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, 2021

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 29, 2021, the registrant had 484,025,623 common units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Statements of Operations	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Partners’ Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7
	Note 1—Nature of Operations and Basis of Presentation	7
	Note 2—Unitholders’ Equity	7
	Note 3—Restricted Cash	8
	Note 4—Accounts and Other Receivables, Net of Current Expected Credit Losses	8
	Note 5—Inventory	8
	Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation	8
	Note 7—Derivative Instruments	9
	Note 8—Accrued Liabilities	12
	Note 9—Debt	13
	Note 10—Revenues from Contracts with Customers	15
	Note 11—Related Party Transactions	18
	Note 12—Net Income per Common Unit	22
	Note 13—Customer Concentration	24
	Note 14—Supplemental Cash Flow Information	24
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	39
Part II. Other Information
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
	Signatures	42

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; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
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; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
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, 2021, 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. 

2

PART I.     FINANCIAL INFORMATION

ITEM 1.    CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

(unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenues
LNG revenues	$	1,791	$	807	$	5,057	$	3,588
LNG revenues—affiliate	453		103		878		352
Regasification revenues	68		67		202		202
Other revenues	12		5		39		28
Total revenues	2,324		982		6,176		4,170
Operating costs and expenses
Cost of sales (excluding items shown separately below)	1,342		454		3,178		1,551
Cost of sales—affiliate	8		33		62		38
Cost of sales—related party	—		—		1		—
Operating and maintenance expense	148		146		465		463
Operating and maintenance expense—affiliate	34		34		103		115
Operating and maintenance expense—related party	12		—		34		—
Development expense	—		—		1		—
General and administrative expense	2		2		7		12
General and administrative expense—affiliate	22		24		64		73
Depreciation and amortization expense	140		137		417		413
Impairment expense and loss on disposal of assets	—		—		6		5
Total operating costs and expenses	1,708		830		4,338		2,670
Income from operations	616		152		1,838		1,500
Other income (expense)
Interest expense, net of capitalized interest	(210)		(221)		(636)		(691)
Loss on modification or extinguishment of debt	(27)		—		(81)		(43)
Other income, net	2		2		2		8
Total other expense	(235)		(219)		(715)		(726)
Net income (loss)	$	381	$	(67)	$	1,123	$	774
Basic and diluted net income (loss) per common unit	$	0.69	$	(0.08)	$	2.07	$	1.55
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation	484.0		414.8		484.0		370.9

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

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

	September 30,		December 31,
	2021		2020
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	1,713	$	1,210
Restricted cash	133		97
Accounts and other receivables, net of current expected credit losses	358		318
Accounts receivable—affiliate	198		184
Advances to affiliate	130		144
Inventory	134		107
Current derivative assets	44		14
Other current assets	105		61
Total current assets	2,815		2,135
Property, plant and equipment, net of accumulated depreciation	16,820		16,723
Operating lease assets, net of accumulated amortization	93		99
Debt issuance costs, net of accumulated amortization	13		17
Derivative assets	25		11
Other non-current assets, net	163		160
Total assets	$	19,929	$	19,145
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	14	$	12
Accrued liabilities	846		658
Accrued liabilities—related party	5		4
Current debt, net of discount and debt issuance costs	944		—
Due to affiliates	45		53
Deferred revenue	166		137
Deferred revenue—affiliate	4		1
Current operating lease liabilities	8		7
Current derivative liabilities	23		11
Total current liabilities	2,055		883
Long-term debt, net of premium, discount and debt issuance costs	17,171		17,580
Non-current deferred revenue	1		—
Operating lease liabilities	85		90
Derivative liabilities	13		35
Other non-current liabilities	—		1
Other non-current liabilities—affiliate	15		17
Partners’ equity
Common unitholders’ interest (484.0 million units issued and outstanding at both September 30, 2021 and December 31, 2020)	856		714
General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2021 and December 31, 2020)	(267)		(175)
Total partners’ equity	589		539
Total liabilities and partners’ equity	$	19,929	$	19,145

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, 2021
	Common Unitholders’ Interest			Subordinated Unitholder’s Interest			General Partner’s Interest			Total Partners’ Equity
	Units	Amount		Units	Amount		Units	Amount
Balance at December 31, 2020	484.0	$	714	—	$	—	9.9	$	(175)	$	539
Net income	—	340		—	—		—	7		347
Distributions
Common units, $0.655/unit	—	(316)		—	—		—	—		(316)
General partner units	—	—		—	—		—	(35)		(35)
Balance at March 31, 2021	484.0	738		—	—		9.9	(203)		535
Net income	—	387		—	—		—	8		395
Distributions
Common units, $0.660/unit	—	(320)		—	—		—	—		(320)
General partner units	—	—		—	—		—	(39)		(39)
Balance at June 30, 2021	484.0	805		—	—		9.9	(234)		571
Net income	—	373		—	—		—	8		381
Distributions
Common units, $0.665/unit	—	(322)		—	—		—	—		(322)
General partner units	—	—		—	—		—	(41)		(41)
Balance at September 30, 2021	484.0	$	856	—	$	—	9.9	$	(267)	$	589

Three and Nine Months Ended September 30, 2020
	Common Unitholders’ Interest			Subordinated Unitholder’s Interest			General Partner’s Interest			Total Partners’ Equity
	Units	Amount		Units	Amount		Units	Amount
Balance at December 31, 2019	348.6	$	1,792	135.4	$	(996)	9.9	$	(81)	$	715
Net income	—	307		—	119		—	9		435
Distributions
Common units, $0.630/unit	—	(220)		—	—		—	—		(220)
Subordinated units, $0.630/unit	—	—		—	(85)		—	—		(85)
General partner units	—	—		—	—		—	(25)		(25)
Balance at March 31, 2020	348.6	1,879		135.4	(962)		9.9	(97)		820
Net income	—	287		—	111		—	8		406
Distributions
Common units, $0.640/unit	—	(223)		—	—		—	—		(223)
Subordinated units, $0.640/unit	—	—		—	(86)		—	—		(86)
General partner units	—	—		—	—		—	(29)		(29)
Balance at June 30, 2020	348.6	$	1,943	135.4	$	(937)	9.9	$	(118)	$	888
Net loss	—	(65)		—	(1)		—	(1)		(67)
Conversion of subordinated units into common units	135.4	(1,026)		(135.4)	1,026		—	—		—
Distributions
Common units, $0.645/unit	—	(225)		—	—		—	—		(225)
Subordinated units, $0.645/unit	—	—		—	(88)		—	—		(88)
General partner units	—	—		—	—		—	(30)		(30)
Balance at September 30, 2020	484.0	$	627	—	$	—	9.9	$	(149)	$	478

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

5

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Nine Months Ended September 30,
	2021		2020
Cash flows from operating activities
Net income	$	1,123	$	774
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	417		413
Amortization of debt issuance costs, premium and discount	22		24
Loss on modification or extinguishment of debt	81		43
Total losses (gains) on derivatives, net	(64)		38
Net cash provided by (used for) settlement of derivative instruments	10		(2)
Impairment expense and loss on disposal of assets	6		5
Other	13		10
Changes in operating assets and liabilities:
Accounts and other receivables, net of current expected credit losses	(41)		93
Accounts receivable—affiliate	(13)		23
Advances to affiliate	11		31
Inventory	(26)		2
Accounts payable and accrued liabilities	165		(96)
Accrued liabilities—related party	1		2
Due to affiliates	(6)		(3)
Deferred revenue	29		24
Other, net	(62)		(45)
Other, net—affiliate	1		(3)
Net cash provided by operating activities	1,667		1,333
Cash flows from investing activities
Property, plant and equipment	(495)		(795)
Net cash used in investing activities	(495)		(795)
Cash flows from financing activities
Proceeds from issuances of debt	2,700		1,995
Repayments of debt	(2,172)		(2,000)
Debt issuance and other financing costs	(35)		(34)
Debt extinguishment costs	(61)		(39)
Distributions to owners	(1,073)		(1,011)
Other	8		—
Net cash used in financing activities	(633)		(1,089)
Net increase (decrease) in cash, cash equivalents and restricted cash	539		(551)
Cash, cash equivalents and restricted cash—beginning of period	1,307		1,962
Cash, cash equivalents and restricted cash—end of period	$	1,846	$	1,411

Balances per Consolidated Balance Sheets:

	September 30,
	2021
Cash and cash equivalents	$	1,713
Restricted cash	133
Total cash, cash equivalents and restricted cash	$	1,846

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

6

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, and has natural gas liquefaction facilities consisting of five operational natural gas liquefaction Trains and one additional Train that is undergoing commissioning and expected to be substantially completed in the first quarter of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG terminal also has operational regasification facilities that include five LNG storage tanks, vaporizers and two marine berths, with an additional marine berth that is under construction. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”).

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 fiscal year ended December 31, 2020.

Results of operations for the three and nine months ended September 30, 2021 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2021.

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. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

Recent Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

NOTE 2—UNITHOLDERS’ EQUITY

The common 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.

Although common unitholders are not obligated to fund losses of the Partnership, its capital account, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continues 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 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.

7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

As of September 30, 2021, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.4% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of The Blackstone Group Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 8.0% by the public. All of our 2% general partner interest was held by Cheniere. CQP Target Holdco’s equity interests are 50.00% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone and 50.00% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

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, 2021 and December 31, 2020, we had $133 million and $97 million of restricted cash, respectively.

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

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

As of September 30, 2021 and December 31, 2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
SPL trade receivable	$	338	$	300
Other accounts receivable	20		18
Total accounts and other receivables, net of current expected credit losses	$	358	$	318

NOTE 5—INVENTORY

As of September 30, 2021 and December 31, 2020, inventory consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Materials	$	83	$	81
LNG	33		8
Natural gas	16		17
Other	2		1
Total inventory	$	134	$	107

NOTE 6—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

As of September 30, 2021 and December 31, 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
LNG terminal
LNG terminal and interconnecting pipeline facilities	$	16,950	$	16,908
LNG terminal construction-in-process	2,623		2,154
Accumulated depreciation	(2,757)		(2,344)
Total LNG terminal, net of accumulated depreciation	16,816		16,718
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(24)
Total fixed assets, net of accumulated depreciation	4		5
Property, plant and equipment, net of accumulated depreciation	$	16,820	$	16,723

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows depreciation expense during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Depreciation expense	$	139	$	135	$	414	$	409

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, 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 Operations to the extent not utilized for the commissioning process, in which case it is capitalized.

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, 2021 and December 31, 2020 (in millions):

	Fair Value Measurements as of
	September 30, 2021								December 31, 2020
	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)	$	(18)	$	(8)	$	59	$	33	$	1	$	(1)	$	(21)	$	(21)

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, 2021 and December 31, 2020, 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 incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2021:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$59	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.333) - $0.415 / $0.015

(1)Unobservable inputs were weighted by the relative fair value of the instruments.

Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.

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, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Balance, beginning of period	$	33	$	51	$	(21)	$	24
Realized and mark-to-market gains (losses):
Included in cost of sales	25		(47)		79		(22)
Purchases and settlements:
Purchases	4		5		6		4
Settlements	(3)		(8)		(5)		(6)
Transfers out of Level 3, net (1)	—		(1)		—		—
Balance, end of period	$	59	$	—	$	59	$	—
Change in unrealized gains (losses) relating to instruments still held at end of period	$	25	$	(47)	$	79	$	(22)

(1)Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty on a net basis. 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 any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

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 remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.

The notional natural gas position of our Liquefaction Supply Derivatives was approximately 5,135 TBtu and 4,970 TBtu as of September 30, 2021 and December 31, 2020, respectively, of which 99 TBtu and 91 TBtu, respectively, were for a natural gas supply contract that SPL has with a related party.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets

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 Sheets Location	September 30, 2021		December 31, 2020
Current derivative assets	$	44	$	14
Derivative assets	25		11
Total derivative assets	69		25
Current derivative liabilities	(23)		(11)
Derivative liabilities	(13)		(35)
Total derivative liabilities	(36)		(46)
Derivative asset (liability), net	$	33	$	(21)

(1)Does not include collateral posted with counterparties by us of $29 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both September 30, 2021 and December 31, 2020.

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues	$	—	$	7	$	—	$	3
Cost of sales	10		(74)		64		(41)

(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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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Consolidated Balance Sheets 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):

	Liquefaction Supply Derivatives
As of September 30, 2021
Gross assets	$	76
Offsetting amounts	(7)
Net assets	$	69
Gross liabilities	$	(43)
Offsetting amounts	7
Net liabilities	$	(36)
As of December 31, 2020
Gross assets	$	69
Offsetting amounts	(44)
Net assets	$	25
Gross liabilities	$	(48)
Offsetting amounts	2
Net liabilities	$	(46)

NOTE 8—ACCRUED LIABILITIES

As of September 30, 2021 and December 31, 2020, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Interest costs and related debt fees	$	209	$	203
Accrued natural gas purchases	523		374
LNG terminal and related pipeline costs	87		71
Other accrued liabilities	27		10
Total accrued liabilities	$	846	$	658

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—DEBT

As of September 30, 2021 and December 31, 2020, our debt consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 SPL Working Capital Facility”) (1)	$	13,128	$	13,650
Cheniere Partners — 3.250% to 5.625% senior notes due between October 2025 and January 2032 and credit facilities (“2019 CQP Credit Facilities”)	4,200		4,100
Unamortized premium, discount and debt issuance costs, net of accumulated amortization	(157)		(170)
Total long-term debt, net of premium, discount and debt issuance costs	17,171		17,580
Current debt:
SPL — current portion of 6.25% senior secured notes due March 2022 (the “2022 SPL Senior Notes”) (1) (2)	522		—
Cheniere Partners — current portion of 5.625% senior notes due October 2026 (the “2026 CQP Senior Notes”) (3)	428		—
Unamortized discount and debt issuance costs, net of accumulated amortization	(6)		—
Total current debt, net of discount and debt issuance costs	944		—
Total debt, net of premium, discount and debt issuance costs	$	18,115	$	17,580

(1)A portion of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected series of sales of approximately $482 million aggregate principal amount of senior secured notes due 2037 pursuant to executed note purchase agreements, expected to be issued in the fourth quarter of 2021, subject to customary closing conditions, will be used to strategically refinance a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses.

(2)In October 2021, $318 million of the 2022 SPL Senior Notes was redeemed with $100 million of the proceeds from our issuance of the 3.250% senior notes due 2032 (the “2032 CQP Senior Notes”) and $218 million of cash on hand. See Issuances and Redemptions section below for further discussion.

(3)In October 2021, we redeemed the remaining outstanding aggregate principal amount of the 2026 CQP Senior Notes that were not purchased pursuant to the tender offer and consent solicitation in September 2021. See Issuances and Redemptions section below for further discussion.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Issuances and Redemptions

The following table shows the issuances and redemptions of long-term debt during the nine months ended September 30, 2021 (in millions), excluding intra-quarter borrowings and repayments:

Issuances	Principal Amount Issued
Three Months Ended March 31, 2021
Cheniere Partners — 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) (1)	$	1,500
Three Months Ended September 30, 2021
Cheniere Partners — 2032 CQP Senior Notes (2)	1,200
Nine Months Ended September 30, 2021 total	$	2,700
Redemptions	Principal Amount Redeemed
Three Months Ended March 31, 2021
Cheniere Partners — 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) (1)	$	1,500
Three Months Ended September 30, 2021
Cheniere Partners — 2026 CQP Senior Notes (2)	672
Nine Months Ended September 30, 2021 total	$	2,172

(1)Net proceeds from the issuance of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in $54 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

(2)Net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem a portion of the 2026 CQP Senior Notes in September 2021 pursuant to the tender offer and consent solicitation, resulting in $27 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs. In October 2021, the remaining net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem the remaining outstanding principal amount of the 2026 CQP Senior Notes and, together with cash on hand, redeem $318 million of the 2022 SPL Senior Notes.

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2021 (in millions):

	2020 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	396		—
Available commitment	$	804	$	750
Priority ranking	Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Weighted average interest rate of outstanding balance	n/a		n/a
Maturity date	March 19, 2025		May 29, 2024

(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Restrictive Debt Covenants

The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain investments or pay dividends or distributions.

As of September 30, 2021, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Total interest cost	$	244	$	246	$	732	$	759
Capitalized interest	(34)		(25)		(96)		(68)
Total interest expense, net of capitalized interest	$	210	$	221	$	636	$	691

Fair Value Disclosures

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

	September 30, 2021				December 31, 2020
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	17,478	$	19,231	$	16,950	$	19,113
Senior notes — Level 3 (2)	800		997		800		1,036
Credit facilities — Level 3 (3)	—		—		—		—

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

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

(3)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 10—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, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues (1)	$	1,791	$	800	$	5,057	$	3,585
LNG revenues—affiliate	453		103		878		352
Regasification revenues	68		67		202		202
Other revenues	12		5		39		28
Total revenues from customers	2,324		975		6,176		4,167
Net derivative loss (2)	—		7		—		3
Total revenues	$	2,324	$	982	$	6,176	$	4,170

(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three and nine months ended September 30, 2020, we recognized $109 million and $513 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $21 million would have

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

been recognized subsequent to September 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million that would have otherwise been recognized during the period if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the three and nine months ended September 30, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

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

Contract Assets

The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	September 30,		December 31,
	2021		2020
Contract assets, net of current expected credit losses	$	1	$	—

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the nine months ended September 30, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

Deferred Revenue Reconciliation

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

	Nine Months Ended September 30, 2021
Deferred revenue, beginning of period	$	137
Cash received but not yet recognized in revenue	166
Revenue recognized from prior period deferral	(137)
Deferred revenue, end of period	$	166

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

	Nine Months Ended September 30, 2021
Deferred revenue—affiliate, beginning of period	$	1
Cash received but not yet recognized in revenue	4
Revenue recognized from prior period deferral	(1)
Deferred revenue—affiliate, end of period	$	4

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2021 and December 31, 2020:

	September 30, 2021			December 31, 2020
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	50.1	9	$	52.1	9
LNG revenues—affiliate	0.7		3	0.1		1
Regasification revenues	1.9		4	2.1		5
Total revenues	$	52.7		$	54.3

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

We 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)The table above excludes substantially all variable consideration under our SPAs and TUAs. 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 amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 63% and 39% of our LNG revenues from contracts included in the table above during the three months ended September 30, 2021 and 2020, respectively, and approximately 56% and 37% of our LNG revenues from contracts included in the table above during the nine months ended September 30, 2021 and 2020, respectively, were related to variable consideration received from customers. Approximately 96% and 94% of our LNG revenues—affiliate from contracts included in the table above during the three and nine months ended September 30, 2021, respectively, and 100% of our LNG revenues—affiliate from contracts included in the table above during each of the three and nine months ended September 30, 2020 were related to variable consideration received from customers. During each of the three and nine months ended September 30, 2021, approximately 5% of our regasification revenues were related to variable consideration received from customers, respectively, and during each of the three and nine months ended September 30, 2020, approximately 6% of our regasification revenues were related to variable consideration received from customers.

We may enter 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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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues—affiliate
Cheniere Marketing Agreements	$	441	$	87	$	860	$	328
Contracts for Sale and Purchase of Natural Gas and LNG	12		16		18		24
Total LNG revenues—affiliate	453		103		878		352
Cost of sales—affiliate
Cheniere Marketing Agreements	—		32		34		32
Contracts for Sale and Purchase of Natural Gas and LNG	8		1		28		6
Total cost of sales—affiliate	8		33		62		38
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	—		—		1		—
Operating and maintenance expense—affiliate
Services Agreements	34		34		103		115
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		—		34		—
General and administrative expense—affiliate
Services Agreements	22		24		64		73

As of September 30, 2021 and December 31, 2020, we had $198 million and $184 million, respectively, of accounts receivable—affiliate under the agreements described below.

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. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Marketing Letter Agreements

In August 2021, SPL and Cheniere Marketing entered into a letter agreement (amending and restating the previous letter agreement between the parties from February 2021) for the sale of up to 81 cargoes to be delivered between 2021 and 2027 at a price equal to 115% of Henry Hub plus $1.96 per MMBtu. Additionally, SPL and Cheniere Marketing entered into a letter agreement for the sale of (1) up to six cargoes to be delivered in 2022 and up to six cargoes to be delivered in 2023 at a price equal to 115% of Henry Hub plus $1.768 per MMBtu; and (2) up to six cargoes to be delivered in 2022 at a price equal to 115% of Henry Hub plus $1.952 per MMBtu.

In December 2020, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu.

In December 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes that were delivered in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.

Facility Swap Agreement

In August 2020, SPL entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.

Natural Gas Transportation and Storage Agreements

SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by Brookfield, who indirectly acquired a portion of our limited partner interests in September 2020 through its purchase of a portion of CQP Target Holdco’s equity interests. We recorded operating and maintenance expense—related party of $12 million and $34 million and cost of sales—related party of zero and $1 million during the three and nine months ended September 30, 2021, respectively, and accrued liabilities—related party of $5 million and $4 million as of September 30, 2021 and December 31, 2020, respectively, with this related party.

Services Agreements

As of September 30, 2021 and December 31, 2020, we had $130 million and $144 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 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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

CTPL MSA

CTPL has a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the operations and business of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations, providing contract administration services for all contracts associated with the Creole Trail Pipeline and obtaining insurance. CTPL is required to reimburse Cheniere Terminals for the aggregate of all costs and expenses incurred in the course of performing the services under the CTPL MSA.

Natural Gas Supply Agreement

SPL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party is partially owned by Blackstone, who also partially owns our limited partner interests. The term of the agreement is for five years, which can commence no earlier than November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions precedent.

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 advanced payments of annual ad valorem taxes 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 shall grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal as early as 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 the dollar-for-dollar credit applied to the ad valorem tax levied against the Sabine Pass LNG terminal in the given year.

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 $2 million in due to affiliates as of both September 30, 2021 and December 31, 2020 and $15 million and $17 million of other non-current liabilities—affiliate as of September 30, 2021 and December 31, 2020, respectively, from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

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

SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with Cheniere Terminals 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 Cheniere Terminals a portion of its future revenues. Accordingly, Tug Services distributed $2 million and $1 million during the three months ended September 30, 2021 and 2020, respectively, and $6 million and

21

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

$4 million during the nine months ended September 30, 2021 and 2020, respectively, to Cheniere Terminals, 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, 2021 and 2020.

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 and Cheniere has not demanded any such payments from SPLNG under the agreement. 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 and Cheniere has not demanded any such payments from SPL under the agreement. 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 and Cheniere has not demanded any such payments from CTPL under the agreement. The agreement is effective for tax returns due on or after May 2013.

NOTE 12—NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statements of Partners’ Equity. On October 26, 2021, we declared a $0.680 distribution per common unit and the related distribution to our general partner and IDR holders that will be paid on November 12, 2021 to unitholders of record as of November 5, 2021 for the period from July 1, 2021 to September 30, 2021.

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 to 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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

			Limited Partner Units
	Total		Common Units		Subordinated Units		General Partner Units		IDR
Three Months Ended September 30, 2021
Net income	$	381
Declared distributions	375		329		—		8		38
Assumed allocation of undistributed net income (1)	$	6	6		—		—		—
Assumed allocation of net income			$	335	$	—	$	8	$	38
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	0.69	$	—
Three Months Ended September 30, 2020
Net loss	$	(67)
Declared distributions	346		315		—		6		25
Assumed allocation of undistributed net loss (1)	$	(413)	(347)		(58)		(8)		—
Assumed allocation of net loss			$	(32)	$	(58)	$	(2)	$	25
Weighted average units outstanding			414.8		69.2
Basic and diluted net loss per unit			$	(0.08)	$	(0.84)
Nine Months Ended September 30, 2021
Net income	$	1,123
Declared distributions	1,091		970		—		22		99
Assumed allocation of undistributed net income (1)	$	32	31		—		1		—
Assumed allocation of net income			$	1,001	$	—	$	23	$	99
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	2.07	$	—
Nine Months Ended September 30, 2020
Net income	$	774
Declared distributions	1,024		763		174		20		67
Assumed allocation of undistributed net loss (1)	$	(250)	(188)		(57)		(5)		—
Assumed allocation of net income			$	575	$	117	$	15	$	67
Weighted average units outstanding			370.9		113.1
Basic and diluted net income per unit			$	1.55	$	1.03

(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).

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—CUSTOMER CONCENTRATION

The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivable, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivable, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2021	2020	2021	2020	2021	2020
Customer A	20%	*	24%	22%	26%	31%
Customer B	17%	14%	16%	15%	18%	21%
Customer C	18%	26%	18%	18%	17%	*
Customer D	19%	22%	17%	18%	17%	22%
Customer E	11%	*	11%	12%	*	*

* Less than 10%

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2021		2020
Cash paid during the period for interest on debt, net of amounts capitalized	$	601	$	636

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $233 million as of both September 30, 2021 and 2020, respectively.

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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 (the “Securities Act”), 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;

•statements regarding the outbreak of COVID-19 and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing credit worthiness of our contractual counterparties, any disruptions in our operations or construction of our Trains and the health and safety of Cheniere’s employees, and on our customers, the global economy and the demand for LNG; 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

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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 fiscal year ended December 31, 2020. 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

•Results of Operations 

•Liquidity and Capital Resources 

•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 in 2006. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

The Sabine Pass LNG terminal, one of the largest LNG production facilities in the world, is located in Cameron Parish, Louisiana, and has natural gas liquefaction facilities consisting of five operational natural gas liquefaction Trains and one additional Train that is undergoing commissioning and expected to be substantially completed in the first quarter of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG terminal also has operational regasification facilities that include five LNG storage tanks with aggregate capacity of approximately 17 Bcfe, two existing marine berths and one under construction that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4 Bcf/d. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. Cheniere published its 2020 Corporate Responsibility (“CR”) report, which details our strategy and progress on ESG issues, as well as our efforts on integrating climate considerations into our business strategy and taking a leadership position on increased environmental transparency, including conducting a climate scenario analysis and our plan to provide LNG customers with Cargo Emission Tags. In August 2021, Cheniere also announced a peer-reviewed LNG life cycle assessment study which allows for improved greenhouse gas emissions assessment, which was published in the American Chemical Society Sustainable Chemistry & Engineering Journal. Cheniere’s CR report is available at cheniere.com/IMPACT. Information on our website, including the CR report, is not incorporated by reference into this Quarterly Report on Form 10-Q.

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Overview of Significant Events

Our significant events since January 1, 2021 and through the filing date of this Form 10-Q include the following:  

Operational

•As of October 31, 2021, over 1,430 cumulative LNG cargoes totaling approximately 110 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

•In September 2021, feed gas was introduced to Train 6 of the Liquefaction Project.

Financial

•We completed the following financing transactions:

◦In September 2021, we issued an aggregate principal amount of $1.2 billion of 3.52% Senior Notes due 2032 (the “2032 CQP Senior Notes”). Net proceeds of the 2032 CQP Senior Notes were used to redeem a portion of the outstanding $1.1 billion aggregate principal amount of the 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”) in September 2021 pursuant to a tender offer and consent solicitation. In October 2021, the remaining net proceeds of the 2032 CQP Senior Notes were used to redeem the remaining outstanding principal amount of the 2026 CQP Senior Notes and, together with cash on hand, redeem $318 million of the 6.25% Senior Secured Notes due 2022 (the “2022 SPL Senior Notes”).

◦During 2021, SPL entered into a series of note purchase agreements for the sale of approximately $482 million aggregate principal amount of Senior Secured Notes due 2037, on a private placement basis (the “2037 SPL Private Placement Senior Secured Notes”). The 2037 SPL Private Placement Senior Secured Notes are expected to be issued in the fourth quarter of 2021, subject to customary closing conditions, and the net proceeds will be used to redeem a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses. The 2037 SPL Private Placement Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years and a weighted average interest rate of 3.07%.

◦In March 2021, we issued an aggregate principal amount of approximately $1.5 billion of 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”). The net proceeds of the 2031 CQP Senior Notes, along with cash on hand, were used to redeem the 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) and to pay fees and expenses in connection with the redemption.

•In April 2021, S&P Global Ratings changed the outlook on our ratings to positive from negative.

•In February 2021, Fitch Ratings (“Fitch”) changed the outlook of SPL’s senior secured notes rating to positive from stable and the outlook of our long-term issuer default rating and senior unsecured notes rating to positive from stable.

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Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Project (including both operational and commissioning volumes) during the nine months ended September 30, 2021 and 2020:

(1) The nine months ended September 30, 2021 excludes eight TBtu that were loaded at our affiliate’s facility.

Net income

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share data)	2021		2020		Change		2021		2020		Change
Net income (loss)	$	381	$	(67)	$	448	$	1,123	$	774	$	349
Basic and diluted net income (loss) per common unit	0.69		(0.08)		0.77		2.07		1.55		0.52

Net income increased by $448 million and $349 million during the three and nine months ended September 30, 2021 from the comparable periods in 2020, primarily as a result of increased margins attributable to increased volume of LNG delivered between the periods and decreased losses from commodity derivatives to secure natural gas feedstock for the Liquefaction Project.

We enter into derivative instruments to manage our exposure to commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions being economically hedged are accounted for under the accrual method of accounting, 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, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.

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Revenues

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except volumes)	2021		2020		Change		2021		2020		Change
LNG revenues	$	1,791	$	807	$	984	$	5,057	$	3,588	$	1,469
LNG revenues—affiliate	453		103		350		878		352		526
Regasification revenues	68		67		1		202		202		—
Other revenues	12		5		7		39		28		11
Total revenues	$	2,324	$	982	$	1,342	$	6,176	$	4,170	$	2,006
LNG volumes recognized as revenues (in TBtu) (1)	308		132		176		946		666		280

(1)Excludes volume associated with cargoes for which customers notified us that they would not take delivery. During the nine months ended September 30, 2021, includes eight TBtu that were loaded at our affiliate’s facility.

Total revenues increased by approximately $1.3 billion and $2.0 billion during the three and nine months ended September 30, 2021, respectively, from the comparable periods in 2020, primarily as a result of higher volumes of LNG delivered between the periods due to the delivery of all available volume of LNG in 2021 and increased revenues per MMBtu during the three and nine months ended September 30, 2021. During the three and nine months ended September 30, 2020, we recognized $109 million and $513 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $21 million would have been recognized subsequent to September 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the three and nine months ended September 30, 2021.

Also included in LNG revenues are sales of certain unutilized natural gas procured for the liquefaction process and gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized revenues of $52 million and $130 million during the three months ended September 30, 2021 and 2020, respectively, and $112 million and $211 million during the nine months ended September 30, 2021 and 2020, respectively, related to these transactions.

Operating costs and expenses

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2021		2020		Change		2021		2020		Change
Cost of sales	$	1,342	$	454	$	888	$	3,178	$	1,551	$	1,627
Cost of sales—affiliate	8		33		(25)		62		38		24
Cost of sales—related party	—		—		—		1		—		1
Operating and maintenance expense	148		146		2		465		463		2
Operating and maintenance expense—affiliate	34		34		—		103		115		(12)
Operating and maintenance expense—related party	12		—		12		34		—		34
Development expense	—		—		—		1		—		1
General and administrative expense	2		2		—		7		12		(5)
General and administrative expense—affiliate	22		24		(2)		64		73		(9)
Depreciation and amortization expense	140		137		3		417		413		4
Impairment expense and loss on disposal of assets	—		—		—		6		5		1
Total operating costs and expenses	$	1,708	$	830	$	878	$	4,338	$	2,670	$	1,668

Total operating costs and expenses increased during the three and nine months ended September 30, 2021 from the three and nine months ended September 30, 2020, primarily as a result of increased cost of sales. 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 increased during the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily due to the increase in pricing of natural gas feedstock as a result of higher US natural gas prices and increased volume of LNG delivered, partially offset by a decrease in net costs associated with the sale of certain unutilized natural gas procured for the liquefaction process and the increased fair value of commodity derivatives to secure

29

natural gas feedstock for the Liquefaction Project due to favorable shifts in long-term forward prices relative to our hedged position. Cost of sales also includes variable transportation and storage costs and other costs to convert natural gas into LNG.

Cost of sales—affiliate decreased during the three months ended September 30, 2021 and increased during the nine months ended September 30, 2021 as a result of the cost of cargoes procured from our affiliate to fulfill our commitments to our long-term customers during operational constraints.

Other expense

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2021		2020		Change		2021		2020		Change
Interest expense, net of capitalized interest	$	210	$	221	$	(11)	$	636	$	691	$	(55)
Loss on modification or extinguishment of debt	27		—		27		81		43		38
Other income, net	(2)		(2)		—		(2)		(8)		6
Total other expense	$	235	$	219	$	16	$	715	$	726	$	(11)

Interest expense, net of capitalized interest, decreased during the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily due to lower interest costs as a result of refinancing higher cost debt and an increase in the portion of total interest costs that is eligible for capitalization primarily due to the continued construction of the remaining assets of the Liquefaction Project. During the three months ended September 30, 2021 and 2020, we incurred $244 million and $246 million of total interest cost, respectively, of which we capitalized $34 million and $25 million, respectively. During the nine months ended September 30, 2021 and 2020, we incurred $732 million and $759 million of total interest cost, respectively, of which we capitalized $96 million and $68 million, respectively.

Loss on modification or extinguishment of debt increased during the three and nine months ended September 30, 2021 from the comparable periods in 2020. Loss on modification or extinguishment of debt recognized in 2021 was primarily attributable to debt extinguishment costs relating to the payment of early redemption fees and premiums and the write off of unamortized debt issuance costs with the redemption of the 2025 CQP Senior Notes and 2026 CQP Senior Notes. Loss on modification or extinguishment of debt recognized in 2020 was primarily attributable to $43 million of debt extinguishment costs relating to the payment of early redemption fees and write off of unamortized debt premiums and issuance costs associated with the 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”).

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at September 30, 2021 and December 31, 2020 (in millions):

	September 30,		December 31,
	2021		2020
Cash and cash equivalents	$	1,713	$	1,210
Restricted cash designated for the Liquefaction Project	133		97
Available commitments under the following credit facilities:
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”)	804		787
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”)	750		750

CQP Senior Notes

The $1.5 billion of 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”), the 2031 CQP Senior Notes and the 2032 CQP Senior Notes (collectively, the “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 (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture, the 2031 CQP Senior Notes are further governed by the Fifth Supplemental Indenture and the 2032 CQP Senior Notes are further governed by the Sixth Supplemental Indenture. The indentures governing the CQP Senior Notes contain terms and events of default and certain covenants that, among other things, limit our ability and the CQP Guarantors’ ability to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

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At any time prior to October 1, 2024 for the 2029 CQP Senior Notes, March 1, 2026 for the 2031 CQP Senior Notes and January 31, 2027 for the 2032 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, 2024 for the 2029 CQP Senior Notes, March 1, 2024 for the 2031 CQP Senior Notes and January 31, 2025 for the 2032 CQP Senior Notes, we may redeem up to 35%, and in the case of the 2032 CQP Senior Notes, up to 40%, 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 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes, 104.000% of the aggregate principal amount of the 2031 CQP Senior Notes and 103.250% of the aggregate principal amount of the 2032 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, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes, March 1, 2026 through the maturity date of March 1, 2031 for the 2031 CQP Senior Notes and January 31, 2027 through maturity date of January 31, 2032 for the 2032 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 substantially all our 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). 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.

The CQP Guarantors’ guarantees are full and unconditional, subject to certain release provisions including (1) the sale, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the CQP 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. In the event of a default in payment of the principal or interest by us, whether at maturity of the CQP Senior Notes or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the CQP Guarantors to enforce the guarantee.

The rights of holders of the CQP Senior Notes against the CQP Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the CQP Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables include summarized financial information of Cheniere Partners (“Parent Issuer”), and the CQP Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis. Investments in and equity in the earnings of SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”), which are not currently members of the Obligor Group, have been excluded. Intercompany balances and transactions between entities in the Obligor Group have been eliminated. Although the creditors of the Obligor Group have no claim against the Non-Guarantors, the Obligor Group may gain access to the assets of the Non-Guarantors upon bankruptcy, liquidation or reorganization of the Non-Guarantors due to its investment in these entities. However, such claims to the assets of the Non-Guarantors would be subordinated to the any claims by the Non-Guarantors’ creditors, including trade creditors. See Sabine Pass LNG Terminal—SPL Senior Notes for additional detail on restrictions of Non-Guarantor debt.

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Summarized Balance Sheets (in millions)	September 30,		December 31,
	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	1,713	$	1,210
Accounts receivable from Non-Guarantors	38		46
Other current assets	54		42
Current assets—affiliate	126		137
Current assets with Non-Guarantors	—		—
Total current assets	1,931		—
Property, plant and equipment, net of accumulated depreciation	2,441		2,493
Other non-current assets, net	108		117
Total assets	$	4,480	$	2,610
LIABILITIES
Current liabilities
Due to affiliates	$	145	$	156
Deferred revenue from Non-Guarantors	21		22
Other current liabilities	543		100
Total current liabilities	709		278
Long-term debt, net of premium, discount and debt issuance costs	4,153		4,060
Other non-current liabilities	85		85
Non-current liabilities—affiliate	15		17
Total liabilities	$	4,962	$	4,440

Summarized Statement of Income (in millions)	Nine Months Ended September 30, 2021
Revenues	$	241
Revenues from Non-Guarantors	396
Total revenues	637
Operating costs and expenses	143
Operating costs and expenses—affiliate	145
Total operating costs and expenses	288
Income from operations	348
Net income	107

2019 CQP Credit Facilities

We have a $750 million revolving credit facility under the 2019 CQP Credit Facilities. Borrowings under the 2019 CQP Credit Facilities are being 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. As of both September 30, 2021 and December 31, 2020, we had $750 million of available commitments and no letters of credit issued or loans outstanding under the 2019 CQP Credit Facilities.

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.

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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).

Sabine Pass LNG Terminal 

Liquefaction Facilities

The Liquefaction Project is one of the largest LNG production facilities in the world. We are currently operating five Trains and two marine berths at the Liquefaction Project, undergoing commissioning of one additional Train that is expected to be substantially completed in the first quarter of 2022 and constructing a third marine berth. We have achieved substantial completion of the first five Trains of the Liquefaction Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the Liquefaction Project as of September 30, 2021:

	Train 6
Overall project completion percentage	97.1%
Completion percentage of:
Engineering	100.0%
Procurement	100.0%
Subcontract work	95.8%
Construction	92.9%
Date of expected substantial completion	1Q 2022

We received approval from FERC to site, construct and operate up to a combined total equivalent of approximately 1,661.94 Bcf/yr (approximately 33 mtpa) of natural gas from the Liquefaction Project. The DOE has has issued multiple orders authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal through December 31, 2050 to FTA countries and non-FTA countries for 1,509.3 Bcf/yr (approximately 30 mtpa) of natural gas, and an additional 152.64 Bcf/yr (approximately 3 mtpa) of natural gas to FTA countries only, with the authorization for the additional volume to non-FTA countries pending.

In December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations separately from long-term authorizations. Accordingly, the DOE amended each of SPL’s long-term authorizations to include short-term export authority, and vacated the short-term orders.

Customers

SPL has entered into fixed price long-term SPAs with third-parties, generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 16 years (plus extension rights) for Trains 1 through 6 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 75% of the total production capacity from these Trains, potentially increasing up to approximately 85% after giving effect to an SPA that Cheniere has committed to provide to us. 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 generally equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, 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 generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel 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.

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

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, (2) up to 30 cargoes scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu (3) up to 81 cargoes to be delivered between 2021 and 2027 at a price equal to 115% of Henry Hub plus $1.96 per MMBtu, (4) up to six cargoes to be delivered in 2022 and up to six cargoes to be delivered in 2023 at a price equal to 115% of Henry Hub plus $1.768 per MMBtu and (5) up to six cargoes to be delivered in 2022 at a price equal to 115% of Henry Hub plus $1.952 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, 2021, SPL had secured up to approximately 5,033 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.

Construction

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks 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 the third marine berth that is currently under construction. As of September 30, 2021, we have incurred $2.2 billion under this contract.

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. Approximately 2 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 TotalEnergies Gas & Power North America, Inc. (“Total”) and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 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 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 each of the three months ended September 30, 2021 and 2020, SPL recorded $32 million as operating and maintenance expense under this partial TUA assignment agreement. During

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each of the nine months ended September 30, 2021 and 2020, SPL recorded $97 million as operating and maintenance expense under this partial TUA assignment agreement.

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

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to the Liquefaction Project will be financed through cash flows under the SPAs, project debt and borrowings and equity contributions from us. We believe that with the net proceeds of borrowings, available commitments under the 2020 SPL Working Capital Facility and 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. 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, 2021 and December 31, 2020 (in millions):

	September 30,		December 31,
	2021		2020
Senior notes (1)	$	18,278	$	17,750
Credit facilities outstanding balance (2)	—		—
Letters of credit issued (3)	396		413
Available commitments under credit facilities (3)	1,554		1,537
Total capital resources from borrowings and available commitments (4)	$	20,228	$	19,700

(1)Includes SPL’s 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 (collectively, the “SPL Senior Notes”) and our CQP Senior Notes.

(2)Includes outstanding balances under the 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities that may be used for general corporate purposes.

(3)Consists of 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities.

(4)Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash equivalents.

SPL Senior Notes

The SPL Senior Notes are governed by a common indenture (the “SPL Indenture”) and the terms of the 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, 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. 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.

At any time prior to six months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2022 SPL Senior Notes, 5.625% Senior Secured Notes due 2023 (the “2023 SPL Senior Notes”), 5.75% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) and 5.625% Senior Notes due 2025 (the “2025 SPL Senior Notes”), in which case the time period is three 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

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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 six months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes and 2025 SPL Senior Notes, in which case the time period is within three months of the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

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 2020 SPL Working Capital Facility. 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 and are fully amortizing according to a fixed sculpted amortization schedule.

During 2021, SPL entered into a series of note purchase agreements for the sale of approximately $482 million aggregate principal amount of the 2037 SPL Private Placement Senior Secured Notes on a private placement basis. The 2037 SPL Private Placement Senior Secured Notes are expected to be issued in the fourth quarter of 2021, subject to customary closing conditions, and the net proceeds will be used to strategically refinance a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses. The 2037 SPL Private Placement Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years and a weighted average interest rate of 3.07%.

2020 SPL Working Capital Facility

In March 2020, SPL entered into the 2020 SPL Working Capital Facility with aggregate commitments of $1.2 billion, which replaced the $1.2 billion Amended and Restated SPL Working Capital Facility (the “2015 SPL Working Capital Facility”). The 2020 SPL Working Capital Facility is intended to be used for loans to SPL, swing line loans to SPL and the issuance of letters of credit on behalf of SPL, primarily for (1) the refinancing of the 2015 SPL Working Capital Facility, (2) fees and expenses related to the 2020 SPL Working Capital Facility, (3) SPL and its future subsidiaries’ gas purchase obligations and (4) SPL and certain of its future subsidiaries’ general corporate purposes. SPL may, from time to time, request increases in the commitments under the 2020 SPL Working Capital Facility of up to $800 million. As of September 30, 2021 and December 31, 2020, SPL had $804 million and $787 million of available commitments and $396 million and $413 million aggregate amount of issued letters of credit, respectively. As of both September 30, 2021 and December 31, 2020, SPL had no outstanding borrowings under the 2020 SPL Working Capital Facility.

The 2020 SPL Working Capital Facility matures on March 19, 2025, but may be extended with consent of the lenders. The 2020 SPL Working Capital Facility provides for mandatory prepayments under customary circumstances.

The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, satisfaction of a 12-month forward-looking and backward-looking 1.25:1.00 debt service reserve ratio test. The obligations of SPL under the 2020 SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a pari passu basis by a first priority lien with the SPL Senior Notes.

Restrictive Debt Covenants

As of September 30, 2021, we and SPL were in compliance with all covenants related to our respective debt agreements.

LIBOR

The use of LIBOR is expected to be phased out by June 2023. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue working with our lenders to pursue any amendments to our debt agreements that are currently subject to LIBOR following LIBOR cessation and will continue to monitor, assess and plan for the phase out of LIBOR.

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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, 2021 and 2020 (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,
	2021		2020
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	1,667	$	1,333
Proceeds from issuances of debt	2,700		1,995
Other	8		—
	$	4,375	$	3,328
Uses of cash, cash equivalents and restricted cash:
Property, plant and equipment	$	(495)	$	(795)
Repayments of debt	(2,172)		(2,000)
Debt issuance and other financing costs	(35)		(34)
Debt extinguishment costs	(61)		(39)
Distributions to owners	(1,073)		(1,011)
	(3,836)		(3,879)
Net increase (decrease) in cash, cash equivalents and restricted cash	$	539	$	(551)

Operating Cash Flows

Our operating cash net inflows during the nine months ended September 30, 2021 and 2020 were $1,667 million and $1,333 million, respectively. The $334 million increase in operating cash inflows in 2021 compared to 2020 was primarily related to cash provided by working capital primarily from payment timing differences and timing of cash receipts from the sale of LNG cargoes.

Proceeds from Issuance of Debt, Repayments of Debt, Debt Issuance and Other Financing Costs and Debt Extinguishment Costs

During the nine months ended September 30, 2021, we issued an aggregate principal amount of $1.5 billion of the 2031 CQP Senior Notes and $1.2 billion of the 2032 CQP Senior Notes and incurred $35 million of debt issuance costs related to these issuances. The proceeds from these issuances, together with cash on hand, were used to redeem all of the outstanding 2025 CQP Senior Notes and $672 million of the 2032 CQP Senior Notes, and we paid $61 million of debt extinguishment costs related to these redemptions, primarily for the payment of early redemption fees and write off of unamortized issuance costs.

During the nine months ended September 30, 2020, we entered into the 2020 SPL Working Capital Facility to replace the previous working capital facility and issued an aggregate principal amount of $2.0 billion of the 2030 SPL Senior Notes, which was used to redeem all of SPL’s outstanding 2021 SPL Senior Notes. We incurred $34 million of debt issuance costs primarily related to up-front fees paid upon closing of the 2030 SPL Senior Notes and the 2020 SPL Working Capital Facility and $39 million of debt extinguishment costs related to the redemption of the 2021 SPL Senior Notes, primarily for the payment of early redemption fees and write off of unamortized issuance costs.

Property, Plant and Equipment

Cash outflows for property, plant and equipment were primarily for the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion.

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Cash Distributions to Unitholders

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus. The following provides a summary of distributions paid by us during the three and nine months ended September 30, 2021 and 2020:

						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 13, 2021	April 1 - June 30, 2021	$	0.665	$	—	$	322	$	—	$	7	$	32
May 14, 2021	January 1 - March 31, 2021	0.660		—		320		—		7		30
February 12, 2021	October 1 - December 31, 2020	0.655		—		316		—		7		27
August 14, 2020	April 1 - June 30, 2020	0.645		0.645		225		88		7		22
May 15, 2020	January 1 - March 31, 2020	0.64		0.64		223		86		7		20
February 14, 2020	October 1 - December 31, 2019	0.63		0.63		220		85		6		18

On October 26, 2021, we declared a $0.680 distribution per common unit and the related distribution to our general partner and incentive distribution right holders to be paid on November 12, 2021 to unitholders of record as of November 5, 2021 for the period from July 1, 2021 to September 30, 2021.

Off-Balance Sheet Arrangements

As of September 30, 2021, 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 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 fiscal year ended December 31, 2020.

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.

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, 2021				December 31, 2020
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	33	$	2	$	(21)	$	4

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

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ITEM 4.     CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the 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. Other than discussed below, there have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2020.

In February 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal. These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to SPL alleging violations of federal pipeline safety regulations relating to the 2018 SPL tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200. On October 12, 2021, SPL responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. SPL continues to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.

ITEM 1A.    RISK FACTORS

Other than as set forth below, there have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2020.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our common units will generally be considered to be “effectively connected” with a U.S. trade or business and subject to U.S. federal income tax. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, withholding may be required on the amount realized unless the disposing unitholder certifies that it is not a foreign person. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the unitholder. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. In Notice 2021-51, the Internal Revenue Service announced that it intends to amend the Treasury regulations to defer the applicability date for withholding on a transfer of an interest in a publicly traded partnership to January 1, 2023. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

ITEM 5.    OTHER INFORMATION

On November 3, 2021, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to thirty-five (35) cargoes to be scheduled for delivery in the 2022 Contract Year at a price equal to 115% of Henry Hub plus $1.92 per MMBtu.

40

ITEM 6.    EXHIBITS

Exhibit No.	Description
4.1	Sixth Supplemental Indenture, dated as of September 27, 2021, 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 27, 2021)
10.1*	Change orders 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-00049 COVID-19 Impacts 2Q2021, dated July 6, 2021, (ii) CO-00050 Third Berth Bunkering Ship Modifications — Pre-Investment for Foundations, dated July 6, 2021, (iii) CO-00051 Thermal Oxidizer Controls Change, dated September 8, 2021, (iv) CO-00052 Third Berth Spare Beacon and Additional Cable Tray, dated September 8, 2021 and (v) CO-00053 Train 6 Gearbox Assembly Replacement for Unit 1411, dated September 24, 2021
10.2*	First Amendment to Third Amended and Restated Common Terms Agreement, dated as of July 26, 2021, among SPL, as borrower, the Secured Debt Holder Group Representatives party thereto, the Secured Hedge Representatives party thereto, the Secured Gas Hedge Representatives party thereto and Société Générale, as the Common Security Trustee and the Intercreditor Agent
10.3*	Letter agreement, dated November 3, 2021, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between SPL and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)
10.4	Registration Rights Agreement, dated as of September 27, 2021, 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 27, 2021)
22.1*	List of Issuers and Guarantor Subsidiaries
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*	Filed herewith.
**	Furnished herewith.

41

SIGNATURES

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

		CHENIERE ENERGY PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC, its general partner
Date:	November 3, 2021	By:	/s/ Zach Davis
			Zach Davis
			Senior Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	November 3, 2021	By:	/s/ Leonard E. Travis
			Leonard E. Travis
			Senior Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

42

EX-10.1

Exhibit 10.1

CHANGE ORDER

COVID-19 Impacts 2Q2021

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-00049 DATE OF CHANGE ORDER: July 6, 2021

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

1.Pursuant to Article 6.2 of the Agreement (Change Orders Requested by Contractor), Parties agree this Change Order includes Contractor’s costs for the second quarter of 2021 (“Q2”) (actuals through April 2021 and forecasted costs through June 2021), in response to the novel coronavirus (COVID-19) outbreak event.

This Change Order is based on the following assumptions and qualifications for Q2:

i.Contractor’s Houston home office personnel have worked and shall continue working effectively remotely or in the Houston home office.

ii.Contractor has been able to keep the Jobsite open throughout the event and shall continue doing so, to the extent reasonably possible, to advance the Work at the current rate of progress (or better if possible), with no planned shutdown in Q2.

iii.Contractor shall continue to put forth diligent mitigation efforts to minimize impacts caused by the event to the extent reasonably practical, including but not limited to: increased craft professional hours for additional cleaning, disinfecting, etc.; increased bussing services to support social distancing; additional cleaning stations, waste management services, etc.; quarantine requirements for supplier technical support (international and others); continued COVID-19 testing costs and hours (excluding quarantine time); increased professional staff for contact tracing efforts; and additional safety PPE, communication materials (e.g., posters, signs, etc.).

iv.No major COVID-19 infection outbreak on the Jobsite resulting in: (i) Site shutdown of all or critical scopes of the Work; or (ii) absenteeism at or above the twenty percent (20%) level for a sustained duration of more than four (4) Weeks. Should either of these triggers occur, the Parties shall jointly collaborate on mitigation actions and plans for shutdown accordingly.

v.Existing government (local, state and/or federal) guidelines, executive orders, actions or directives as of 9 March 2021 shall remain unchanged through the end of Q2. New government orders shall be subject to separate notices and Change Orders, if applicable.

vi.Owner’s operations and other professional staff personnel shall continue to support the Contractor’s activities for the Project in support of the Work.

vii.Subcontractors and Suppliers shall continue to provide uninterrupted support for construction activities either at Site or remotely if possible.

viii.Any changes in the above assumptions and qualifications and additional costs beyond Q2 are excluded from this Change Order; and may be part of a separate Change Order in accordance with Article 6.2 of the Agreement.

2.Contractor has not experienced schedule impacts on the critical path of the CPM Schedule through 15 May 2021; and should all the qualifications and assumptions above remain as stated, Contractor does not anticipate any schedule impacts to the Project on the critical path of the CPM Schedule through Q2. In the event of the occurrence of any impacts to the critical path of the CPM Schedule, Contractor shall notify Owner in accordance with Article 6.5 of the Agreement.

3.The detailed cost breakdown of this Change Order is provided in Exhibit A of this Change Order.

4.Schedule C-3 (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 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 (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-48)	$	15,549,729
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,032,442,302
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	2,256,901
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,034,699,203

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44)	$	(4,939,146)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	452,756,854
10.	The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
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	$	452,756,854

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)	$	2,485,199,156
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	2,256,901
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,487,456,057

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): Yes; see Exhibit B of this Change Order.

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 following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): 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: 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/ KM 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/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
July 12, 2021	July 6, 2021
Date of Signing	Date of Signing

CHANGE ORDER

Third Berth Bunkering Ship Modifications - Pre-Investment for Foundations

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-00050 DATE OF CHANGE ORDER: July 6, 2021

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

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), and pursuant to Owner’s request via Letter No. SPL4-BE-C20-055, dated 12 November 2020, and Contractor’s Third Berth Bunkering Study Class 3 Estimate provided via Letter No. 26012-100-T21-GAM-00026, dated 2 April 2021, the Parties agree this Change Order includes Contractor’s engineering, procurement and construction costs to proceed with Pre-Investment of Foundations for an additional Gangway Tower, new Hydraulic Power Unit (“HPU”) and Bunker Arm Vapor Line pedestals as further described in Section 5.0 of Contractor’s Third Berth Bunkering Study Report No. 26012-100-G65-GEX-00001, Rev 00A, dated 31 March 2021.

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

3.Schedule C-3 (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 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 (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49)	$	17,806,630
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,034,699,203
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 in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,034,699,203

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, & 25-27, 30-31, 33, 36-37, 39-40, 43-44)	$	(4,939,146)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	452,756,854
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	371,193
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	$	453,128,047

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)	$	2,487,456,057
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	371,193
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,487,827,250

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 following dates are modified: N/A

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

Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B of this Change Order.

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

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: 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/ KM 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/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
July 12, 2021	July 6, 2021
Date of Signing	Date of Signing

CHANGE ORDER

Thermal Oxidizer Controls Change

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-00051 DATE OF CHANGE ORDER: September 8, 2021

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

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor's engineering costs to implement two (2) design changes to the Thermal Oxidizer System controls scheme for Train 6 (MOC #M2020778-001 & MOC #M2021544-001).

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

3.Schedule C-3 (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 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 (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49)	$	17,806,630
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,034,699,203
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	40,306
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,034,739,509

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50)	$	(4,567,953)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	453,128,047
10.	The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
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	$	453,128,047

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)....................................................	$	2,487,827,250
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	40,306
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,487,867,556

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): 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 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 following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): 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: 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/ KM 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/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
September 16, 2021	September 8, 2021
Date of Signing	Date of Signing

CHANGE ORDER

Third Berth Spare Beacon and Additional Cable Tray

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-00052 DATE OF CHANGE ORDER: September 8, 2021

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

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s procurement and construction costs to procure, supply and pre-assemble a spare beacon structure for the Third Berth Project.

2.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s engineering, procurement, and construction costs to install a new six (6) inch wide cable tray on the existing pipe rack to support installation of the new 5kV cable for the Third Berth Project.

3. The detailed cost breakdown for this Change Order is detailed in Exhibits A.1 and A.2 of this Change Order.

4. Schedule C-3 (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 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 (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49, 51)	$	17,846,936
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,034,739,509
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 in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,034,739,509

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50)	$	(4,567,953)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	453,128,047
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	589,417
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	$	453,717,464

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)....................................................	$	2,487,867,556
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	589,417
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,488,456,973

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 following dates are modified: N/A

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

Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B of this Change Order.

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

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: 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/ KM 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/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Project Manager
Title	Title
September 16, 2021	September 8, 2021
Date of Signing	Date of Signing

CHANGE ORDER

Train 6 Gearbox Assembly Replacement for Unit 1411

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-00053 DATE OF CHANGE ORDER: September 24, 2021

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

1.Contractor acknowledges that one(1) gearbox assembly (identified as "PROPANE COMPRESSOR ASSEMBLY GEARBOX; 46C-1411-GB02 GEARBOX; PN: NF2419E; S/N: YH00156; GE NUOVO PIGNONE/LUFKIN") procured by Contractor for Subproject 6(a), which is part of compressor number 46C-1411 ("Compressor"), requires repair before it can be incorporated into Subproject 6(a) ("Original Gearbox Assembly").

2.Contractor states that the repair of the Original Gearbox Assembly and subsequent installation of the repaired Original Gearbox Assembly into Subproject 6(a) may delay the achievement of Substantial Completion. To mitigate this delay, Contractor has requested Owner provide the following capital spare parts from the Stage 4 Liquefaction Facility: (a) one (1) low speed shaft and gear set, (b) one (1) high speed pinion, and (c) four (4) tilting pad bearings and other various operating spare parts to be installed in the Compressor (subclauses (a), (b), (c) and the operating spare parts together, the "Replacement Parts").

3.Owner has no obligation to provide the Replacement Parts to Contractor. Notwithstanding the foregoing, Owner agrees to make the Replacement Parts available to Contractor for the purpose of Contractor installing such Replacement Parts into Subproject 6(a) (in lieu of installing the Original Gearbox Assembly) based on the conditions stated in this Change Order.

4.Contractor shall, for all Replacement Parts provided by Owner procure for Owner equivalent replacement or refurbished (as needed) parts in condition equivalent to condition of the Replacement Parts and meeting all requirements under the Agreement (including Article 12) ("New Parts") and shall deliver the New Parts to a storage location designated by Owner. Contractor shall use commercially reasonable efforts to make such delivery on or before [28JAN2022] (the "Delivery Date". Contractor shall also provide to Owner a schedule for the procurement and delivery of the New Parts, which schedule shall account for the delivery of all New Parts to Owner on or before the Delivery Date. Once approved in writing by Owner (such approval not to be unreasonably withheld), Contractor shall procure and deliver the New Parts in accordance with such approved schedule. Notwithstanding the foregoing, any written request by Owner Representative to maintain or improve upon such schedule shall be implemented by Contractor unless otherwise agreed in writing between David Craft of Owner and Kane McIntosh of Contractor.

5.Contractor shall bear all costs and expenses in relation to repair, restoration, delivery, transportation, installation, uninstallation, removal, return and storage of, or any other services for, the Original Gearbox Assembly, the Replacement Parts, the New Parts and Contractor's performance of its obligations under this Change Order.

6.In the event Owner sustains a failure of any gearbox comparable to the Original Gearbox Assembly or any spare parts comparable to any Replacement Part currently in operation in the Stage 1 Liquefaction Facility, the Stage 2 Liquefaction Facility or the Stage 3 Liquefaction Facility (each individually, "such other Liquefaction Facility") prior to Owner receiving the New Parts, Contractor shall return and, if applicable, uninstall, the such Replacement Part to Owner for use in such other Liquefaction Facility, and Contractor shall not be entitled to any Change Order under the Agreement in connection with the return and, if applicable, the uninstallation, of the Replacement Parts, including no adjustment to the Guaranteed Substantial Completion Date.

7.THE PARTIES AGREE THAT (I) OWNER PROVIDES AND CONTRACTOR SHALL ACCEPT ALL REPLACEMENT PARTS "AS- IS" WITH ANY AND ALL DEFECTS (IF ANY), INCLUDING LATENT DEFECTS; (II) ANY USE OF ANY REPLACEMENT PARTS BY CONTRACTOR, INCLUDING CONTRACTOR'S INCORPORATION OF ANY REPLACEMENT PARTS INTO SUBPROJECT 6(a), SHALL BE AT CONTRACTOR'S SOLE RISK AND SHALL NOT RELIEVE CONTRACTOR OF ANY OF ITS OBLIGATIONS UNDER THE AGREEMENT (INCLUDING ACHIEVING THE GUARANTEED SUBSTANTIAL COMPLETION DATE, THE MAC AND PERFORMANCE GUARANTEE IN ACCORDANCE WITH THE AGREEMENT); AND (III) OWNER HEREBY DISCLAIMS ANY AND ALL WARRANTIES RELATING TO ALL REPLACEMENT PARTS, INCLUDING THE IMPLIED WARRANTY OF MERCHANTABILITY AND IMPLIED WARRANTY OF FITNESS FOR A

PARTICULAR PURPOSE. After installation of any Replacement Parts into the Stage 4 Liquefaction Facility, Article 12 of the Agreement (including the warranty obligations) shall apply to the Replacement Parts as if the Replacement Parts were provided by Contractor under 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 (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41-42, 45-49, 51)	$	17,846,936
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,034,739,509
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 in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,034,739,509

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50, 52)	$	(3,978,536)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	453,717,464
10.	The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
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	$	453,717,464

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)....................................................	$	2,488,456,973
15.	The Contract Price will be unchanged by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	—
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,488,456,973

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 following dates are modified: N/A

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

Select either A or B:

Other adjustments to liability or obligation of Contractor or Owner under the Agreement; 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/ KM 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/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Project Manager
Title	Title
September 29, 2021	September 27, 2021
Date of Signing	Date of Signing

EX-10.2

Exhibit 10.2

FIRST AMENDMENT TO THIRD AMENDED AND RESTATED COMMON TERMS AGREEMENT

This First Amendment to Third Amended and Restated Common Terms Agreement (this “Amendment”), dated as of July 26, 2021 amends the Third Amended and Restated Common Terms Agreement, dated as of March 19, 2020 (as it may be further amended, restated, supplemented or otherwise modified from time to time prior to this Amendment, the “Common Terms Agreement”), by and among Sabine Pass Liquefaction, LLC, a Delaware limited liability company (the “Borrower”), the Subsidiaries of the Borrower from time to time party thereto, Société Générale, as the Common Security Trustee (in such capacity, the “Common Security Trustee”) and as the Intercreditor Agent (in such capacity, the “Intercreditor Agent”), the Secured Debt Holder Group Representatives, the Secured Hedge Representatives and the Secured Gas Hedge Representatives party thereto from time to time. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Common Terms Agreement.

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

WHEREAS, the Secured Debt Holder Group Representative for the Working Capital Debt, the Common Security Trustee, the Intercreditor Agent and the Required Lenders are willing to amend the Common Terms Agreement as set forth in Section 1 herein.

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

Section 1.Amendment to the Common Terms Agreement. Pursuant to Section 5.1 of the Common Terms Agreement and Section 4.1(i) of the Intercreditor Agreement, each of the Borrower, the Common Security Trustee, the Intercreditor Agent and the Secured Debt Holder Group Representative for the Working Capital Debt hereby consents to the following amendment:

1.1    The definition of “Permitted Hedging Agreement” in Schedule 1 of the Common Terms Agreement is hereby amended to delete the stricken text (indicated textually in the same manner as the following example: stricken text) and to add the double-underlined text (indicated textually in the same manner as the following example: double-underlined text) as set forth below:

“Permitted Hedging Agreement” means any:

(a)    Interest Rate Protection Agreements;

(b)    the following gas hedging contracts:

1

(i)    Futures Contracts, Fixed-Float Futures Swaps, NYMEX Natural Gas Futures Contracts and Swing Swaps for gas hedging purposes for up to a maximum of 78 TBtu of gas utilizing intra-month and up to three prompt month contracts;

(ii)    Index Swaps for gas hedging purposes for up to a maximum of 74.4 TBtu per month of gas utilizing up to three twenty four prompt month contracts; and

(iii)    Basis Swaps for gas hedging purposes for up to a maximum of (a) 74.4 TBtu per month for Basis Swaps with a tenor up to 24 months and (b) 30.0 TBtu for Basis Swaps with a tenor greater than 24 months but less than 36 months. For the avoidance of doubt, Basis Swaps with a tenor of more than 36 months are prohibited. Further, the aggregate notional volume of financial natural gas positions in Basis Swaps may not exceed that of physical natural gas positions on an MMBtu basis.

1.2    The Common Terms Agreement as amended by this Section 1 is referred to

herein as the “Amended Common Terms Agreement”.

Section 2.    Effectiveness. This Amendment shall become effective as of the date

hereof upon the satisfaction of the following condition precedent: this Amendment shall have been executed by the Common Security Trustee and the Common Security Trustee shall have received counterparts of this Amendment executed by each of (a) the Borrower, (b) the Intercreditor Agent, (c) the Secured Debt Holder Group Representative for the Working Capital Debt (who constitutes the Majority Aggregate Secured Credit Facilities Debt Participants (as defined in the Intercreditor Agreement)) and (d) the Lenders constituting the Required Lenders under the Working Capital Facility Agreement.

Section 3.    Representations and Warranties. The Borrower hereby represents and warrants to the Lenders that:

3.1    no Default or Event of Default has occurred and is continuing as of the date

hereof or will result from the consummation of the transactions contemplated by the Amendment; and

3.2    each of the representations and warranties of the Borrower in the Financing

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

Section 4.    Financing Document. This Amendment constitutes a Financing Document as such term is defined in, and for purposes of, the Amended Common Terms Agreement.

2

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

Section 6.    Headings. All headings in this Amendment are included only for convenience and ease of reference and shall not be considered in the construction and interpretation of any provision hereof.

Section 7.    Binding Nature and Benefit. This Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted assigns.

Section 8.    Counterparts; Electronic Execution. This Amendment may be executed in multiple counterparts, each of which shall be deemed an original for all purposes, but all of which together shall constitute one and the same instrument. Delivery of an executed counterpart of a signature page of this Amendment by facsimile or portable document format (“pdf”) shall be effective as delivery of a manually executed counterpart of this Amendment. The words “execution,” “execute”, “signed,” “signature,” and words of like import in or related to any document to be signed in connection with this Amendment and the transactions contemplated hereby shall be deemed to include electronic signatures, the electronic matching of assignment terms and contract formations on electronic platforms approved by the Common Security Trustee, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.

Section 9.    No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Common Terms Agreement shall continue unchanged and shall remain in full force and effect. Each amendment granted herein shall apply solely to the matters set forth herein and such amendment shall not be deemed or construed as an amendment of any other matters, nor shall such amendment apply to any other matters.

Section 10.    Direction to Secured Debt Holder Group Representative, Intercreditor Agent and Common Security Trustee.

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

(b)    based on the instructions above, the Secured Debt Holder Group Representative for the Working Capital Debt, constituting the Majority Aggregate Secured Credit Facilities Debt Participants (as defined in the Intercreditor

3

Agreement), hereby directs the Intercreditor Agent to (i) execute this Amendment and (ii) direct the Common Security Trustee to execute this Amendment; and

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

[Remainder of the page left intentionally blank.]

4

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

SABINE PASS LIQUEFACTION, LLC,

as the Borrower

By:	/s/ Lisa C. Cohen
	Name:	Lisa C. Cohen
	Title:	Treasurer

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

SOCIÉTÉ GÉNÉRALE,

as Common Security Trustee and Secured

Debt Holder Group Representative for the

Commercial Banks Facility

By:	/s/ Karla Navas
	Name:	Karla Navas
	Title:	Vice President

SOCIÉTÉ GÉNÉRALE,

as the Intercreditor Agent

By:	/s/ Karla Navas
	Name:	Karla Navas
	Title:	Vice President

SOCIÉTÉ GÉNÉRALE,

as a Lender

By:	/s/ Karla Navas
	Name:	Karla Navas
	Title:	Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

THE BANK OF NOVA SCOTIA,

as the Secured Debt Holder Group Representative for the Working Capital Debt

By:	/s/ Joe Lattanzi
	Name:	Joe Lattanzi
	Title:	Managing Director

THE BANK OF NOVA SCOTIA, HOUSTON BRANCH

as an Issuing Bank, the Swing Line Lender and a Lender

By:	/s/ Joe Lattanzi
	Name:	Joe Lattanzi
	Title:	Managing Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

ABN AMRO CAPITAL USA LLC,

as a Lender

By:	/s/ Darrell Holley
	Name:	Darrell Holley
	Title:	Managing Director

By:	/s/ Matt Worstell
	Name:	Matt Wortsell
	Title:	Executive Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

BANCO BILBAO VIZCAYA

ARGENTARIA, S.A. NEW YORK

BRANCH,

as a Lender

By:	/s/ Cara Younger
	Name:	Cara Younger
	Title:	Executive Director

By:	/s/ Miriam Trautmann
	Name:	Miriam Trautmann
	Title:	Senior Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

BANK OF CHINA, NEW YORK

BRANCH

as a Lender

By:	/s/ Raymond Qiao
	Name:	Raymond Qiao
	Title:	Executive Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

CITIBANK, N.A.,

as a Lender

By:	/s/ Catherine Shepherd
	Name:	Catherine Shepherd
	Title:	Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

HSBC BANK USA, NATIONAL ASSOCIATION,

as a Lender and an Issuing Bank

By:	/s/ Balaji Rajgopal
	Name:	Balaji Rajgopal
	Title:	Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

INDUSTRIAL AND COMMERCIAL BANK

OF CHINA LIMITED, NEW YORK BRANCH, as a Lender

By:	/s/ Michael Merrow
	Name:	Michael Merrow
	Title:	Vice President

By:	/s/ Michael Fabisiak
	Name:	Michael Fabisiak
	Title:	Head of Project Finance

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

ING CAPITAL LLC,

as a Lender and an Issuing Bank

By:	/s/ Subha Pasumarti
	Name:	Subha Pasumarti
	Title:	Managing Director

By:	/s/ Gabriel D’Huart
	Name:	Gabriel D’Huart
	Title:	Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

INTESA SANPAOLO S.P.A., NEW YORK BRANCH,

as a Lender

By:	/s/ Fuensanta Diaz Cobacho
	Name:	Fuensanta Diaz Cobacho
	Title:	Managing Director

By:	/s/ Nicholas A. Matacchieri
	Name:	Nicholas A. Matacchieri
	Title:	Managing Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

MIZUHO BANK, LTD.,

as Lender

By:	/s/ Edward Sacks
	Name:	Edward Sacks
	Title:	Executive Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

MUFG BANK, LTD.,

as a Lender

By:	/s/ Saad Iqbal
	Name:	Saad Iqbal
	Title:	Managing Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

NATIONAL AUSTRALIA BANK LIMITED,

as a Lender

By:	/s/ Eli Davis
	Name:	Eli Davis
	Title:	Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

NATIXIS, NEW YORK BRANCH,

as Lender and Issuing Bank

By:	/s/ Anthony Perna
	Name:	Anthony Perna
	Title:	Director

By:	/s/ Jonathan Cohen
	Name:	Jonathan Cohen
	Title:	Executive

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

BANCO DE SABADELL, S.A., MIAMI BRANCH,

as a Lender

By:	/s/ Ignacio Alcaraz
	Name:	Ignacio Alcaraz
	Title:	Head of Structured Finance Americas

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

BANCO SANTANDER, S.A., NEW YORK BRANCH,

as a Lender

By:	/s/ Daniel S. Kostman
	Name:	Daniel S. Kostman
	Title:	Executive Director

By:	/s/ Robert Cestari
	Name:	Robert Cestari
	Title:	Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

STANDARD CHARTERED BANK,

as a Lender

By:	/s/ Mr. Sridhar Nagarajan
	Name:	Mr. Sridhar Nagarajan
	Title:	Regional Head, Project and Export Finance, Europe and Americas

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

SUMITOMO MITSUI BANKING CORPORATION,

as a Lender

By:	/s/ Juan Kreutz
	Name:	Juan Kreutz
	Title:	Managing Director

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

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

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as a Lender and an Issuing Bank

By:	/s/ Borden Tennant
	Name:	Borden Tennant
	Title:	Vice President

SIGNATURE PAGE TO FIRST AMENDMENT TO THIRD A&R COMMON TERMS AGREEMENT (SPL)

EX-10.3

Exhibit 10.3

Sabine Pass Liquefaction, LLC

November 3, 2021

Cheniere Marketing International LLP

3rd Floor, The Zig Zag Building

70 Victoria Street

London SW1E 6SQ, United Kingdom

Attn: Commercial Operations

Re:Letter Agreement regarding the Base SPA (“Letter Agreement”)

Dear Sir or Madam:

The Parties have entered into that certain Amended and Restated LNG Sale and Purchase Agreement (FOB) dated August 5, 2014 between Sabine Pass Liquefaction, LLC and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC) (as amended and assigned, the “Base SPA”).Capitalized terms used but not defined herein shall have the meanings given them in the Base SPA. This Letter Agreement sets forth the terms of certain sales and purchases of LNG under the Base SPA.

The Parties hereby agree that, notwithstanding Section 9.2 and subject to Section 14 of the Base SPA, the FPC (expressed in USD per MMBtu) applicable to up to thirty-five (35) cargoes scheduled for delivery in Contract Year 2022 shall equal USD one decimal nine two per MMBtu (US$1.92/MMBtu).

Please indicate Buyer’s agreement with the terms of this Letter Agreement by executing a copy of this Letter Agreement where indicated below and returning it to Seller.

Sincerely,

Sabine Pass Liquefaction, LLC

By:	/s/ Zach Davis
	Zach Davis
	Chief Financial Officer

Accepted and Agreed:

Cheniere Marketing International LLP
acting by its managing member, Cheniere Marketing, LLC
By:	/s/ Anatol Feygin
	Anatol Feygin
	Executive Vice President and Chief Commercial Officer

700 Milam Street, Suite 1900, Houston, Texas 77002

+1 713-375-5000

EX-22.1

Exhibit 22.1

Cheniere Energy Partners, L.P.

List of Issuers and Guarantor Subsidiaries

The following entities are guarantors of the 5.625% Senior Notes due 2026, 4.500% Senior Notes due 2029, 4.000% Senior Notes due 2031 and 3.250% Senior Notes due 2032 issued by Cheniere Energy Partners, L.P.

Entity	Jurisdiction of Organization	Role
Cheniere Energy Partners, L.P.	Delaware	Issuer
Cheniere Energy Investments, LLC	Delaware	Guarantor
Sabine Pass LNG-GP, LLC	Delaware	Guarantor
Sabine Pass LNG, L.P.	Delaware	Guarantor
Sabine Pass Tug Services, LLC	Delaware	Guarantor
Cheniere Pipeline GP Interests, LLC	Delaware	Guarantor
Cheniere Creole Trail Pipeline, L.P.	Delaware	Guarantor

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 (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

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

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

Date: November 3, 2021

/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, Zach Davis, 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 (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

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

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

Date: November 3, 2021

/s/ Zach Davis

Zach Davis

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, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: November 3, 2021

/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, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Zach Davis, Chief Financial Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

Date: November 3, 2021

/s/ Zach Davis

Zach Davis

Chief Financial Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2021	Oct. 29, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2021
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 Units, Units Outstanding		484,025,623
Entity Central Index Key	0001383650
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q3

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Revenues
Revenues		$ 2,324	$ 982	$ 6,176	$ 4,170
Revenues from contracts with customers		2,324	975	6,176	4,167
Operating costs and expenses
Cost of sales (excluding items shown separately below)		1,342	454	3,178	1,551
Cost of sales—affiliate		8	33	62	38
Cost of sales—related party		0	0	1	0
Operating and maintenance expense		148	146	465	463
Operating and maintenance expense—affiliate		34	34	103	115
Operating and maintenance expense—related party		12	0	34	0
Development expense		0	0	1	0
General and administrative expense		2	2	7	12
General and administrative expense—affiliate		22	24	64	73
Depreciation and amortization expense		140	137	417	413
Impairment expense and loss on disposal of assets		0	0	6	5
Total operating costs and expenses		1,708	830	4,338	2,670
Income from operations		616	152	1,838	1,500
Other income (expense)
Interest expense, net of capitalized interest		(210)	(221)	(636)	(691)
Loss on modification or extinguishment of debt		(27)	0	(81)	(43)
Other income, net		2	2	2	8
Total other expense		(235)	(219)	(715)	(726)
Net income (loss)		$ 381	$ (67)	$ 1,123	$ 774
Basic and diluted net income (loss) per common unit		$ 0.69	$ (0.08)	$ 2.07	$ 1.55
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation		484.0	414.8	484.0	370.9
LNG [Member]
Revenues
Revenues		$ 1,791	$ 807	$ 5,057	$ 3,588
Revenues from contracts with customers	[1]	1,791	800	5,057	3,585
LNG—affiliate [Member]
Revenues
Revenues from contracts with customers		453	103	878	352
Regasification [Member]
Revenues
Revenues from contracts with customers		68	67	202	202
Other [Member]
Revenues
Revenues from contracts with customers		$ 12	$ 5	$ 39	$ 28

[1] LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three and nine months ended September 30, 2020, we recognized $109 million and $513 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $21 million would have been recognized subsequent to September 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million that would have otherwise been recognized during the period if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the three and nine months ended September 30, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

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Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents	$ 1,713	$ 1,210
Restricted cash	133	97
Accounts and other receivables, net of current expected credit losses	358	318
Accounts receivable—affiliate	198	184
Advances to affiliate	130	144
Inventory	134	107
Current derivative assets	44	14
Other current assets	105	61
Total current assets	2,815	2,135
Property, plant and equipment, net of accumulated depreciation	16,820	16,723
Operating lease assets, net of accumulated amortization	93	99
Debt issuance costs, net of accumulated amortization	13	17
Derivative assets	25	11
Other non-current assets, net	163	160
Total assets	19,929	19,145
Current liabilities
Accounts payable	14	12
Accrued liabilities	846	658
Accrued liabilities—related party	5	4
Current debt, net of discount and debt issuance costs	944	0
Due to affiliates	45	53
Deferred revenue	166	137
Deferred revenue—affiliate	4	1
Current operating lease liabilities	8	7
Current derivative liabilities	23	11
Total current liabilities	2,055	883
Long-term debt, net of premium, discount and debt issuance costs	17,171	17,580
Non-current deferred revenue	1	0
Operating lease liabilities	85	90
Derivative liabilities	13	35
Other non-current liabilities	0	1
Other non-current liabilities—affiliate	15	17
Partners’ equity
Common unitholders’ interest (484.0 million units issued and outstanding at both September 30, 2021 and December 31, 2020)	856	714
General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2021 and December 31, 2020)	(267)	(175)
Total partners’ equity	589	539
Total liabilities and partners’ equity	$ 19,929	$ 19,145

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Consolidated Balance Sheets Parentheticals - shares shares in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Cheniere Partners [Member]
General Partner Ownership Interest Percentage	2.00%	2.00%
Common Units [Member]
Limited Partners' Capital Account, Units Issued	484.0	484.0
Limited Partners' Capital Account, Units Outstanding	484.0	484.0
General Partner [Member]
General Partners' Capital Account, Units Issued	9.9	9.9
General Partners' Capital Account, Units Outstanding	9.9	9.9

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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, 2019		348.6	135.4
Partners' equity, beginning of period at Dec. 31, 2019	$ 715	$ 1,792	$ (996)	$ (81)
General partner units, Outstanding, beginning of period at Dec. 31, 2019				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	435	307	119	$ 9
Distributions		$ (220)	$ (85)	(25)
Units, Outstanding, end of period at Mar. 31, 2020		348.6	135.4
Partners' equity, end of period at Mar. 31, 2020	820	$ 1,879	$ (962)	$ (97)
General partner units, Outstanding, end of period at Mar. 31, 2020				9.9
Units, Outstanding, beginning of period at Dec. 31, 2019		348.6	135.4
Partners' equity, beginning of period at Dec. 31, 2019	715	$ 1,792	$ (996)	$ (81)
General partner units, Outstanding, beginning of period at Dec. 31, 2019				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	774
Units, Outstanding, end of period at Sep. 30, 2020		484.0	0.0
Partners' equity, end of period at Sep. 30, 2020	478	$ 627	$ 0	$ (149)
General partner units, Outstanding, end of period at Sep. 30, 2020				9.9
Units, Outstanding, beginning of period at Mar. 31, 2020		348.6	135.4
Partners' equity, beginning of period at Mar. 31, 2020	820	$ 1,879	$ (962)	$ (97)
General partner units, Outstanding, beginning of period at Mar. 31, 2020				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	406	287	111	$ 8
Distributions		$ (223)	$ (86)	(29)
Units, Outstanding, end of period at Jun. 30, 2020		348.6	135.4
Partners' equity, end of period at Jun. 30, 2020	888	$ 1,943	$ (937)	$ (118)
General partner units, Outstanding, end of period at Jun. 30, 2020				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	(67)	$ (65)	$ (1)	$ (1)
Conversion of subordinated units into common units, units		135.4	(135.4)
Conversion of subordinated units into common units	0	$ (1,026)	$ 1,026	0
Distributions		$ (225)	$ (88)	(30)
Units, Outstanding, end of period at Sep. 30, 2020		484.0	0.0
Partners' equity, end of period at Sep. 30, 2020	478	$ 627	$ 0	$ (149)
General partner units, Outstanding, end of period at Sep. 30, 2020				9.9
Units, Outstanding, beginning of period at Dec. 31, 2020		484.0	0.0
Partners' equity, beginning of period at Dec. 31, 2020	539	$ 714	$ 0	$ (175)
General partner units, Outstanding, beginning of period at Dec. 31, 2020				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	347	340	$ 0	$ 7
Distributions		$ (316)		(35)
Units, Outstanding, end of period at Mar. 31, 2021		484.0	0.0
Partners' equity, end of period at Mar. 31, 2021	535	$ 738	$ 0	$ (203)
General partner units, Outstanding, end of period at Mar. 31, 2021				9.9
Units, Outstanding, beginning of period at Dec. 31, 2020		484.0	0.0
Partners' equity, beginning of period at Dec. 31, 2020	539	$ 714	$ 0	$ (175)
General partner units, Outstanding, beginning of period at Dec. 31, 2020				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	1,123
Units, Outstanding, end of period at Sep. 30, 2021		484.0	0.0
Partners' equity, end of period at Sep. 30, 2021	589	$ 856	$ 0	$ (267)
General partner units, Outstanding, end of period at Sep. 30, 2021				9.9
Units, Outstanding, beginning of period at Mar. 31, 2021		484.0	0.0
Partners' equity, beginning of period at Mar. 31, 2021	535	$ 738	$ 0	$ (203)
General partner units, Outstanding, beginning of period at Mar. 31, 2021				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	395	387	$ 0	$ 8
Distributions		$ (320)		(39)
Units, Outstanding, end of period at Jun. 30, 2021		484.0	0.0
Partners' equity, end of period at Jun. 30, 2021	571	$ 805	$ 0	$ (234)
General partner units, Outstanding, end of period at Jun. 30, 2021				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	381	373	$ 0	$ 8
Distributions		$ (322)		(41)
Units, Outstanding, end of period at Sep. 30, 2021		484.0	0.0
Partners' equity, end of period at Sep. 30, 2021	$ 589	$ 856	$ 0	$ (267)
General partner units, Outstanding, end of period at Sep. 30, 2021				9.9

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Consolidated Statements of Partners' Equity Parentheticals - $ / shares	3 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020
Common Units [Member]
Distributions Paid, Per Unit	$ 0.665	$ 0.660	$ 0.655	$ 0.645	$ 0.640	$ 0.630
Subordinated Units [Member]
Distributions Paid, Per Unit				$ 0.645	$ 0.640	$ 0.630

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Cash flows from operating activities
Net income	$ 1,123	$ 774
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	417	413
Amortization of debt issuance costs, premium and discount	22	24
Loss on modification or extinguishment of debt	81	43
Total losses (gains) on derivatives, net	(64)	38
Net cash provided by (used for) settlement of derivative instruments	10	(2)
Impairment expense and loss on disposal of assets	6	5
Other	13	10
Changes in operating assets and liabilities:
Accounts and other receivables, net of current expected credit losses	(41)	93
Accounts receivable—affiliate	(13)	23
Advances to affiliate	11	31
Inventory	(26)	2
Accounts payable and accrued liabilities	165	(96)
Accrued liabilities—related party	1	2
Due to affiliates	(6)	(3)
Deferred revenue	29	24
Other, net	(62)	(45)
Other, net—affiliate	1	(3)
Net cash provided by operating activities	1,667	1,333
Cash flows from investing activities
Property, plant and equipment	(495)	(795)
Net cash used in investing activities	(495)	(795)
Cash flows from financing activities
Proceeds from issuances of debt	2,700	1,995
Repayments of debt	(2,172)	(2,000)
Debt issuance and other financing costs	(35)	(34)
Debt extinguishment costs	(61)	(39)
Distributions to owners	(1,073)	(1,011)
Other	8	0
Net cash used in financing activities	(633)	(1,089)
Net increase (decrease) in cash, cash equivalents and restricted cash	539	(551)
Cash, cash equivalents and restricted cash—beginning of period	1,307	1,962
Cash, cash equivalents and restricted cash—end of period	$ 1,846	$ 1,411

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Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 1,713	$ 1,210
Restricted cash	133	97
Total cash, cash equivalents and restricted cash	$ 1,846	$ 1,307	$ 1,411	$ 1,962

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Nature of Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, and has natural gas liquefaction facilities consisting of five operational natural gas liquefaction Trains and one additional Train that is undergoing commissioning and expected to be substantially completed in the first quarter of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG terminal also has operational regasification facilities that include five LNG storage tanks, vaporizers and two marine berths, with an additional marine berth that is under construction. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”).

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 fiscal year ended December 31, 2020.

Results of operations for the three and nine months ended September 30, 2021 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2021.

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. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

Recent Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

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Unitholders' Equity

9 Months Ended

Sep. 30, 2021

Partners' Capital Notes [Abstract]

Unitholders' Equity

UNITHOLDERS’ EQUITY

The common 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.

Although common unitholders are not obligated to fund losses of the Partnership, its capital account, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continues 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 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, 2021, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.4% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of The Blackstone Group Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 8.0% by the public. All of our 2% general partner interest was held by Cheniere. CQP Target Holdco’s equity interests are 50.00% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone and 50.00% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

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Restricted Cash

9 Months Ended

Sep. 30, 2021

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, 2021 and December 31, 2020, we had $133 million and $97 million of restricted cash, respectively.

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

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Accounts and Other Receivables, Net of Current Expected Credit Losses

9 Months Ended

Sep. 30, 2021

Receivables [Abstract]

Accounts and Other Receivables, Net of Current Expected Credit Losses

ACCOUNTS AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

As of September 30, 2021 and December 31, 2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
SPL trade receivable	$	338	$	300
Other accounts receivable	20		18
Total accounts and other receivables, net of current expected credit losses	$	358	$	318

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Inventory

9 Months Ended

Sep. 30, 2021

Inventory Disclosure [Abstract]

Inventory

INVENTORY

As of September 30, 2021 and December 31, 2020, inventory consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Materials	$	83	$	81
LNG	33		8
Natural gas	16		17
Other	2		1
Total inventory	$	134	$	107

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Property, Plant and Equipment, Net of Accumulated Depreciation

9 Months Ended

Sep. 30, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

As of September 30, 2021 and December 31, 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
LNG terminal
LNG terminal and interconnecting pipeline facilities	$	16,950	$	16,908
LNG terminal construction-in-process	2,623		2,154
Accumulated depreciation	(2,757)		(2,344)
Total LNG terminal, net of accumulated depreciation	16,816		16,718
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(24)
Total fixed assets, net of accumulated depreciation	4		5
Property, plant and equipment, net of accumulated depreciation	$	16,820	$	16,723

The following table shows depreciation expense during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Depreciation expense	$	139	$	135	$	414	$	409

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Derivative Instruments

9 Months Ended

Sep. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, 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 Operations to the extent not utilized for the commissioning process, in which case it is capitalized.

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, 2021 and December 31, 2020 (in millions):

	Fair Value Measurements as of
	September 30, 2021								December 31, 2020
	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)	$	(18)	$	(8)	$	59	$	33	$	1	$	(1)	$	(21)	$	(21)

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, 2021 and December 31, 2020, 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 incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

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 prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2021:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$59	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.333) - $0.415 / $0.015

(1)Unobservable inputs were weighted by the relative fair value of the instruments.

Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.

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, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Balance, beginning of period	$	33	$	51	$	(21)	$	24
Realized and mark-to-market gains (losses):
Included in cost of sales	25		(47)		79		(22)
Purchases and settlements:
Purchases	4		5		6		4
Settlements	(3)		(8)		(5)		(6)
Transfers out of Level 3, net (1)	—		(1)		—		—
Balance, end of period	$	59	$	—	$	59	$	—
Change in unrealized gains (losses) relating to instruments still held at end of period	$	25	$	(47)	$	79	$	(22)

(1)Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty on a net basis. 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 any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

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 remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.

The notional natural gas position of our Liquefaction Supply Derivatives was approximately 5,135 TBtu and 4,970 TBtu as of September 30, 2021 and December 31, 2020, respectively, of which 99 TBtu and 91 TBtu, respectively, were for a natural gas supply contract that SPL has with a related party.

Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets

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 Sheets Location	September 30, 2021		December 31, 2020
Current derivative assets	$	44	$	14
Derivative assets	25		11
Total derivative assets	69		25
Current derivative liabilities	(23)		(11)
Derivative liabilities	(13)		(35)
Total derivative liabilities	(36)		(46)
Derivative asset (liability), net	$	33	$	(21)

(1)Does not include collateral posted with counterparties by us of $29 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both September 30, 2021 and December 31, 2020.

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues	$	—	$	7	$	—	$	3
Cost of sales	10		(74)		64		(41)

(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 Sheets 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):

	Liquefaction Supply Derivatives
As of September 30, 2021
Gross assets	$	76
Offsetting amounts	(7)
Net assets	$	69
Gross liabilities	$	(43)
Offsetting amounts	7
Net liabilities	$	(36)
As of December 31, 2020
Gross assets	$	69
Offsetting amounts	(44)
Net assets	$	25
Gross liabilities	$	(48)
Offsetting amounts	2
Net liabilities	$	(46)

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Accrued Liabilities

9 Months Ended

Sep. 30, 2021

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

As of September 30, 2021 and December 31, 2020, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Interest costs and related debt fees	$	209	$	203
Accrued natural gas purchases	523		374
LNG terminal and related pipeline costs	87		71
Other accrued liabilities	27		10
Total accrued liabilities	$	846	$	658

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Debt

9 Months Ended

Sep. 30, 2021

Debt Disclosure [Abstract]

Debt

DEBT

As of September 30, 2021 and December 31, 2020, our debt consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 SPL Working Capital Facility”) (1)	$	13,128	$	13,650
Cheniere Partners — 3.250% to 5.625% senior notes due between October 2025 and January 2032 and credit facilities (“2019 CQP Credit Facilities”)	4,200		4,100
Unamortized premium, discount and debt issuance costs, net of accumulated amortization	(157)		(170)
Total long-term debt, net of premium, discount and debt issuance costs	17,171		17,580
Current debt:
SPL — current portion of 6.25% senior secured notes due March 2022 (the “2022 SPL Senior Notes”) (1) (2)	522		—
Cheniere Partners — current portion of 5.625% senior notes due October 2026 (the “2026 CQP Senior Notes”) (3)	428		—
Unamortized discount and debt issuance costs, net of accumulated amortization	(6)		—
Total current debt, net of discount and debt issuance costs	944		—
Total debt, net of premium, discount and debt issuance costs	$	18,115	$	17,580

(1)A portion of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected series of sales of approximately $482 million aggregate principal amount of senior secured notes due 2037 pursuant to executed note purchase agreements, expected to be issued in the fourth quarter of 2021, subject to customary closing conditions, will be used to strategically refinance a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses.

(2)In October 2021, $318 million of the 2022 SPL Senior Notes was redeemed with $100 million of the proceeds from our issuance of the 3.250% senior notes due 2032 (the “2032 CQP Senior Notes”) and $218 million of cash on hand. See Issuances and Redemptions section below for further discussion.

(3)In October 2021, we redeemed the remaining outstanding aggregate principal amount of the 2026 CQP Senior Notes that were not purchased pursuant to the tender offer and consent solicitation in September 2021. See Issuances and Redemptions section below for further discussion.

Issuances and Redemptions

The following table shows the issuances and redemptions of long-term debt during the nine months ended September 30, 2021 (in millions), excluding intra-quarter borrowings and repayments:

Issuances	Principal Amount Issued
Three Months Ended March 31, 2021
Cheniere Partners — 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) (1)	$	1,500
Three Months Ended September 30, 2021
Cheniere Partners — 2032 CQP Senior Notes (2)	1,200
Nine Months Ended September 30, 2021 total	$	2,700
Redemptions	Principal Amount Redeemed
Three Months Ended March 31, 2021
Cheniere Partners — 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) (1)	$	1,500
Three Months Ended September 30, 2021
Cheniere Partners — 2026 CQP Senior Notes (2)	672
Nine Months Ended September 30, 2021 total	$	2,172

(1)Net proceeds from the issuance of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in $54 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

(2)Net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem a portion of the 2026 CQP Senior Notes in September 2021 pursuant to the tender offer and consent solicitation, resulting in $27 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs. In October 2021, the remaining net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem the remaining outstanding principal amount of the 2026 CQP Senior Notes and, together with cash on hand, redeem $318 million of the 2022 SPL Senior Notes.

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2021 (in millions):

	2020 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	396		—
Available commitment	$	804	$	750
Priority ranking	Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Weighted average interest rate of outstanding balance	n/a		n/a
Maturity date	March 19, 2025		May 29, 2024

(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

Restrictive Debt Covenants

The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain investments or pay dividends or distributions.

As of September 30, 2021, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Total interest cost	$	244	$	246	$	732	$	759
Capitalized interest	(34)		(25)		(96)		(68)
Total interest expense, net of capitalized interest	$	210	$	221	$	636	$	691

Fair Value Disclosures

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

	September 30, 2021				December 31, 2020
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	17,478	$	19,231	$	16,950	$	19,113
Senior notes — Level 3 (2)	800		997		800		1,036
Credit facilities — Level 3 (3)	—		—		—		—

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

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

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

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Revenues from Contracts with Customers

9 Months Ended

Sep. 30, 2021

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, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues (1)	$	1,791	$	800	$	5,057	$	3,585
LNG revenues—affiliate	453		103		878		352
Regasification revenues	68		67		202		202
Other revenues	12		5		39		28
Total revenues from customers	2,324		975		6,176		4,167
Net derivative loss (2)	—		7		—		3
Total revenues	$	2,324	$	982	$	6,176	$	4,170

(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three and nine months ended September 30, 2020, we recognized $109 million and $513 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $21 million would have

been recognized subsequent to September 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million that would have otherwise been recognized during the period if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the three and nine months ended September 30, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

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

Contract Assets

The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	September 30,		December 31,
	2021		2020
Contract assets, net of current expected credit losses	$	1	$	—

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the nine months ended September 30, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

Deferred Revenue Reconciliation

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

	Nine Months Ended September 30, 2021
Deferred revenue, beginning of period	$	137
Cash received but not yet recognized in revenue	166
Revenue recognized from prior period deferral	(137)
Deferred revenue, end of period	$	166

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

	Nine Months Ended September 30, 2021
Deferred revenue—affiliate, beginning of period	$	1
Cash received but not yet recognized in revenue	4
Revenue recognized from prior period deferral	(1)
Deferred revenue—affiliate, end of period	$	4

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, 2021 and December 31, 2020:

	September 30, 2021			December 31, 2020
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	50.1	9	$	52.1	9
LNG revenues—affiliate	0.7		3	0.1		1
Regasification revenues	1.9		4	2.1		5
Total revenues	$	52.7		$	54.3

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

We 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)The table above excludes substantially all variable consideration under our SPAs and TUAs. 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 amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 63% and 39% of our LNG revenues from contracts included in the table above during the three months ended September 30, 2021 and 2020, respectively, and approximately 56% and 37% of our LNG revenues from contracts included in the table above during the nine months ended September 30, 2021 and 2020, respectively, were related to variable consideration received from customers. Approximately 96% and 94% of our LNG revenues—affiliate from contracts included in the table above during the three and nine months ended September 30, 2021, respectively, and 100% of our LNG revenues—affiliate from contracts included in the table above during each of the three and nine months ended September 30, 2020 were related to variable consideration received from customers. During each of the three and nine months ended September 30, 2021, approximately 5% of our regasification revenues were related to variable consideration received from customers, respectively, and during each of the three and nine months ended September 30, 2020, approximately 6% of our regasification revenues were related to variable consideration received from customers.

We may enter 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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Related Party Transactions

9 Months Ended

Sep. 30, 2021

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 Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues—affiliate
Cheniere Marketing Agreements	$	441	$	87	$	860	$	328
Contracts for Sale and Purchase of Natural Gas and LNG	12		16		18		24
Total LNG revenues—affiliate	453		103		878		352
Cost of sales—affiliate
Cheniere Marketing Agreements	—		32		34		32
Contracts for Sale and Purchase of Natural Gas and LNG	8		1		28		6
Total cost of sales—affiliate	8		33		62		38
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	—		—		1		—
Operating and maintenance expense—affiliate
Services Agreements	34		34		103		115
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		—		34		—
General and administrative expense—affiliate
Services Agreements	22		24		64		73

As of September 30, 2021 and December 31, 2020, we had $198 million and $184 million, respectively, of accounts receivable—affiliate under the agreements described below.

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. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project.

Cheniere Marketing Letter Agreements

In August 2021, SPL and Cheniere Marketing entered into a letter agreement (amending and restating the previous letter agreement between the parties from February 2021) for the sale of up to 81 cargoes to be delivered between 2021 and 2027 at a price equal to 115% of Henry Hub plus $1.96 per MMBtu. Additionally, SPL and Cheniere Marketing entered into a letter agreement for the sale of (1) up to six cargoes to be delivered in 2022 and up to six cargoes to be delivered in 2023 at a price equal to 115% of Henry Hub plus $1.768 per MMBtu; and (2) up to six cargoes to be delivered in 2022 at a price equal to 115% of Henry Hub plus $1.952 per MMBtu.

In December 2020, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu.

In December 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes that were delivered in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.

Facility Swap Agreement

In August 2020, SPL entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.

Natural Gas Transportation and Storage Agreements

SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by Brookfield, who indirectly acquired a portion of our limited partner interests in September 2020 through its purchase of a portion of CQP Target Holdco’s equity interests. We recorded operating and maintenance expense—related party of $12 million and $34 million and cost of sales—related party of zero and $1 million during the three and nine months ended September 30, 2021, respectively, and accrued liabilities—related party of $5 million and $4 million as of September 30, 2021 and December 31, 2020, respectively, with this related party.

Services Agreements

As of September 30, 2021 and December 31, 2020, we had $130 million and $144 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 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.

CTPL MSA

CTPL has a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the operations and business of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations, providing contract administration services for all contracts associated with the Creole Trail Pipeline and obtaining insurance. CTPL is required to reimburse Cheniere Terminals for the aggregate of all costs and expenses incurred in the course of performing the services under the CTPL MSA.

Natural Gas Supply Agreement

SPL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party is partially owned by Blackstone, who also partially owns our limited partner interests. The term of the agreement is for five years, which can commence no earlier than November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions precedent.

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 advanced payments of annual ad valorem taxes 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 shall grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal as early as 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 the dollar-for-dollar credit applied to the ad valorem tax levied against the Sabine Pass LNG terminal in the given year.

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 $2 million in due to affiliates as of both September 30, 2021 and December 31, 2020 and $15 million and $17 million of other non-current liabilities—affiliate as of September 30, 2021 and December 31, 2020, respectively, from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

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

SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with Cheniere Terminals 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 Cheniere Terminals a portion of its future revenues. Accordingly, Tug Services distributed $2 million and $1 million during the three months ended September 30, 2021 and 2020, respectively, and $6 million and

$4 million during the nine months ended September 30, 2021 and 2020, respectively, to Cheniere Terminals, 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, 2021 and 2020.

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 and Cheniere has not demanded any such payments from SPLNG under the agreement. 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 and Cheniere has not demanded any such payments from SPL under the agreement. 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 and Cheniere has not demanded any such payments from CTPL under the agreement. The agreement is effective for tax returns due on or after May 2013.

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Net Income (Loss) per Common Unit

9 Months Ended

Sep. 30, 2021

Earnings Per Share [Abstract]

Net Income (Loss) per Common Unit

NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statements of Partners’ Equity. On October 26, 2021, we declared a $0.680 distribution per common unit and the related distribution to our general partner and IDR holders that will be paid on November 12, 2021 to unitholders of record as of November 5, 2021 for the period from July 1, 2021 to September 30, 2021.

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

			Limited Partner Units
	Total		Common Units		Subordinated Units		General Partner Units		IDR
Three Months Ended September 30, 2021
Net income	$	381
Declared distributions	375		329		—		8		38
Assumed allocation of undistributed net income (1)	$	6	6		—		—		—
Assumed allocation of net income			$	335	$	—	$	8	$	38
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	0.69	$	—
Three Months Ended September 30, 2020
Net loss	$	(67)
Declared distributions	346		315		—		6		25
Assumed allocation of undistributed net loss (1)	$	(413)	(347)		(58)		(8)		—
Assumed allocation of net loss			$	(32)	$	(58)	$	(2)	$	25
Weighted average units outstanding			414.8		69.2
Basic and diluted net loss per unit			$	(0.08)	$	(0.84)
Nine Months Ended September 30, 2021
Net income	$	1,123
Declared distributions	1,091		970		—		22		99
Assumed allocation of undistributed net income (1)	$	32	31		—		1		—
Assumed allocation of net income			$	1,001	$	—	$	23	$	99
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	2.07	$	—
Nine Months Ended September 30, 2020
Net income	$	774
Declared distributions	1,024		763		174		20		67
Assumed allocation of undistributed net loss (1)	$	(250)	(188)		(57)		(5)		—
Assumed allocation of net income			$	575	$	117	$	15	$	67
Weighted average units outstanding			370.9		113.1
Basic and diluted net income per unit			$	1.55	$	1.03

(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).

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Customer Concentration

9 Months Ended

Sep. 30, 2021

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivable, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivable, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2021	2020	2021	2020	2021	2020
Customer A	20%	*	24%	22%	26%	31%
Customer B	17%	14%	16%	15%	18%	21%
Customer C	18%	26%	18%	18%	17%	*
Customer D	19%	22%	17%	18%	17%	22%
Customer E	11%	*	11%	12%	*	*

* Less than 10%

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2021

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,
	2021		2020
Cash paid during the period for interest on debt, net of amounts capitalized	$	601	$	636

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $233 million as of both September 30, 2021 and 2020, respectively.

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Nature of Operations and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2021

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 fiscal year ended December 31, 2020.

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. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

Recent Accounting Standards

Recent Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

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Accounts and Other Receivables, Net of Current Expected Credit Losses (Tables)

9 Months Ended

Sep. 30, 2021

Receivables [Abstract]

Schedule of Accounts and Other Receivables, Net of Current Expected Credit Losses

As of September 30, 2021 and December 31, 2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
SPL trade receivable	$	338	$	300
Other accounts receivable	20		18
Total accounts and other receivables, net of current expected credit losses	$	358	$	318

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Inventory (Tables)

9 Months Ended

Sep. 30, 2021

Inventory Disclosure [Abstract]

Schedule of Inventory

As of September 30, 2021 and December 31, 2020, inventory consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Materials	$	83	$	81
LNG	33		8
Natural gas	16		17
Other	2		1
Total inventory	$	134	$	107

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Property, Plant and Equipment, Net of Accumulated Depreciation (Tables)

9 Months Ended

Sep. 30, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

As of September 30, 2021 and December 31, 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
LNG terminal
LNG terminal and interconnecting pipeline facilities	$	16,950	$	16,908
LNG terminal construction-in-process	2,623		2,154
Accumulated depreciation	(2,757)		(2,344)
Total LNG terminal, net of accumulated depreciation	16,816		16,718
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(24)
Total fixed assets, net of accumulated depreciation	4		5
Property, plant and equipment, net of accumulated depreciation	$	16,820	$	16,723

Schedule of Depreciation and Offsets to LNG Terminal Costs

The following table shows depreciation expense during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Depreciation expense	$	139	$	135	$	414	$	409

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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, 2021 and December 31, 2020 (in millions):

	Fair Value Measurements as of
	September 30, 2021								December 31, 2020
	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)	$	(18)	$	(8)	$	59	$	33	$	1	$	(1)	$	(21)	$	(21)

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, 2021:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$59	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.333) - $0.415 / $0.015

(1)Unobservable inputs were weighted by the relative fair value of the instruments.

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, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Balance, beginning of period	$	33	$	51	$	(21)	$	24
Realized and mark-to-market gains (losses):
Included in cost of sales	25		(47)		79		(22)
Purchases and settlements:
Purchases	4		5		6		4
Settlements	(3)		(8)		(5)		(6)
Transfers out of Level 3, net (1)	—		(1)		—		—
Balance, end of period	$	59	$	—	$	59	$	—
Change in unrealized gains (losses) relating to instruments still held at end of period	$	25	$	(47)	$	79	$	(22)

(1)Transferred into Level 3 as a result of unobservable market, or out of Level 3 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 Sheets Location	September 30, 2021		December 31, 2020
Current derivative assets	$	44	$	14
Derivative assets	25		11
Total derivative assets	69		25
Current derivative liabilities	(23)		(11)
Derivative liabilities	(13)		(35)
Total derivative liabilities	(36)		(46)
Derivative asset (liability), net	$	33	$	(21)

(1)Does not include collateral posted with counterparties by us of $29 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both September 30, 2021 and December 31, 2020.

Derivative Instruments, Gain (Loss)

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues	$	—	$	7	$	—	$	3
Cost of sales	10		(74)		64		(41)

(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.

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):

	Liquefaction Supply Derivatives
As of September 30, 2021
Gross assets	$	76
Offsetting amounts	(7)
Net assets	$	69
Gross liabilities	$	(43)
Offsetting amounts	7
Net liabilities	$	(36)
As of December 31, 2020
Gross assets	$	69
Offsetting amounts	(44)
Net assets	$	25
Gross liabilities	$	(48)
Offsetting amounts	2
Net liabilities	$	(46)

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Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2021

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

As of September 30, 2021 and December 31, 2020, accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Interest costs and related debt fees	$	209	$	203
Accrued natural gas purchases	523		374
LNG terminal and related pipeline costs	87		71
Other accrued liabilities	27		10
Total accrued liabilities	$	846	$	658

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Debt (Tables)

9 Months Ended

Sep. 30, 2021

Debt Disclosure [Abstract]

Schedule of Debt Instruments

As of September 30, 2021 and December 31, 2020, our debt consisted of the following (in millions):

	September 30,		December 31,
	2021		2020
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 SPL Working Capital Facility”) (1)	$	13,128	$	13,650
Cheniere Partners — 3.250% to 5.625% senior notes due between October 2025 and January 2032 and credit facilities (“2019 CQP Credit Facilities”)	4,200		4,100
Unamortized premium, discount and debt issuance costs, net of accumulated amortization	(157)		(170)
Total long-term debt, net of premium, discount and debt issuance costs	17,171		17,580
Current debt:
SPL — current portion of 6.25% senior secured notes due March 2022 (the “2022 SPL Senior Notes”) (1) (2)	522		—
Cheniere Partners — current portion of 5.625% senior notes due October 2026 (the “2026 CQP Senior Notes”) (3)	428		—
Unamortized discount and debt issuance costs, net of accumulated amortization	(6)		—
Total current debt, net of discount and debt issuance costs	944		—
Total debt, net of premium, discount and debt issuance costs	$	18,115	$	17,580

(1)A portion of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected series of sales of approximately $482 million aggregate principal amount of senior secured notes due 2037 pursuant to executed note purchase agreements, expected to be issued in the fourth quarter of 2021, subject to customary closing conditions, will be used to strategically refinance a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses.

(2)In October 2021, $318 million of the 2022 SPL Senior Notes was redeemed with $100 million of the proceeds from our issuance of the 3.250% senior notes due 2032 (the “2032 CQP Senior Notes”) and $218 million of cash on hand. See Issuances and Redemptions section below for further discussion.

(3)In October 2021, we redeemed the remaining outstanding aggregate principal amount of the 2026 CQP Senior Notes that were not purchased pursuant to the tender offer and consent solicitation in September 2021. See Issuances and Redemptions section below for further discussion.

Schedule of Debt Issuances And Redemptions

The following table shows the issuances and redemptions of long-term debt during the nine months ended September 30, 2021 (in millions), excluding intra-quarter borrowings and repayments:

Issuances	Principal Amount Issued
Three Months Ended March 31, 2021
Cheniere Partners — 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) (1)	$	1,500
Three Months Ended September 30, 2021
Cheniere Partners — 2032 CQP Senior Notes (2)	1,200
Nine Months Ended September 30, 2021 total	$	2,700
Redemptions	Principal Amount Redeemed
Three Months Ended March 31, 2021
Cheniere Partners — 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) (1)	$	1,500
Three Months Ended September 30, 2021
Cheniere Partners — 2026 CQP Senior Notes (2)	672
Nine Months Ended September 30, 2021 total	$	2,172

(1)Net proceeds from the issuance of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in $54 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

(2)Net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem a portion of the 2026 CQP Senior Notes in September 2021 pursuant to the tender offer and consent solicitation, resulting in $27 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs. In October 2021, the remaining net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem the remaining outstanding principal amount of the 2026 CQP Senior Notes and, together with cash on hand, redeem $318 million of the 2022 SPL Senior Notes.

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2021 (in millions):

	2020 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	396		—
Available commitment	$	804	$	750
Priority ranking	Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Weighted average interest rate of outstanding balance	n/a		n/a
Maturity date	March 19, 2025		May 29, 2024

(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

Schedule of Interest Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Total interest cost	$	244	$	246	$	732	$	759
Capitalized interest	(34)		(25)		(96)		(68)
Total interest expense, net of capitalized interest	$	210	$	221	$	636	$	691

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	September 30, 2021				December 31, 2020
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	17,478	$	19,231	$	16,950	$	19,113
Senior notes — Level 3 (2)	800		997		800		1,036
Credit facilities — Level 3 (3)	—		—		—		—

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

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

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

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Revenues from Contracts with Customers (Tables)

9 Months Ended

Sep. 30, 2021

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, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues (1)	$	1,791	$	800	$	5,057	$	3,585
LNG revenues—affiliate	453		103		878		352
Regasification revenues	68		67		202		202
Other revenues	12		5		39		28
Total revenues from customers	2,324		975		6,176		4,167
Net derivative loss (2)	—		7		—		3
Total revenues	$	2,324	$	982	$	6,176	$	4,170

(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three and nine months ended September 30, 2020, we recognized $109 million and $513 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $21 million would have

been recognized subsequent to September 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million that would have otherwise been recognized during the period if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the three and nine months ended September 30, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.(2)See Note 7—Derivative Instruments for additional information about our derivatives.

Contract with Customer, Asset

The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	September 30,		December 31,
	2021		2020
Contract assets, net of current expected credit losses	$	1	$	—

Contract Balances Reconciliation

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

	Nine Months Ended September 30, 2021
Deferred revenue, beginning of period	$	137
Cash received but not yet recognized in revenue	166
Revenue recognized from prior period deferral	(137)
Deferred revenue, end of period	$	166

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

	Nine Months Ended September 30, 2021
Deferred revenue—affiliate, beginning of period	$	1
Cash received but not yet recognized in revenue	4
Revenue recognized from prior period deferral	(1)
Deferred revenue—affiliate, end of period	$	4

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, 2021 and December 31, 2020:

	September 30, 2021			December 31, 2020
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	50.1	9	$	52.1	9
LNG revenues—affiliate	0.7		3	0.1		1
Regasification revenues	1.9		4	2.1		5
Total revenues	$	52.7		$	54.3

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

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2021

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 Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
LNG revenues—affiliate
Cheniere Marketing Agreements	$	441	$	87	$	860	$	328
Contracts for Sale and Purchase of Natural Gas and LNG	12		16		18		24
Total LNG revenues—affiliate	453		103		878		352
Cost of sales—affiliate
Cheniere Marketing Agreements	—		32		34		32
Contracts for Sale and Purchase of Natural Gas and LNG	8		1		28		6
Total cost of sales—affiliate	8		33		62		38
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	—		—		1		—
Operating and maintenance expense—affiliate
Services Agreements	34		34		103		115
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		—		34		—
General and administrative expense—affiliate
Services Agreements	22		24		64		73

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Net Income (Loss) per Common Unit (Tables)

9 Months Ended

Sep. 30, 2021

Earnings Per Share [Abstract]

Schedule of Net Income per Common Unit

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

			Limited Partner Units
	Total		Common Units		Subordinated Units		General Partner Units		IDR
Three Months Ended September 30, 2021
Net income	$	381
Declared distributions	375		329		—		8		38
Assumed allocation of undistributed net income (1)	$	6	6		—		—		—
Assumed allocation of net income			$	335	$	—	$	8	$	38
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	0.69	$	—
Three Months Ended September 30, 2020
Net loss	$	(67)
Declared distributions	346		315		—		6		25
Assumed allocation of undistributed net loss (1)	$	(413)	(347)		(58)		(8)		—
Assumed allocation of net loss			$	(32)	$	(58)	$	(2)	$	25
Weighted average units outstanding			414.8		69.2
Basic and diluted net loss per unit			$	(0.08)	$	(0.84)
Nine Months Ended September 30, 2021
Net income	$	1,123
Declared distributions	1,091		970		—		22		99
Assumed allocation of undistributed net income (1)	$	32	31		—		1		—
Assumed allocation of net income			$	1,001	$	—	$	23	$	99
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	2.07	$	—
Nine Months Ended September 30, 2020
Net income	$	774
Declared distributions	1,024		763		174		20		67
Assumed allocation of undistributed net loss (1)	$	(250)	(188)		(57)		(5)		—
Assumed allocation of net income			$	575	$	117	$	15	$	67
Weighted average units outstanding			370.9		113.1
Basic and diluted net income per unit			$	1.55	$	1.03

(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).

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Customer Concentration (Tables)

9 Months Ended

Sep. 30, 2021

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivable, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivable, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2021	2020	2021	2020	2021	2020
Customer A	20%	*	24%	22%	26%	31%
Customer B	17%	14%	16%	15%	18%	21%
Customer C	18%	26%	18%	18%	17%	*
Customer D	19%	22%	17%	18%	17%	22%
Customer E	11%	*	11%	12%	*	*

* Less than 10%

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2021

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,
	2021		2020
Cash paid during the period for interest on debt, net of amounts capitalized	$	601	$	636

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Nature of Operations and Basis of Presentation (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($) item milliontonnes / yr unit mi trains	Sep. 30, 2020 USD ($)
Nature of Operations and Basis of Presentation [Line Items]
Income Tax Expense (Benefit) | $	$ 0	$ 0
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains Operating | trains	5
Number of Liquefaction LNG Trains Commissioning | trains	1
Total Production Capability | milliontonnes / yr	30
Number Of LNG Storage Tanks | unit	5
Number of Marine Berths Operating | item	2
Number of Marine Berths Constructing | item	1
Creole Trail Pipeline [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length of Natural Gas Pipeline | mi	94

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Unitholders' Equity (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Maximum [Member]
Other Ownership Interests [Line Items]
Number of days after quarter end distribution is paid	45 days
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 Partners [Member]
Other Ownership Interests [Line Items]
General Partner Ownership Interest Percentage	2.00%	2.00%
Cheniere [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	48.60%
General Partner Ownership Interest Percentage	100.00%
CQP Target Holdco LLC and Other Blackstone and Brookfield Affiliates [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	41.40%
Public [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	8.00%
BIP Chinook Holdco LLC [Member] | CQP Target Holdco LLC [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	50.00%
BIF IV Cypress Aggregator (Delaware) LLC [Member] | CQP Target Holdco LLC [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	50.00%

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Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 133	$ 97
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 133	$ 97

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Accounts and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Receivables [Abstract]
SPL trade receivable	$ 338	$ 300
Other accounts receivable	20	18
Total accounts and other receivables, net of current expected credit losses	$ 358	$ 318

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Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Inventory [Line Items]
Inventory	$ 134	$ 107
Materials [Member]
Inventory [Line Items]
Inventory	83	81
LNG [Member]
Inventory [Line Items]
Inventory	33	8
Natural gas [Member]
Inventory [Line Items]
Inventory	16	17
Other [Member]
Inventory [Line Items]
Inventory	$ 2	$ 1

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 16,820	$ 16,723
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(2,757)	(2,344)
Property, plant and equipment, net of accumulated depreciation	16,816	16,718
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	16,950	16,908
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,623	2,154
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	30	29
Accumulated depreciation	(26)	(24)
Property, plant and equipment, net of accumulated depreciation	$ 4	$ 5

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 139	$ 135	$ 414	$ 409

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Derivative Instruments - Narrative (Details) - tbtu	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	5,135	4,970
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	10 years
Financial Liquefaction Supply Derivatives | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	3 years
SPL [Member] | Natural Gas Supply Agreement [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	99	91

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 33	$ (21)
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	(18)	1
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	(8)	(1)
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	$ 59	$ (21)

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - USD ($)		9 Months Ended
		Sep. 30, 2021	Dec. 31, 2020
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		$ 33,000,000	$ (21,000,000)
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		59,000,000	$ (21,000,000)
Physical Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		59,000,000
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	(1.333)
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	0.415
Physical Liquefaction Supply Derivatives [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	$ 0.015

[1] Unobservable inputs were weighted by the relative fair value of the instruments.

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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, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ 33	$ 51	$ (21)	$ 24
Realized and mark-to-market gains (losses):
Included in cost of sales		25	(47)	79	(22)
Purchases and settlements:
Purchases		4	5	6	4
Settlements		(3)	(8)	(5)	(6)
Transfers out of Level 3, net	[1]	0	(1)	0	0
Balance, end of period		59	0	59	0
Change in unrealized gains (losses) relating to instruments still held at end of period		$ 25	$ (47)	$ 79	$ (22)

[1] Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Sep. 30, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Current derivative assets		$ 44	$ 14
Derivative assets		25	11
Total derivative assets	[1]	69	25
Current derivative liabilities		(23)	(11)
Derivative liabilities		(13)	(35)
Total derivative liabilities	[1]	(36)	(46)
Derivative asset (liability), net	[1]	33	(21)
Derivative, collateral posted by us		29	4
Natural Gas Supply Agreement [Member]
Derivatives, Fair Value [Line Items]
Derivative asset (liability), net		0	0
Current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[1]	44	14
Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	25	11
Current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities	[1]	(23)	(11)
Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	$ (13)	$ (35)

[1] Does not include collateral posted with counterparties by us of $29 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both September 30, 2021 and December 31, 2020.

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2021	Sep. 30, 2019	Sep. 30, 2021	Sep. 30, 2020
LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 0	$ 7	$ 0	$ 3
Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 10	$ (74)	$ 64	$ (41)

[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 - Balance Sheet Presentation Table (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 33	$ (21)
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	76	69
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(7)	(44)
Derivative Assets (Liabilities), at Fair Value, Net	69	25
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(43)	(48)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	7	2
Derivative Assets (Liabilities), at Fair Value, Net	$ (36)	$ (46)

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Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 209	$ 203
Accrued natural gas purchases	523	374
LNG terminal and related pipeline costs	87	71
Other accrued liabilities	27	10
Total accrued liabilities	$ 846	$ 658

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions		1 Months Ended	9 Months Ended
		Oct. 31, 2021	Sep. 30, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-term Debt, Net of Premium, Discount and Debt Issuance Costs			$ 17,171	$ 17,580
Total Current Debt, Net of Discount and Debt Issuance Costs			944	0
Total Debt, Net of Premium, Discount and Debt Issuance Costs			18,115	17,580
Repayments of Long-term Debt			2,172
Long-term Debt [Member]
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net			(157)	(170)
Current Debt [Member]
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net			(6)	0
2022 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Current portion of senior secured notes	[1],[2]		$ 522	0
Debt Instrument, Interest Rate, Stated Percentage			6.25%
2022 SPL Senior Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 318
2022 SPL Senior Notes [Member] | Subsequent Event [Member] | Proceeds of 2032 CQP Senior Notes
Debt Instrument [Line Items]
Repayments of Long-term Debt		100
2022 SPL Senior Notes [Member] | Subsequent Event [Member] | Cash
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 218
2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Current portion of senior secured notes	[3]		$ 428	0
Debt Instrument, Interest Rate, Stated Percentage			5.625%
2037 Private Placement Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 482
SPL [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[2]		$ 13,128	13,650
SPL [Member] | Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.20%
SPL [Member] | Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.25%
Cheniere Partners [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 4,200	$ 4,100
Cheniere Partners [Member] | Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			3.25%
Cheniere Partners [Member] | Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			5.625%
Cheniere Partners [Member] | 2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	[4]		$ 672
Cheniere Partners [Member] | 2032 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			3.25%

[1] In October 2021, $318 million of the 2022 SPL Senior Notes was redeemed with $100 million of the proceeds from our issuance of the 3.250% senior notes due 2032 (the “2032 CQP Senior Notes”) and $218 million of cash on hand. See Issuances and Redemptions section below for further discussion.

[2] A portion of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected series of sales of approximately $482 million aggregate principal amount of senior secured notes due 2037 pursuant to executed note purchase agreements, expected to be issued in the fourth quarter of 2021, subject to customary closing conditions, will be used to strategically refinance a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses.

[3] In October 2021, we redeemed the remaining outstanding aggregate principal amount of the 2026 CQP Senior Notes that were not purchased pursuant to the tender offer and consent solicitation in September 2021. See Issuances and Redemptions section below for further discussion.

[4] Net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem a portion of the 2026 CQP Senior Notes in September 2021 pursuant to the tender offer and consent solicitation, resulting in $27 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs. In October 2021, the remaining net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem the remaining outstanding principal amount of the 2026 CQP Senior Notes and, together with cash on hand, redeem $318 million of the 2022 SPL Senior Notes.

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Debt - Schedule of Issuances and Redemptions (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended			9 Months Ended
		Oct. 31, 2021	Sep. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt						$ 2,700
Repayments of Long-term Debt						2,172
Loss on modification or extinguishment of debt			$ 27		$ 0	$ 81	$ 43
2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			5.625%			5.625%
2022 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.25%			6.25%
2022 SPL Senior Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 318
Cheniere Partners [Member] | 2031 CQP Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.00%			4.00%
Proceeds from Issuance of Long-term Debt	[1]			$ 1,500
Cheniere Partners [Member] | 2032 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			3.25%			3.25%
Proceeds from Issuance of Long-term Debt	[2]		$ 1,200
Cheniere Partners [Member] | 2025 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			5.25%			5.25%
Repayments of Long-term Debt	[1]					$ 1,500
Loss on modification or extinguishment of debt						54
Cheniere Partners [Member] | 2026 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	[2]					672
Loss on modification or extinguishment of debt						$ 27

[1] Net proceeds from the issuance of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in $54 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

[2] Net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem a portion of the 2026 CQP Senior Notes in September 2021 pursuant to the tender offer and consent solicitation, resulting in $27 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs. In October 2021, the remaining net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem the remaining outstanding principal amount of the 2026 CQP Senior Notes and, together with cash on hand, redeem $318 million of the 2022 SPL Senior Notes.

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Debt - Credit Facilities Table (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($) Rate
2020 SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	$ 1,200	[1]
Outstanding balance	0	[1]
Commitments prepaid or terminated	0	[1]
Letters of credit issued	396	[1]
Available commitment	$ 804	[1]
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Debt Instrument, Maturity Date	Mar. 19, 2025	[1]
2020 SPL Working Capital Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%
2020 SPL Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%
2020 SPL Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.125%
2020 SPL Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.75%
2020 SPL Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.125%
2020 SPL Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.75%
2019 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Original facility size	$ 1,500
Outstanding balance	0
Commitments prepaid or terminated	750
Letters of credit issued	0
Available commitment	$ 750
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Debt Instrument, Maturity Date	May 29, 2024
2019 CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.25%
2019 CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	2.125%
2019 CQP Credit Facilities [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.25%
2019 CQP Credit Facilities [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.125%

[1] The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Debt Disclosure [Abstract]
Total interest cost	$ 244	$ 246	$ 732	$ 759
Capitalized interest	(34)	(25)	(96)	(68)
Total interest expense, net of capitalized interest	$ 210	$ 221	$ 636	$ 691

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 18,115	$ 17,580
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	17,478	16,950
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	800	800
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	19,231	19,113
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	997	1,036
Credit facilities [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [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, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[3]	$ 0	$ 0

[1] The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

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

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

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Revenues from Contracts with Customers - Narrative (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	63.00%	39.00%	56.00%	37.00%
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	5.00%	6.00%	5.00%	6.00%
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	96.00%	100.00%	94.00%	100.00%

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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, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 2,324	$ 975	$ 6,176	$ 4,167
Net derivative loss	[1]	0	7	0	3
Total revenues		2,324	982	6,176	4,170
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	[2]	1,791	800	5,057	3,585
Total revenues		1,791	807	5,057	3,588
Suspension Fees and LNG Cover Damages Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		0	109	0	513
Suspension Fees and LNG Cover Damages Revenue [Member] | Subsequent Period
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			21		21
Suspension Fees and LNG Cover Damages Revenue [Member] | Current Period
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			244
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		453	103	878	352
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		68	67	202	202
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 12	$ 5	$ 39	$ 28

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

[2] LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three and nine months ended September 30, 2020, we recognized $109 million and $513 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $21 million would have been recognized subsequent to September 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million that would have otherwise been recognized during the period if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the three and nine months ended September 30, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

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Revenues from Contracts with Customers - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 1	$ 0
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	137
Cash received but not yet recognized in revenue	166
Revenue recognized from prior period deferral	(137)
Deferred revenues, end of period	166
Deferred revenue—affiliate, beginning of period	1
Cash received but not yet recognized in revenue	4
Revenue recognized from prior period deferral	(1)
Deferred revenue—affiliate, end of period	$ 4

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Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Sep. 30, 2021	Dec. 31, 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 54.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 52.7
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 52.1
Weighted Average Recognition Timing	[1]		9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 50.1
Weighted Average Recognition Timing	[1]	9 years
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 0.1
Weighted Average Recognition Timing	[1]		1 year
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 0.7
Weighted Average Recognition Timing	[1]	3 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 2.1
Weighted Average Recognition Timing	[1]		5 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 1.9
Weighted Average Recognition Timing	[1]	4 years

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

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 453	$ 103	$ 878	$ 352
Cost of sales—affiliate	8	33	62	38
Cost of sales—related party	0	0	1	0
Operating and maintenance expense—affiliate	34	34	103	115
Operating and maintenance expense—related party	12	0	34	0
General and administrative expense—affiliate	22	24	64	73
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	441	87	860	328
Cost of sales—affiliate	0	32	34	32
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	12	16	18	24
Cost of sales—affiliate	8	1	28	6
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	34	34	103	115
General and administrative expense—affiliate	22	24	64	73
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Cost of sales—related party	0	0	1	0
Operating and maintenance expense—related party	$ 12	$ 0	$ 34	$ 0

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Related Party Transactions - LNG Terminal Capacity Agreements (Details)	9 Months Ended
	Sep. 30, 2021 USD ($) Cargo	Dec. 31, 2020 USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate	$ 198,000,000	$ 184,000,000
SPL [Member] | Affiliated Entity [Member] | Facility Swap Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
SPL [Member] | Cheniere Marketing [Member] | Cheniere Marketing SPA [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 3.00
SPL [Member] | Cheniere Marketing [Member] | 2021 - 2027 Letter Agreement
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 1.96
SPL [Member] | Cheniere Marketing [Member] | 2021 - 2027 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	81
SPL [Member] | Cheniere Marketing [Member] | 2022 - 2023 Letter Agreement | 2022 | Plus $1.768 per MMBtu
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 1.768
SPL [Member] | Cheniere Marketing [Member] | 2022 - 2023 Letter Agreement | 2022 | Plus $1.952 per MMBtu
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 1.952
SPL [Member] | Cheniere Marketing [Member] | 2022 - 2023 Letter Agreement | 2023
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 1.768
SPL [Member] | Cheniere Marketing [Member] | 2022 - 2023 Letter Agreement | Maximum [Member] | 2022 | Plus $1.768 per MMBtu
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	6
SPL [Member] | Cheniere Marketing [Member] | 2022 - 2023 Letter Agreement | Maximum [Member] | 2022 | Plus $1.952 per MMBtu
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	6
SPL [Member] | Cheniere Marketing [Member] | 2022 - 2023 Letter Agreement | Maximum [Member] | 2023
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	6
SPL [Member] | Cheniere Marketing [Member] | 2021 Letter Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 0.728
SPL [Member] | Cheniere Marketing [Member] | 2021 Letter Agreement [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	30
SPL [Member] | Cheniere Marketing [Member] | 2020 Letter Agreement
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 1.67
SPL [Member] | Cheniere Marketing [Member] | 2020 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	43

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Related Party Transactions - Service Agreements (Details) - USD ($)	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 130,000,000	$ 144,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	130,000,000	$ 144,000,000
Cheniere Terminals [Member] | Cheniere Partners Services Agreement [Member]
Related Party Transaction [Line Items]
Quarterly non-accountable overhead reimbursement charge	$ 3,000,000
SPL [Member] | Cheniere Terminals [Member] | Management Services Agreement [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
SPL [Member] | Cheniere Investments [Member] | Operation and Maintenance Agreement [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
SPLNG [Member] | Cheniere Terminals [Member] | Management Services Agreement [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	520,000
SPLNG [Member] | Cheniere Investments [Member] | Operation and Maintenance Agreement [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%

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Related Party Transactions - Other Agreements (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Related Party Transaction [Line Items]
Operating and maintenance expense—related party	$ 12,000,000	$ 0	$ 34,000,000	$ 0
Cost of sales—related party	0	0	1,000,000	0
Accrued liabilities—related party	5,000,000		5,000,000		$ 4,000,000
Due to affiliates	45,000,000		45,000,000		53,000,000
Other non-current liabilities—affiliate	15,000,000		15,000,000		17,000,000
LNG revenues—affiliate	453,000,000	103,000,000	878,000,000	352,000,000
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—related party	12,000,000	0	34,000,000	0
Cost of sales—related party	0	0	1,000,000	0
SPLNG [Member] | Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Aggregate commitment under the Agreement	25,000,000		$ 25,000,000
Tax Initiative Agreement Term			10 years
SPLNG [Member] | Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			$ 0
SPLNG [Member] | Cheniere Marketing [Member] | Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Due to affiliates	2,000,000		2,000,000
Other non-current liabilities—affiliate	15,000,000		15,000,000		17,000,000
SPLNG [Member] | Cheniere Marketing [Member] | LNG Terminal Export Agreement [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	0	0	0	0
Tug Services [Member] | Cheniere Terminals [Member] | Terminal Marine Services Agreement [Member]
Related Party Transaction [Line Items]
General Partner Distributions	2,000,000	$ 1,000,000	$ 6,000,000	$ 4,000,000
SPL and CTPL [Member] | Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term			10 years
Operating and maintenance expense—related party	12,000,000		$ 34,000,000
Cost of sales—related party	0		1,000,000
Accrued liabilities—related party	$ 5,000,000		$ 5,000,000		$ 4,000,000
SPL [Member] | Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term			5 years
SPL [Member] | Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			$ 0
CTPL [Member] | Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			$ 0

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Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended						9 Months Ended
		Oct. 26, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss)			$ 381	$ 395	$ 347	$ (67)	$ 406	$ 435	$ 1,123	$ 774
Declared distributions			375			346			1,091	1,024
Assumed allocation of undistributed net income (loss)	[1]		$ 6			$ (413)			$ 32	$ (250)
Weighted average units outstanding			484.0			414.8			484.0	370.9
Basic and diluted net income (loss) per unit			$ 0.69			$ (0.08)			$ 2.07	$ 1.55
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss)			$ 373	387	340	$ (65)	287	307
Declared distributions			329			315			$ 970	$ 763
Assumed allocation of undistributed net income (loss)	[1]		6			(347)			31	(188)
Assumed allocation of net income (loss)			$ 335			$ (32)			$ 1,001	$ 575
Weighted average units outstanding			484.0			414.8			484.0	370.9
Basic and diluted net income (loss) per unit			$ 0.69			$ (0.08)			$ 2.07	$ 1.55
Common Units [Member] | Subsequent Event [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.680
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss)			$ 0	0	0	$ (1)	111	119
Declared distributions			0			0			$ 0	$ 174
Assumed allocation of undistributed net income (loss)	[1]		0			(58)			0	(57)
Assumed allocation of net income (loss)			$ 0			$ (58)			$ 0	$ 117
Weighted average units outstanding			0.0			69.2			0.0	113.1
Basic and diluted net income (loss) per unit			$ 0			$ (0.84)			$ 0	$ 1.03
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss)			$ 8	$ 8	$ 7	$ (1)	$ 8	$ 9
Declared distributions			8			6			$ 22	$ 20
Assumed allocation of undistributed net income (loss)	[1]		0			(8)			1	(5)
Assumed allocation of net income (loss)			8			(2)			23	15
IDR [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions			38			25			99	67
Assumed allocation of undistributed net income (loss)	[1]		0			0			0	0
Assumed allocation of net income (loss)			$ 38			$ 25			$ 99	$ 67

[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).

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Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	20.00%		24.00%	22.00%
Customer A [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			26.00%		31.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%	14.00%	16.00%	15.00%
Customer B [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			18.00%		21.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	26.00%	18.00%	18.00%
Customer C [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			17.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%	22.00%	17.00%	18.00%
Customer D [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			17.00%		22.00%
Customer E [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%		11.00%	12.00%

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized	$ 601	$ 636
Balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)	$ 233	$ 233