarantor subsidiaries [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 0	$ 785

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Supplemental Guarantor Information

9 Months Ended

Sep. 30, 2019

Supplemental Guarantor Information [Abstract]

Supplemental Guarantor Information

SUPPLEMENTAL GUARANTOR INFORMATION

Our CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the indenture governing the CQP Senior Notes. See Note 10—Debt in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2018 for additional information regarding the CQP Senior Notes.

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

Condensed Consolidating Balance Sheet
September 30, 2019
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	1,701	$	6	$	—	$	—		$	1,707
Restricted cash	—		—		185		—			185
Accounts and other receivables	—		3		274		—			277
Accounts receivable—affiliate	—		35		66		(34		)	67
Advances to affiliate	—		151		154		(128		)	177
Inventory	—		13		90		—			103
Derivative assets	—		—		8		—			8
Other current assets	1		12		52		—			65
Other current assets—affiliate	—		—		22		(22		)	—
Total current assets	1,702		220		851		(184		)	2,589
Property, plant and equipment, net	79		2,454		13,831		(26		)	16,338
Operating lease assets, net	—		86		21		(16		)	91
Debt issuance costs, net	10		—		7		—			17
Non-current derivative assets	—		—		29		—			29
Investments in subsidiaries	2,931		495		—		(3,426		)	—
Other non-current assets, net	—		25		132		—			157
Total assets	$	4,722	$	3,280	$	14,871	$	(3,652	)	$	19,221
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	5	$	12	$	—		$	17
Accrued liabilities	77		36		544		—			657
Due to affiliates	—		158		45		(163		)	40
Deferred revenue	—		21		148		—			169
Deferred revenue—affiliate	—		21		—		(21		)	—
Current operating lease liabilities	—		6		—		—			6
Derivative liabilities	—		—		29		—			29
Total current liabilities	77		247		778		(184		)	918
Long-term debt, net	4,053		—		13,518		—			17,571
Non-current operating lease liabilities	—		79		5		—			84
Non-current derivative liabilities	—		—		32		—			32
Other non-current liabilities	—		3		1		—			4
Other non-current liabilities—affiliate	—		20		16		(16		)	20
Partners’ equity	592		2,931		521		(3,452		)	592
Total liabilities and partners’ equity	$	4,722	$	3,280	$	14,871	$	(3,652	)	$	19,221

Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	779		6		756		—			1,541
Accounts and other receivables	1		1		346		—			348
Accounts receivable—affiliate	1		40		113		(40		)	114
Advances to affiliate	—		104		210		(86		)	228
Inventory	—		12		87		—			99
Derivative assets	—		—		6		—			6
Other current assets	—		2		18		—			20
Other current assets—affiliate	—		—		21		(21		)	—
Total current assets	781		165		1,557		(147		)	2,356
Property, plant and equipment, net	79		2,128		13,209		(26		)	15,390
Debt issuance costs, net	1		—		12		—			13
Non-current derivative assets	—		—		31		—			31
Investments in subsidiaries	2,544		440		—		(2,984		)	—
Other non-current assets, net	—		26		158		—			184
Total assets	$	3,405	$	2,759	$	14,967	$	(3,157	)	$	17,974
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4	$	11	$	—		$	15
Accrued liabilities	39		14		768		—			821
Due to affiliates	—		127		48		(126		)	49
Deferred revenue	—		25		91		—			116
Deferred revenue—affiliate	—		22		—		(21		)	1
Derivative liabilities	—		—		66		—			66
Total current liabilities	39		192		984		(147		)	1,068
Long-term debt, net	2,566		—		13,500		—			16,066
Non-current derivative liabilities	—		—		14		—			14
Other non-current liabilities	—		1		3		—			4
Other non-current liabilities—affiliate	—		22		—		—			22
Partners’ equity	800		2,544		466		(3,010		)	800
Total liabilities and partners’ equity	$	3,405	$	2,759	$	14,967	$	(3,157	)	$	17,974

Condensed Consolidating Statement of Income
Three Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,140		$	—		$	1,140
LNG revenues—affiliate	—			—			257			—			257
Regasification revenues	—			66			—			—			66
Regasification revenues—affiliate	—			65			—			(65		)	—
Other revenues	—			13			—			—			13
Other revenues—affiliate	—			36			—			(36		)	—
Total revenues	—			180			1,397			(101		)	1,476
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			742			—			742
Cost of sales—affiliate	—			6			17			(17		)	6
Operating and maintenance expense	—			22			150			—			172
Operating and maintenance expense—affiliate	—			5			113			(84		)	34
General and administrative expense	1			1			1			—			3
General and administrative expense—affiliate	4			8			28			(6		)	34
Depreciation and amortization expense	1			21			117			(1		)	138
Impairment expense and loss on disposal of assets	—			—			1			—			1
Total operating costs and expenses	6			63			1,169			(108		)	1,130
Income (loss) from operations	(6		)	117			228			7			346
Other income (expense)
Interest expense, net of capitalized interest	(47		)	(1		)	(183		)	—			(231		)
Loss on modification or extinguishment of debt	(13		)	—			—			—			(13		)
Equity earnings of subsidiaries	170			48			—			(218		)	—
Other income (expense)	6			(1		)	3			—			8
Total other income (expense)	116			46			(180		)	(218		)	(236		)
Net income	$	110		$	163		$	48		$	(211	)	$	110

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

Condensed Consolidating Statement of Income
Nine Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	3,678		$	—		$	3,678
LNG revenues—affiliate	—			—			1,017			—			1,017
Regasification revenues	—			199			—			—			199
Regasification revenues—affiliate	—			196			—			(196		)	—
Other revenues	—			36			—			—			36
Other revenues—affiliate	—			160			—			(160		)	—
Total revenues	—			591			4,695			(356		)	4,930
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			2,501			—			2,501
Cost of sales—affiliate	—			6			35			(35		)	6
Operating and maintenance expense	—			74			398			—			472
Operating and maintenance expense—affiliate	—			76			335			(311		)	100
General and administrative expense	3			2			4			—			9
General and administrative expense—affiliate	10			22			64			(14		)	82
Depreciation and amortization expense	2			58			331			(1		)	390
Impairment expense and loss on disposal of assets	—			—			6			—			6
Total operating costs and expenses	15			238			3,674			(361		)	3,566
Income (loss) from operations	(15		)	353			1,021			5			1,364
Other income (expense)
Interest expense, net of capitalized interest	(120		)	(4		)	(524		)	—			(648		)
Loss on modification or extinguishment of debt	(13		)	—			—			—			(13		)
Equity earnings of subsidiaries	860			506			—			(1,366		)	—
Other income	15			—			9			—			24
Total other income (expense)	742			502			(515		)	(1,366		)	(637		)
Net income	$	727		$	855		$	506		$	(1,361	)	$	727

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

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by operating activities	$	782		$	907		$	656		$	(1,368	)	$	977
Cash flows from investing activities
Property, plant and equipment, net	—			(35		)	(1,123		)	2			(1,156		)
Investments in subsidiaries	(1,109		)	(949		)	—			2,058			—
Return of capital	721			546			—			(1,267		)	—
Other	—			—			(1		)	—			(1		)
Net cash used in investing activities	(388		)	(438		)	(1,124		)	793			(1,157		)
Cash flows from financing activities
Proceeds from issuances of debt	2,230			—			—			—			2,230
Repayments of debt	(730		)	—			—			—			(730		)
Debt issuance and deferred financing costs	(33		)	—			—			—			(33		)
Debt extinguishment costs	(4		)	—			—			—			(4		)
Distributions to parent	—			(1,581		)	(1,052		)	2,633			—
Contributions from parent	—			1,109			949			(2,058		)	—
Distributions to owners	(935		)	—			—			—			(935		)
Other	—			3			—			—			3
Net cash provided by (used in) financing activities	528			(469		)	(103		)	575			531
Net increase (decrease) in cash, cash equivalents and restricted cash	922			—			(571		)	—			351
Cash, cash equivalents and restricted cash—beginning of period	779			6			756			—			1,541
Cash, cash equivalents and restricted cash—end of period	$	1,701		$	6		$	185		$	—		$	1,892

Balances per Condensed Consolidating Balance Sheet:

	September 30, 2019
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	1,701	$	6	$	—	$	—	$	1,707
Restricted cash	—		—		185		—		185
Total cash, cash equivalents and restricted cash	$	1,701	$	6	$	185	$	—	$	1,892

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

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Related Party Transactions

9 Months Ended

Sep. 30, 2019

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
LNG revenues—affiliate
Cheniere Marketing Agreements	$	255	$	205	$	1,015	$	886
Contracts for Sale and Purchase of Natural Gas and LNG	2		—		2		—
Total LNG revenues—affiliate	257		205		1,017		886
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	6		—		6		—
Operating and maintenance expense—affiliate
Services Agreements	34		31		100		87
General and administrative expense—affiliate
Services Agreements	34		18		82		53

As of September 30, 2019 and December 31, 2018, we had $67 million and $114 million, respectively, of accounts receivable—affiliate, under the agreements described below.

Terminal Use Agreement

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 May 2036.

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

Cheniere Marketing Agreements

Cheniere Marketing SPA

Cheniere Marketing has an SPA (“Base 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.

In May 2019, SPL and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by SPL to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo.

Cheniere Marketing Master SPA

SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement. SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, Train 5 of the Liquefaction Project.

Cheniere Marketing Letter Agreement

In May 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu scheduled for delivery between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu.

Services Agreements

As of September 30, 2019 and December 31, 2018, we had $177 million and $228 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Cheniere Partners Services Agreement

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

Cheniere Investments Information Technology Services Agreement

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

SPLNG O&M Agreement

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

SPLNG MSA

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

SPL O&M Agreement

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

SPL MSA

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

CTPL O&M Agreement

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

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This initiative represented an aggregate commitment of $25 million over 10 years in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to ad valorem tax levied on our LNG terminal in the year the Cameron Parish dollar-for-dollar credit is applied.

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as obligations. We had $4 million and $3 million in due to affiliates and $20 million and $22 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing as of September 30, 2019 and December 31, 2018, respectively.

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.

SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas sold and purchased under this agreement is recorded as LNG revenues—affiliate and cost of sales—affiliate, respectively.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. The agreement also provides that Tug Services shall contingently pay the wholly owned subsidiary of Cheniere a portion of its future revenues. Accordingly, Tug Services distributed $2 million during each of the three months ended September 30, 2019 and 2018, respectively, and $5 million and $4 million during the nine months ended September 30, 2019 and 2018, respectively, to the wholly owned subsidiary of Cheniere, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the three and nine months ended September 30, 2019 and 2018.

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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Inventory (Tables)

9 Months Ended

Sep. 30, 2019

Inventory Disclosure [Abstract]

Schedule of Inventory

As of September 30, 2019 and December 31, 2018, inventory consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Natural gas	$	15	$	28
LNG	7		6
Materials and other	81		65
Total inventory	$	103	$	99

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash flows from operating activities
Net income	$ 727	$ 923
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	390	318
Amortization of debt issuance costs, deferred commitment fees, premium and discount	23	24
Loss on modification or extinguishment of debt	13	12
Total losses (gains) on derivatives, net	(30)	29
Net cash provided by (used for) settlement of derivative instruments	11	0
Impairment expense and loss on disposal of assets	6	8
Other	8	5
Changes in operating assets and liabilities:
Accounts and other receivables	36	(33)
Accounts receivable—affiliate	47	140
Advances to affiliate	(47)	(79)
Inventory	(3)	6
Accounts payable and accrued liabilities	(209)	(77)
Due to affiliates	(3)	(5)
Deferred revenue	54	6
Other, net	(42)	(10)
Other, net—affiliate	(4)	(3)
Net cash provided by operating activities	977	1,264
Cash flows from investing activities
Property, plant and equipment, net	(1,156)	(578)
Other	(1)	0
Net cash used in investing activities	(1,157)	(578)
Cash flows from financing activities
Proceeds from issuances of debt	2,230	1,100
Repayments of debt	(730)	(1,090)
Debt issuance and deferred financing costs	(33)	(8)
Debt extinguishment costs	(4)	(6)
Distributions to owners	(935)	(814)
Other	3	0
Net cash provided by (used in) financing activities	531	(818)
Net increase (decrease) in cash, cash equivalents and restricted cash	351	(132)
Cash, cash equivalents and restricted cash—beginning of period	1,541	1,589
Cash, cash equivalents and restricted cash—end of period	$ 1,892	$ 1,457

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Consolidated Balance Sheets Parentheticals - shares shares in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
General Partner Ownership Interest Percentage	2.00%	2.00%
General Partners' Capital Account, Units Issued	9.9	9.9
General Partners' Capital Account, Units Outstanding	9.9	9.9
Common Units [Member]
Limited Partners' Capital Account, Units Issued	348.6	348.6
Limited Partners' Capital Account, Units Outstanding	348.6	348.6
Subordinated Units [Member]
Limited Partners' Capital Account, Units Issued	135.4	135.4
Limited Partners' Capital Account, Units Outstanding	135.4	135.4

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Revenues from Contracts with Customers - Narrative (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	49.00%	55.00%	53.00%	55.00%
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	3.00%	3.00%	3.00%	3.00%
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	100.00%	100.00%	100.00%	100.00%

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 17,571	$ 16,066
Senior notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	16,780	15,275
Senior notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	18,340	15,672
2037 SPL Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	791	791
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]	909	817
Credit facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[3]	0	0
Credit facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[3]	$ 0	$ 0

[1] Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2026 CQP Senior Notes and 2029 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, 2016 CQP Credit Facilities and 2019 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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Supplemental Guarantor Information (Tables)

9 Months Ended

Sep. 30, 2019

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Balance Sheets

Condensed Consolidating Balance Sheet
September 30, 2019
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	1,701	$	6	$	—	$	—		$	1,707
Restricted cash	—		—		185		—			185
Accounts and other receivables	—		3		274		—			277
Accounts receivable—affiliate	—		35		66		(34		)	67
Advances to affiliate	—		151		154		(128		)	177
Inventory	—		13		90		—			103
Derivative assets	—		—		8		—			8
Other current assets	1		12		52		—			65
Other current assets—affiliate	—		—		22		(22		)	—
Total current assets	1,702		220		851		(184		)	2,589
Property, plant and equipment, net	79		2,454		13,831		(26		)	16,338
Operating lease assets, net	—		86		21		(16		)	91
Debt issuance costs, net	10		—		7		—			17
Non-current derivative assets	—		—		29		—			29
Investments in subsidiaries	2,931		495		—		(3,426		)	—
Other non-current assets, net	—		25		132		—			157
Total assets	$	4,722	$	3,280	$	14,871	$	(3,652	)	$	19,221
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	5	$	12	$	—		$	17
Accrued liabilities	77		36		544		—			657
Due to affiliates	—		158		45		(163		)	40
Deferred revenue	—		21		148		—			169
Deferred revenue—affiliate	—		21		—		(21		)	—
Current operating lease liabilities	—		6		—		—			6
Derivative liabilities	—		—		29		—			29
Total current liabilities	77		247		778		(184		)	918
Long-term debt, net	4,053		—		13,518		—			17,571
Non-current operating lease liabilities	—		79		5		—			84
Non-current derivative liabilities	—		—		32		—			32
Other non-current liabilities	—		3		1		—			4
Other non-current liabilities—affiliate	—		20		16		(16		)	20
Partners’ equity	592		2,931		521		(3,452		)	592
Total liabilities and partners’ equity	$	4,722	$	3,280	$	14,871	$	(3,652	)	$	19,221

Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	779		6		756		—			1,541
Accounts and other receivables	1		1		346		—			348
Accounts receivable—affiliate	1		40		113		(40		)	114
Advances to affiliate	—		104		210		(86		)	228
Inventory	—		12		87		—			99
Derivative assets	—		—		6		—			6
Other current assets	—		2		18		—			20
Other current assets—affiliate	—		—		21		(21		)	—
Total current assets	781		165		1,557		(147		)	2,356
Property, plant and equipment, net	79		2,128		13,209		(26		)	15,390
Debt issuance costs, net	1		—		12		—			13
Non-current derivative assets	—		—		31		—			31
Investments in subsidiaries	2,544		440		—		(2,984		)	—
Other non-current assets, net	—		26		158		—			184
Total assets	$	3,405	$	2,759	$	14,967	$	(3,157	)	$	17,974
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4	$	11	$	—		$	15
Accrued liabilities	39		14		768		—			821
Due to affiliates	—		127		48		(126		)	49
Deferred revenue	—		25		91		—			116
Deferred revenue—affiliate	—		22		—		(21		)	1
Derivative liabilities	—		—		66		—			66
Total current liabilities	39		192		984		(147		)	1,068
Long-term debt, net	2,566		—		13,500		—			16,066
Non-current derivative liabilities	—		—		14		—			14
Other non-current liabilities	—		1		3		—			4
Other non-current liabilities—affiliate	—		22		—		—			22
Partners’ equity	800		2,544		466		(3,010		)	800
Total liabilities and partners’ equity	$	3,405	$	2,759	$	14,967	$	(3,157	)	$	17,974

Condensed Consolidating Statements of Income

Condensed Consolidating Statement of Income
Three Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	1,140		$	—		$	1,140
LNG revenues—affiliate	—			—			257			—			257
Regasification revenues	—			66			—			—			66
Regasification revenues—affiliate	—			65			—			(65		)	—
Other revenues	—			13			—			—			13
Other revenues—affiliate	—			36			—			(36		)	—
Total revenues	—			180			1,397			(101		)	1,476
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			742			—			742
Cost of sales—affiliate	—			6			17			(17		)	6
Operating and maintenance expense	—			22			150			—			172
Operating and maintenance expense—affiliate	—			5			113			(84		)	34
General and administrative expense	1			1			1			—			3
General and administrative expense—affiliate	4			8			28			(6		)	34
Depreciation and amortization expense	1			21			117			(1		)	138
Impairment expense and loss on disposal of assets	—			—			1			—			1
Total operating costs and expenses	6			63			1,169			(108		)	1,130
Income (loss) from operations	(6		)	117			228			7			346
Other income (expense)
Interest expense, net of capitalized interest	(47		)	(1		)	(183		)	—			(231		)
Loss on modification or extinguishment of debt	(13		)	—			—			—			(13		)
Equity earnings of subsidiaries	170			48			—			(218		)	—
Other income (expense)	6			(1		)	3			—			8
Total other income (expense)	116			46			(180		)	(218		)	(236		)
Net income	$	110		$	163		$	48		$	(211	)	$	110

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

Condensed Consolidating Statement of Income
Nine Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	—		$	3,678		$	—		$	3,678
LNG revenues—affiliate	—			—			1,017			—			1,017
Regasification revenues	—			199			—			—			199
Regasification revenues—affiliate	—			196			—			(196		)	—
Other revenues	—			36			—			—			36
Other revenues—affiliate	—			160			—			(160		)	—
Total revenues	—			591			4,695			(356		)	4,930
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			2,501			—			2,501
Cost of sales—affiliate	—			6			35			(35		)	6
Operating and maintenance expense	—			74			398			—			472
Operating and maintenance expense—affiliate	—			76			335			(311		)	100
General and administrative expense	3			2			4			—			9
General and administrative expense—affiliate	10			22			64			(14		)	82
Depreciation and amortization expense	2			58			331			(1		)	390
Impairment expense and loss on disposal of assets	—			—			6			—			6
Total operating costs and expenses	15			238			3,674			(361		)	3,566
Income (loss) from operations	(15		)	353			1,021			5			1,364
Other income (expense)
Interest expense, net of capitalized interest	(120		)	(4		)	(524		)	—			(648		)
Loss on modification or extinguishment of debt	(13		)	—			—			—			(13		)
Equity earnings of subsidiaries	860			506			—			(1,366		)	—
Other income	15			—			9			—			24
Total other income (expense)	742			502			(515		)	(1,366		)	(637		)
Net income	$	727		$	855		$	506		$	(1,361	)	$	727

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

Condensed Consolidating Statements of Cash Flows

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2019
(in millions)
	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by operating activities	$	782		$	907		$	656		$	(1,368	)	$	977
Cash flows from investing activities
Property, plant and equipment, net	—			(35		)	(1,123		)	2			(1,156		)
Investments in subsidiaries	(1,109		)	(949		)	—			2,058			—
Return of capital	721			546			—			(1,267		)	—
Other	—			—			(1		)	—			(1		)
Net cash used in investing activities	(388		)	(438		)	(1,124		)	793			(1,157		)
Cash flows from financing activities
Proceeds from issuances of debt	2,230			—			—			—			2,230
Repayments of debt	(730		)	—			—			—			(730		)
Debt issuance and deferred financing costs	(33		)	—			—			—			(33		)
Debt extinguishment costs	(4		)	—			—			—			(4		)
Distributions to parent	—			(1,581		)	(1,052		)	2,633			—
Contributions from parent	—			1,109			949			(2,058		)	—
Distributions to owners	(935		)	—			—			—			(935		)
Other	—			3			—			—			3
Net cash provided by (used in) financing activities	528			(469		)	(103		)	575			531
Net increase (decrease) in cash, cash equivalents and restricted cash	922			—			(571		)	—			351
Cash, cash equivalents and restricted cash—beginning of period	779			6			756			—			1,541
Cash, cash equivalents and restricted cash—end of period	$	1,701		$	6		$	185		$	—		$	1,892

Balances per Condensed Consolidating Balance Sheet:

	September 30, 2019
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	1,701	$	6	$	—	$	—	$	1,707
Restricted cash	—		—		185		—		185
Total cash, cash equivalents and restricted cash	$	1,701	$	6	$	185	$	—	$	1,892

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

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Accounts and Other Receivables (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Receivables [Abstract]
SPL trade receivable	$ 261	$ 330
Other accounts receivable	16	18
Total accounts and other receivables	$ 277	$ 348

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Derivative Instruments - Narrative (Details) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 31, 2018 USD ($)	Sep. 30, 2019 tbtu	Dec. 31, 2018 tbtu
CQP Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative gain (loss), net | $	$ 28
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract		10 years
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount		3,880	2,978
SPL [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Energy Units Secured Through Natural Gas Supply Contracts		4,108	3,464

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Accounts and Other Receivables (Tables)

9 Months Ended

Sep. 30, 2019

Receivables [Abstract]

Schedule of Accounts and Other Receivables

As of September 30, 2019 and December 31, 2018, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
SPL trade receivable	$	261	$	330
Other accounts receivable	16		18
Total accounts and other receivables	$	277	$	348

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2019

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2019		2018
Cash paid during the period for interest, net of amounts capitalized	$	624	$	586

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $298 million and $204 million as of September 30, 2019 and 2018, respectively.

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Revenues from Contracts with Customers

9 Months Ended

Sep. 30, 2019

Revenue from Contract with Customer [Abstract]

Revenues from Contracts with Customers

REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
LNG revenues	$	1,139	$	1,249	$	3,676	$	3,419
LNG revenues—affiliate	257		205		1,017		886
Regasification revenues	66		66		199		196
Other revenues	13		9		36		28
Total revenues from customers	1,475		1,529		4,928		4,529
Net derivative gains (1)	1		—		2		—
Total revenues	$	1,476	$	1,529	$	4,930	$	4,529

(1) See Note 7—Derivative Instruments for additional information about our derivatives.

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):

	Nine Months Ended September 30, 2019
Deferred revenues, beginning of period	$	116
Cash received but not yet recognized	169
Revenue recognized from prior period deferral	(116		)
Deferred revenues, end of period	$	169

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2019 and December 31, 2018:

	September 30, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues (2)	$	55.7	10	$	53.6	10
Regasification revenues	2.4		5	2.6		6
Total revenues	$	58.1		$	56.2

(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.

(2) Includes future consideration from agreement contractually assigned to SPL from Cheniere Marketing.

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

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

(2) We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes substantially 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. Approximately 49% and 55% of our LNG revenues during the three months ended September 30, 2019 and 2018, respectively, and approximately 53% and 55% of our LNG revenues during the nine months ended September 30, 2019 and 2018, respectively, were related to variable consideration received from customers. During each of the three and nine months ended September 30, 2019 and 2018, approximately 3% of our regasification revenues were related to variable consideration received from customers. All of our LNG revenues—affiliate were related to variable consideration received from customers during each of the three and nine months ended September 30, 2019 and 2018.

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.

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Consolidated Statements of Partners' Equity Parentheticals - $ / shares	3 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018
Common Units [Member]
Distributions Paid, Per Unit	$ 0.61	$ 0.60	$ 0.59	$ 0.56	$ 0.55	$ 0.50
Subordinated Units [Member]
Distributions Paid, Per Unit	$ 0.61	$ 0.60	$ 0.59	$ 0.56	$ 0.55	$ 0.50

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Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 1,707	$ 0
Restricted cash	185	1,541
Accounts and other receivables	277	348
Accounts receivable—affiliate	67	114
Advances to affiliate	177	228
Inventory	103	99
Derivative assets	8	6
Other current assets	65	20
Total current assets	2,589	2,356
Property, plant and equipment, net	16,338	15,390
Operating lease assets, net	91	0
Debt issuance costs, net	17	13
Non-current derivative assets	29	31
Other non-current assets, net	157	184
Total assets	19,221	17,974
Current liabilities
Accounts payable	17	15
Accrued liabilities	657	821
Due to affiliates	40	49
Deferred revenue	169	116
Deferred revenue—affiliate	0	1
Current operating lease liabilities	6	0
Derivative liabilities	29	66
Total current liabilities	918	1,068
Long-term debt, net	17,571	16,066
Non-current operating lease liabilities	84	0
Non-current derivative liabilities	32	14
Other non-current liabilities	4	4
Other non-current liabilities—affiliate	20	22
Partners’ equity
Common unitholders’ interest (348.6 million units issued and outstanding at September 30, 2019 and December 31, 2018)	1,692	1,806
Subordinated unitholders’ interest (135.4 million units issued and outstanding at September 30, 2019 and December 31, 2018)	(1,035)	(990)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2019 and December 31, 2018)	(65)	(16)
Total partners’ equity	592	800
Total liabilities and partners’ equity	$ 19,221	$ 17,974

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2019

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2019 and December 31, 2018, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	September 30, 2019												December 31, 2018
	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 (liability)	$	(6	)	$	(10	)	$	(8	)	$	(24	)	$	5	$	(23	)	$	(25	)	$	(43	)

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2019:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$(8)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.618) - $0.056

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

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2019 and 2018 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Balance, beginning of period	$	34		$	11		$	(25	)	$	43
Realized and mark-to-market gains (losses):
Included in cost of sales	(42		)	4			(22		)	(5		)
Purchases and settlements:
Purchases	(1		)	4			(4		)	8
Settlements	1			1			43			(27		)
Transfers out of Level 3 (1)	—			(1		)	—			—
Balance, end of period	$	(8	)	$	19		$	(8	)	$	19
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(42	)	$	4		$	(22	)	$	(5	)

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

Fair Value of Derivative Instruments by Balance Sheet Location

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

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	September 30, 2019			December 31, 2018
Derivative assets	$	8		$	6
Non-current derivative assets	29			31
Total derivative assets	37			37
Derivative liabilities	(29		)	(66		)
Non-current derivative liabilities	(32		)	(14		)
Total derivative liabilities	(61		)	(80		)
Derivative liability, net	$	(24	)	$	(43	)

(1) Does not include collateral calls of $10 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018, respectively.

Derivative Net Presentation on Consolidated Balance Sheets

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

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2019
Liquefaction Supply Derivatives	$	40		$	(3	)	$	37
Liquefaction Supply Derivatives	(63		)	2			(61		)
As of December 31, 2018
Liquefaction Supply Derivatives	$	63		$	(26	)	$	37
Liquefaction Supply Derivatives	(92		)	12			(80		)

Liquefaction Supply Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

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 and nine months ended September 30, 2019 and 2018 (in millions):

		Three Months Ended September 30,					Nine Months Ended September 30,
	Consolidated Statement of Income Location (1)	2019			2018		2019		2018
Liquefaction Supply Derivatives gain	LNG revenues	$	1		$	—	$	2	$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	(55		)	10		28		(42		)

(1)

Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

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Leases (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Schedule of Leases, Balance Sheet Location

The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):

	Consolidated Balance Sheet Location	September 30, 2019
Right-of-use assets—Operating	Operating lease assets, net	$	91
Current operating lease liabilities	Current operating lease liabilities	6
Non-current operating lease liabilities	Non-current operating lease liabilities	84

Schedule of Lease Cost, Income Statement Location

The following table shows the classification and location of our lease cost on our Consolidated Statements of Income (in millions):

	Consolidated Statement of Income Location	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost (1)	Operating costs and expenses (2)	$	2	$	8

(1)    Includes $1 million of variable lease costs.

(2)

Presented in cost of sales, operating and maintenance expense, general and administrative expense or general and administrative expense—affiliate consistent with the nature of the asset under lease.

Schedule of Maturity of Lease Liabilities

Future annual minimum lease payments for operating leases as of September 30, 2019 are as follows (in millions): 

Years Ending December 31,	Operating Leases
2019	$	3
2020	10
2021	10
2022	10
2023	10
Thereafter	125
Total lease payments	168
Less: Interest	(78		)
Present value of lease liabilities	$	90

Future annual minimum lease payments for operating leases as of December 31, 2018, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows (in millions):

Years Ending December 31,	Operating Leases (1)
2019	$	10
2020	10
2021	10
2022	10
2023	10
Thereafter	124
Total	$	174

(1)

Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components.

Lessee, Other Quantitative Information

The following table shows the weighted-average remaining lease term (in years) and the weighted-average discount rate for our operating leases:

	September 30, 2019
Weighted-average remaining lease term (in years)	25.9
Weighted-average discount rate	4.8	%

The following table includes other quantitative information for our operating leases (in millions):

	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	7

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Customer Concentration (Tables)

9 Months Ended

Sep. 30, 2019

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 revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers:

	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2019	2018	2019	2018	2019	2018
Customer A	24%	24%	28%	27%	20%	35%
Customer B	18%	21%	19%	22%	17%	23%
Customer C	22%	21%	20%	23%	15%	30%
Customer D	19%	24%	21%	18%	21%	*
Customer E	*	—%	*	—%	14%	—%

* Less than 10%

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Other Non-Current Assets

9 Months Ended

Sep. 30, 2019

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

As of September 30, 2019 and December 31, 2018, other non-current assets, net consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
Advances made to municipalities for water system enhancements	$	88	$	90
Advances and other asset conveyances to third parties to support LNG terminals	35		36
Tax-related payments and receivables	17		17
Information technology service prepayments	8		20
Advances made under EPC and non-EPC contracts	2		14
Other	7		7
Total other non-current assets, net	$	157	$	184

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Accounts and Other Receivables

9 Months Ended

Sep. 30, 2019

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2019 and December 31, 2018, accounts and other receivables consisted of the following (in millions):

	September 30,		December 31,
	2019		2018
SPL trade receivable	$	261	$	330
Other accounts receivable	16		18
Total accounts and other receivables	$	277	$	348

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Related Party Transactions - Other Agreements (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Related Party Transaction [Line Items]
Due to affiliates	$ 40,000,000		$ 40,000,000		$ 49,000,000
Other non-current liabilities—affiliate	20,000,000		20,000,000		22,000,000
LNG revenues—affiliate	257,000,000	$ 205,000,000	1,017,000,000	$ 886,000,000
Cooperative Endeavor Agreements [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Aggregate commitment under the Agreement	25,000,000		$ 25,000,000
Tax Initiative Agreement Term			10 years
Cooperative Endeavor Agreements [Member] | Cheniere Marketing [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Due to affiliates	4,000,000		$ 4,000,000		3,000,000
Other non-current liabilities—affiliate	20,000,000		20,000,000		$ 22,000,000
Terminal Marine Services Agreement [Member] | Wholly owned subsidiary of Cheniere [Member] | Tug Services [Member]
Related Party Transaction [Line Items]
General Partner Distributions	2,000,000	2,000,000	5,000,000	4,000,000
LNG Terminal Export Agreement [Member] | Cheniere Marketing [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 0	$ 0	0	$ 0
Tax Sharing Agreement [Member] | Cheniere [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			0
Tax Sharing Agreement [Member] | Cheniere [Member] | SPL [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			0
Tax Sharing Agreement [Member] | Cheniere [Member] | CTPL [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			$ 0

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 624	$ 586
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 298	$ 204

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Debt - Schedule of Debt Instruments (Details) - USD ($)	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net	$ (179,000,000)	$ (184,000,000)
Long-term Debt, Net	17,571,000,000	16,066,000,000
Current Debt, Working Capital Facility	0	0
Total Debt, Net	17,571,000,000	16,066,000,000
2021 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2022 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,000,000,000	1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.25%
2023 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%
2025 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,350,000,000	1,350,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.20%
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 800,000,000	800,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2025 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.25%
2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,100,000,000	1,100,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2029 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	4.50%
2016 CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	0
2019 CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	0	0
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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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
		Oct. 31, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
CQP Interest Rate Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ 28
Liquefaction Supply Derivatives [Member] | LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]		$ 1	$ 0	$ 2	$ 0
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]		$ (55)	$ 10	$ 28	$ (42)

[1] Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (24)	$ (43)
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	(6)	5
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	(10)	(23)
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	$ (8)	$ (25)