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 333-192373

Sabine Pass Liquefaction, LLC 

(Exact name of registrant as specified in its charter)

Delaware	27-3235920
(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
None	None	None

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 ☒

Note: The registrant was a voluntary filer until January 25, 2021. The registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.

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 ☒

Indicate the number of shares outstanding of the issuer’s classes of common stock, as of the latest practicable date:  Not applicable

SABINE PASS LIQUEFACTION, LLC

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Financial Statements	2
	Statements of Operations	2
	Balance Sheets	3
	Statements of Member’s Equity	4
	Statements of Cash Flows	5
	Notes to Financial Statements	6
	Note 1—Nature of Operations and Basis of Presentation	6
	Note 2—Restricted Cash	6
	Note 3—Accounts and Other Receivables, Net of Current Expected Credit Losses	6
	Note 4—Inventory	7
	Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation	7
	Note 6—Derivative Instruments	7
	Note 7—Accrued Liabilities	11
	Note 8—Debt	12
	Note 9—Revenue from Contracts with Customers	13
	Note 10—Related Party Transactions	16
	Note 11—Customer Concentration	19
	Note 12—Supplemental Cash Flow Information	20
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	31
Item 4.	Controls and Procedures	31
Part II. Other Information
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 6.	Exhibits	33
	Signatures	34

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

Entity Abbreviations 

Cheniere	Cheniere Energy, Inc.
Cheniere Investments	Cheniere Energy Investments, LLC
Cheniere Marketing	Cheniere Marketing, LLC and subsidiaries
Cheniere Partners	Cheniere Energy Partners, L.P.
Cheniere Terminals	Cheniere LNG Terminals, LLC
CTPL	Cheniere Creole Trail Pipeline, L.P.
SPLNG	Sabine Pass LNG, L.P.

Unless the context requires otherwise, references to “SPL,” the “Company,” “we,” “us” and “our” refer to Sabine Pass Liquefaction, LLC.

1

PART I.    FINANCIAL INFORMATION

ITEM 1.     FINANCIAL STATEMENTS 

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF OPERATIONS

(in millions)

(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
Total revenues	2,244		910		5,935		3,940
Operating costs and expenses
Cost of sales (excluding items shown separately below)	1,342		454		3,178		1,551
Cost of sales—affiliate	17		37		93		60
Cost of sales—related party	—		—		1		—
Operating and maintenance expense	130		124		404		405
Operating and maintenance expense—affiliate	113		114		341		352
Operating and maintenance expense—related party	12		—		34		—
General and administrative expense	1		1		3		8
General and administrative expense—affiliate	16		17		45		54
Depreciation and amortization expense	118		115		351		348
Impairment expense and loss on disposal of assets	—		—		2		—
Total operating costs and expenses	1,749		862		4,452		2,778
Income from operations	495		48		1,483		1,162
Other income (expense)
Interest expense, net of capitalized interest	(155)		(164)		(473)		(523)
Loss on modification of debt	—		—		—		(43)
Other income, net	—		—		—		1
Total other expense	(155)		(164)		(473)		(565)
Net income (loss)	$	340	$	(116)	$	1,010	$	597

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

2

SABINE PASS LIQUEFACTION, LLC

BALANCE SHEETS

(in millions)

	September 30,		December 31,
	2021		2020
ASSETS	(unaudited)
Current assets
Restricted cash	$	133	$	97
Accounts and other receivables, net of current expected credit losses	352		309
Accounts receivable—affiliate	198		185
Advances to affiliate	114		122
Inventory	118		93
Current derivative assets	44		14
Other current assets	73		41
Other current assets—affiliate	22		21
Total current assets	1,054		882
Property, plant and equipment, net of accumulated depreciation	14,404		14,255
Debt issuance costs, net of accumulated amortization	8		10
Derivative assets	25		11
Other non-current assets, net	168		165
Total assets	$	15,659	$	15,323
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	10	$	8
Accrued liabilities	761		591
Accrued liabilities—related party	5		4
Current debt, net of discount and debt issuance costs	203		—
Due to affiliates	48		59
Deferred revenue	144		114
Deferred revenue—affiliate	4		—
Current derivative liabilities	23		11
Total current liabilities	1,198		787
Long-term debt, net of premium, discount and debt issuance costs	13,336		13,520
Derivative liabilities	13		35
Other non-current liabilities	8		8
Other non-current liabilities—affiliate	15		15
Member’s equity	1,089		958
Total liabilities and member’s equity	$	15,659	$	15,323

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

3

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF MEMBER’S EQUITY

(in millions)

(unaudited)

Three and Nine Months Ended September 30, 2021
	Sabine Pass LNG-LP, LLC		Total Member’s Equity
Balance at December 31, 2020	$	958	$	958
Distributions	(310)		(310)
Net income	337		337
Balance at March 31, 2021	985		985
Distributions	(328)		(328)
Net income	333		333
Balance at June 30, 2021	990		990
Distributions	(241)		(241)
Net income	340		340
Balance at September 30, 2021	$	1,089	$	1,089

Three and Nine Months Ended September 30, 2020
	Sabine Pass LNG-LP, LLC		Total Member’s Equity
Balance at December 31, 2019	$	534	$	534
Capital contributions	226		226
Distributions	(376)		(376)
Net income	360		360
Balance at March 31, 2020	744		744
Capital contributions	261		261
Distributions	(200)		(200)
Net income	353		353
Balance at June 30, 2020	1,158		1,158
Distributions	(135)		(135)
Net loss	(116)		(116)
Balance at September 30, 2020	$	907	$	907

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

4

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Nine Months Ended September 30,
	2021		2020
Cash flows from operating activities
Net income	$	1,010	$	597
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	351		348
Amortization of debt issuance costs, premium and discount	17		19
Loss on modification of debt	—		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	2		—
Changes in operating assets and liabilities:
Accounts and other receivables, net of current expected credit losses	(42)		95
Accounts receivable—affiliate	(14)		22
Advances to affiliate	6		28
Inventory	(25)		2
Accounts payable and accrued liabilities	147		(166)
Accrued liabilities—related party	1		2
Due to affiliates	(10)		(3)
Deferred revenue	30		26
Deferred revenue—affiliate	4		—
Other, net	(42)		(29)
Net cash provided by operating activities	1,381		1,020
Cash flows from investing activities
Property, plant and equipment	(465)		(747)
Net cash used in investing activities	(465)		(747)
Cash flows from financing activities
Proceeds from issuances of debt	—		1,995
Repayments of debt	—		(2,000)
Debt issuance and other financing costs	(1)		(34)
Debt extinguishment costs	—		(39)
Capital contributions	—		487
Distributions	(879)		(706)
Net cash used in financing activities	(880)		(297)
Net increase (decrease) in restricted cash	36		(24)
Restricted cash—beginning of period	97		181
Restricted cash—end of period	$	133	$	157

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

5

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

The Sabine Pass LNG terminal currently has 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 is located in Cameron Parish, Louisiana, adjacent to the existing regasification facilities owned by SPLNG.

Basis of Presentation

The accompanying unaudited Financial Statements of SPL 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 Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2020.

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss is included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Cheniere Partners is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of Cheniere Partners taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

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.

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—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 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 our debt holders, we are 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 3—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
Trade receivable	$	338	$	300
Other accounts receivable	14		9
Total accounts and other receivables, net of current expected credit losses	$	352	$	309

6

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 4—INVENTORY

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

	September 30,		December 31,
	2021		2020
Materials	$	68	$	68
LNG	33		8
Natural gas	16		17
Other	1		—
Total inventory	$	118	$	93

NOTE 5—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	$	13,742	$	13,711
LNG terminal construction-in-process	2,564		2,100
Accumulated depreciation	(1,906)		(1,561)
Total LNG terminal, net of accumulated depreciation	14,400		14,250
Fixed assets
Fixed assets	19		19
Accumulated depreciation	(15)		(14)
Total fixed assets, net of accumulated depreciation	4		5
Property, plant and equipment, net of accumulated depreciation	$	14,404	$	14,255

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	$	116	$	114	$	347	$	345

NOTE 6—DERIVATIVE INSTRUMENTS

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

7

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

8

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three 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

We have 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 we have with a related party.

9

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

	Fair Value Measurements as of (1)
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 Balance Sheets as of September 30, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that we have 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 Statements of Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Gain (Loss) Recognized in Statements of Operations
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.

10

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Balance Sheets Presentation

Our derivative instruments are presented on a net basis on our 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 7—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	$	158	$	150
Accrued natural gas purchases	523		374
Liquefaction Project costs	77		64
Other accrued liabilities	3		3
Total accrued liabilities	$	761	$	591

11

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—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:
4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 Working Capital Facility”) (1)	$	13,446	$	13,650
Unamortized premium, discount and debt issuance costs, net of accumulated amortization	(110)		(130)
Total long-term debt, net of premium, discount and debt issuance costs	13,336		13,520
Current debt:
Current portion of 6.25% senior secured notes due March 2022 (the “2022 Senior Notes”) (1)	204		—
Unamortized discount and debt issuance costs, net of accumulated amortization	(1)		—
Total current debt, net of discount and debt issuance costs	203		—
Total debt, net of premium, discount and debt issuance costs	$	13,539	$	13,520

(1)A portion of the 2022 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 Senior Notes and pay related fees, costs and expenses. An additional $318 million of the 2022 Senior Notes was redeemed in October 2021 with capital contributions received from Cheniere Partners subsequent to the balance sheet date, and thus is also categorized as long-term debt.

2020 Working Capital Facility

Below is a summary of our 2020 Working Capital Facility as of September 30, 2021 (in millions):

	2020 Working Capital Facility (1)
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	396
Available commitment	$	804
Priority ranking	Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%
Weighted average interest rate of outstanding balance	n/a
Maturity date	March 19, 2025

(1)The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. We pay a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on our then-current rating), 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.

12

SABINE PASS LIQUEFACTION, LLC

NOTES TO 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 our ability to make certain investments or pay dividends or distributions.

As of September 30, 2021, we were in compliance with all covenants related to our 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	$	189	$	189	$	569	$	589
Capitalized interest	(34)		(25)		(96)		(66)
Total interest expense, net of capitalized interest	$	155	$	164	$	473	$	523

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)	$	12,850	$	14,409	$	12,850	$	14,834
Senior notes — Level 3 (2)	800		997		800		1,036
Working capital facility — 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 9—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
Total revenues from customers	2,244		903		5,935		3,937
Net derivative loss (2)	—		7		—		3
Total revenues	$	2,244	$	910	$	5,935	$	3,940

(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

13

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 6—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 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 Balance Sheets (in millions):

	Nine Months Ended September 30, 2021
Deferred revenue, beginning of period	$	114
Cash received but not yet recognized in revenue	144
Revenue recognized from prior period deferral	(114)
Deferred revenue, end of period	$	144

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

	Nine Months Ended September 30, 2021
Deferred revenue—affiliate, beginning of period	$	—
Cash received but not yet recognized in revenue	4
Deferred revenue—affiliate, end of period	$	4

14

SABINE PASS LIQUEFACTION, LLC

NOTES TO 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
Total revenues	$	50.8		$	52.2

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

We 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. 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.

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.

15

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our 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
Cargo loading fees under TUA	10		5		32		23
Contracts for Sale and Purchase of Natural Gas and LNG	7		—		27		5
Total cost of sales—affiliate	17		37		93		60
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	—		—		1		—
Operating and maintenance expense—affiliate
TUA	66		67		199		200
Natural Gas Transportation Agreement	21		20		61		61
Services Agreements	26		27		80		90
LNG Site Sublease Agreement	—		—		1		1
Total operating and maintenance expense—affiliate	113		114		341		352
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		—		34		—
General and administrative expense—affiliate
Services Agreements	16		17		45		54

As of September 30, 2021 and December 31, 2020, we had $198 million and $185 million, respectively, of accounts receivable—affiliate under the agreements described below.

LNG Terminal-Related Agreements

Terminal Use Agreements

We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA.

Cheniere Partners has guaranteed our obligations under our TUA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process.

16

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Marketing Agreements

Cheniere Marketing SPA

Cheniere Marketing has an SPA (“Base SPA”) with us to purchase, at Cheniere Marketing’s option, any LNG produced by us 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, we 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 us 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

We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. We 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, we 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, we 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, we 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, we 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, we 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

To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. These agreements with CTPL have a primary term that continues until 20 years from May 2016 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to two consecutive terms of 10 years. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise. As of both September 30, 2021 and December 31, 2020, we recorded due to affiliates of $7 million and $6 million, respectively, related to this agreement.

17

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

We are also party to various natural gas transportation and storage agreements 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 the investment management company that indirectly acquired a portion of Cheniere Partners’ limited partner interests in September 2020. 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 $114 million and $122 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 Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere 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.

Liquefaction O&M Agreement

We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners, pursuant to which we receive 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 our behalf, 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, we are 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, we 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.

Liquefaction MSA

We have a management services agreement (the “Liquefaction 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 Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our 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, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

Natural Gas Supply Agreement

We are a 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 Cheniere Partners’ 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.

18

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

LNG Site Sublease Agreement

We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple periods of 10 years with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements.

Cooperation Agreement

We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We conveyed $5 million in assets to SPLNG under this agreement during the nine months ended September 30, 2020. We did not convey any assets to SPLNG under this agreement during the three and nine months ended September 30, 2021 and the three months ended September 30, 2020.

Contracts for Sale and Purchase of Natural Gas and LNG

We have agreements with SPLNG, CTPL and CCL that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements 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 these agreements is recorded as LNG revenues—affiliate.

State Tax Sharing Agreement

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

NOTE 11—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	21%	*	25%	23%	27%	32%
Customer B	17%	15%	16%	16%	18%	21%
Customer C	19%	28%	18%	19%	18%	*
Customer D	20%	24%	18%	19%	17%	22%
Customer E	*	*	*	10%	*	*

* Less than 10%

19

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 12—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, net of amounts capitalized	$	451	$	527
Non-cash distributions to affiliates for conveyance of assets	—		5

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $228 million and $217 million as of 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 that we expect to commence or complete construction of our natural gas liquefaction project, 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 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 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

21

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 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 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, currently has 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 is located in Cameron Parish, Louisiana, adjacent to the existing regasification facilities owned by SPLNG.

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.

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.

22

Financial

•In October 2021, we redeemed $318 million of our outstanding 6.25% Senior Secured Notes due 2022 (the “2022 Senior Notes”) using $318 million of capital contributions from Cheniere Partners.

•During 2021, we 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 Private Placement Senior Secured Notes”). The 2037 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 Senior Notes and pay related fees, costs and expenses. The 2037 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 February 2021, Fitch Ratings (“Fitch”) changed the outlook of our senior secured notes rating to positive from stable.

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.

Our net income was $340 million for the three months ended September 30, 2021, compared to a net loss of $116 million in the three months ended September 30, 2020 and our net income was $1,010 million for the nine months ended September 30, 2021, compared to $597 million in the nine months ended September 30, 2020. These $456 million and $413 million increases in net income, respectively, were primarily a result of 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 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.

23

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
Total revenues	$	2,244	$	910	$	1,334	$	5,935	$	3,940	$	1,995
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 from the three and nine months ended September 30, 2020, respectively, 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	17		37		(20)		93		60		33
Cost of sales—related party	—		—		—		1		—		1
Operating and maintenance expense	130		124		6		404		405		(1)
Operating and maintenance expense—affiliate	113		114		(1)		341		352		(11)
Operating and maintenance expense—related party	12		—		12		34		—		34
General and administrative expense	1		1		—		3		8		(5)
General and administrative expense—affiliate	16		17		(1)		45		54		(9)
Depreciation and amortization expense	118		115		3		351		348		3
Impairment expense and loss on disposal of assets	—		—		—		2		—		2
Total operating costs and expenses	$	1,749	$	862	$	887	$	4,452	$	2,778	$	1,674

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 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.

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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 (income)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2021		2020		Change		2021		2020		Change
Interest expense, net of capitalized interest	$	155	$	164	$	(9)	$	473	$	523	$	(50)
Loss on modification of debt	—		—		—		—		43		(43)
Other income, net	—		—		—		—		(1)		1
Total other expense	$	155	$	164	$	(9)	$	473	$	565	$	(92)

Interest expense, net of capitalized interest, decreased during the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily as a result of 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 $189 million and $189 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 $569 million and $589 million of total interest cost, respectively, of which we capitalized $96 million and $66 million, respectively.

Loss on modification or extinguishment of debt decreased during the nine months ended September 30, 2021 from the comparable periods in 2020. Loss on modification or extinguishment of debt recognized in 2020 was 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 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
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 Working Capital Facility”)	804		787

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 issued multiple orders

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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 our long-term authorizations to include short-term export authority, and vacated the short-term orders.

Customers

We have 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 us 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 our 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 our SPAs. The variable fees under our 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.

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 us 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 us to purchase: (1) at Cheniere Marketing’s option, any LNG produced by us 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 we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. We have entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project. We have 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, we 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

We have 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

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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 us to enter into a change order, or we agree 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.

Terminal Use Agreements

We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. Cheniere Partners has guaranteed our obligations under our TUA. During the three months ended September 30, 2021 and 2020, we recorded operating and maintenance expense—affiliate of $66 million and $67 million respectively, for the TUA Fees and cost of sales—affiliate of $10 million and $5 million, respectively, for cargo loading services incurred under the TUA. During the nine months ended September 30, 2021 and 2020, we recorded operating and maintenance expense—affiliate of $199 million and $200 million respectively, for the TUA Fees and cost of sales—affiliate of $32 million and $23 million, respectively, for cargo loading services incurred under the TUA.

Additionally, we have entered into a partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 5 of the Liquefaction Project, we gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides us 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 us to more flexibly manage our LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During both the three months ended September 30, 2021 and 2020, we recorded $32 million as operating and maintenance expense under this partial TUA assignment agreement. During both the nine months ended September 30, 2021 and 2020, we recorded $97 million as operating and maintenance expense under this partial TUA assignment agreement.

Capital Resources

We currently expect that our 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 Cheniere Partners. We believe that with the net proceeds of borrowings, available commitments under the 2020 Working Capital Facility, cash flows from operations and equity contributions from Cheniere Partners, we will have adequate financial resources available to meet our currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the Liquefaction Project.

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The following table provides a summary of our capital resources from borrowings and available commitments for the Liquefaction Project, excluding equity contributions from Cheniere Partners 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)	$	13,650	$	13,650
Credit facilities outstanding balance (2)	—		—
Letters of credit issued (2)	396		413
Available commitments under credit facilities (2)	804		787
Total capital resources from borrowings and available commitments (3)	$	14,850	$	14,850

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

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

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

Senior Notes

The Senior Notes are governed by a common indenture (the “Indenture”) and the terms of the 5.00% Senior Secured Notes due 2037 (the “2037 Senior Notes”) are governed by a separate indenture (the “2037 Senior Notes Indenture”). Both the Indenture and the 2037 Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit our ability and the ability of our 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 our 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 our assets and enter into certain LNG sales contracts. Subject to permitted liens, the Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in us and substantially all of our assets. We 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 Senior Notes (except for the 2022 Senior Notes, 5.625% Senior Secured Notes due 2023 (the “2023 Senior Notes”), 5.75% Senior Secured Notes due 2024 (the “2024 Senior Notes”) and 5.625% Senior Notes due 2025 (the “2025 Senior Notes”), in which case the time period is three months before the respective dates of maturity), we may redeem all or part of such series of the Senior Notes at a redemption price equal to the ‘make-whole’ price (except for the 2037 Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. We may also, at any time within six months of the respective maturity dates for each series of the Senior Notes (except for the 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes and 2025 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 Senior Notes at a redemption price equal to 100% of the principal amount of such series of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

We 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 our current outstanding indebtedness, including the Senior Notes and the 2020 Working Capital Facility. Semi-annual principal payments for the 2037 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, we entered into a series of note purchase agreements for the sale of approximately $482 million aggregate principal amount of the 2037 Private Placement Senior Secured Notes on a private placement basis. The 2037 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 our outstanding 2022 Senior Notes and pay

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related fees, costs and expenses. The 2037 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 Working Capital Facility

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

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

The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. We are 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. Obligations under the 2020 Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of our and future subsidiaries membership interests on a pari passu basis by a first priority lien with the Senior Notes.

Restrictive Debt Covenants

As of September 30, 2021, we were in compliance with all covenants related to our 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	$	1,381	$	1,020
Proceeds from issuances of debt	—		1,995
Capital contributions	—		487
Other	—		—
	$	1,381	$	3,502
Uses of cash, cash equivalents and restricted cash:
Property, plant and equipment	$	(465)	$	(747)
Repayments of debt	—		(2,000)
Debt issuance and other financing costs	(1)		(34)
Debt extinguishment costs	—		(39)
Distributions	(879)		(706)
	(1,345)		(3,526)
Net increase (decrease) in restricted cash	$	36	$	(24)

Operating Cash Flows

Our operating cash net inflows during the nine months ended September 30, 2021 and 2020 were $1,381 million and $1,020 million, respectively. The $361 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.

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.

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, 2020, we entered into the 2020 Working Capital Facility to replace the previous working capital facility and issued an aggregate principal amount of $2.0 billion of the 4.500% Senior Secured Notes due 2030, which along with cash on hand was used to redeem all of the outstanding 2021 Senior Notes. We incurred $34 million of debt issuance costs primarily related to up-front fees paid and $39 million of debt extinguishment costs related to these transactions, primarily for the payment of early redemption fees and write off of unamortized issuance costs.

Distributions

During the nine months ended September 30, 2021 and 2020, we made distributions of $879 million and $706 million, respectively, to Cheniere Partners.

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 financial position or operating results. 

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Summary of Critical Accounting Estimates

The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the 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 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 6—Derivative Instruments for additional details about our derivative instruments.

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 management, including our Chief Executive Officer and our 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 Chief Executive Officer and our 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 us 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, we 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 us returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to us alleging violations of federal pipeline safety regulations relating to the 2018 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, we responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. We continue 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

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.

ITEM 5.    OTHER INFORMATION

On November 3, 2021, we 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.

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ITEM 6.    EXHIBITS

Exhibit No.	Description
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 the Company 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 the Company, 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 the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)
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.

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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. 

		SABINE PASS LIQUEFACTION, LLC
Date:	November 3, 2021	By:	/s/ Zach Davis
			Zach Davis
			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
			Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

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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-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 Sabine Pass Liquefaction, LLC;

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 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

Sabine Pass Liquefaction, LLC

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 Sabine Pass Liquefaction, LLC;

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 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

Sabine Pass Liquefaction, LLC

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 Sabine Pass Liquefaction, LLC (the “Company”) 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 the Company, 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 Company.

Date: November 3, 2021

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Sabine Pass Liquefaction, LLC

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 Sabine Pass Liquefaction, LLC (the “Company”) 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 the Company, 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 Company.

Date: November 3, 2021

/s/ Zach Davis

Zach Davis

Chief Financial Officer of

Sabine Pass Liquefaction, LLC

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2021 shares
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2021
Document Transition Report	false
Entity File Number	333-192373
Entity Registrant Name	Sabine Pass Liquefaction, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	27-3235920
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	None
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Central Index Key	0001499200
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q3
No Trading Symbol Flag	true
Entity Common Stock, Shares Outstanding	0

XML

Statements of Income - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Revenues
Revenues		$ 2,244	$ 910	$ 5,935	$ 3,940
Revenues from contracts with customers		2,244	903	5,935	3,937
Operating costs and expenses
Cost of sales (excluding items shown separately below)		1,342	454	3,178	1,551
Cost of sales—affiliate		17	37	93	60
Cost of sales—related party		0	0	1	0
Operating and maintenance expense		130	124	404	405
Operating and maintenance expense—affiliate		113	114	341	352
Operating and maintenance expense—related party		12	0	34	0
General and administrative expense		1	1	3	8
General and administrative expense—affiliate		16	17	45	54
Depreciation and amortization expense		118	115	351	348
Impairment expense and loss on disposal of assets		0	0	2	0
Total operating costs and expenses		1,749	862	4,452	2,778
Income from operations		495	48	1,483	1,162
Other income (expense)
Interest expense, net of capitalized interest		(155)	(164)	(473)	(523)
Loss on modification of debt		0	0	0	(43)
Other income, net		0	0	0	1
Total other expense		(155)	(164)	(473)	(565)
Net income (loss)		340	(116)	1,010	597
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

[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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Balance Sheets - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Current assets
Restricted cash	$ 133	$ 97
Accounts and other receivables, net of current expected credit losses	352	309
Accounts receivable—affiliate	198	185
Advances to affiliate	114	122
Inventory	118	93
Current derivative assets	44	14
Other current assets	73	41
Other current assets—affiliate	22	21
Total current assets	1,054	882
Property, plant and equipment, net of accumulated depreciation	14,404	14,255
Debt issuance costs, net of accumulated amortization	8	10
Derivative assets	25	11
Other non-current assets, net	168	165
Total assets	15,659	15,323
Current liabilities
Accounts payable	10	8
Accrued liabilities	761	591
Accrued liabilities—related party	5	4
Current debt, net of discount and debt issuance costs	203	0
Due to affiliates	48	59
Deferred revenue	144	114
Deferred revenue—affiliate	4	0
Current derivative liabilities	23	11
Total current liabilities	1,198	787
Long-term debt, net of premium, discount and debt issuance costs	13,336	13,520
Derivative liabilities	13	35
Other non-current liabilities	8	8
Other non-current liabilities—affiliate	15	15
Member’s equity	1,089	958
Total liabilities and member’s equity	$ 15,659	$ 15,323

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Statements of Member's Equity - USD ($) $ in Millions	Total	Sabine Pass LNG-LP, LLC [Member]
Members' equity, beginning of period at Dec. 31, 2019	$ 534	$ 534
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	226	226
Distributions	(376)	(376)
Net income (loss)	360	360
Member's equity, end of period at Mar. 31, 2020	744	744
Members' equity, beginning of period at Dec. 31, 2019	534	534
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	597
Member's equity, end of period at Sep. 30, 2020	907	907
Members' equity, beginning of period at Mar. 31, 2020	744	744
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	261	261
Distributions	(200)	(200)
Net income (loss)	353	353
Member's equity, end of period at Jun. 30, 2020	1,158	1,158
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions	(135)	(135)
Net income (loss)	(116)	(116)
Member's equity, end of period at Sep. 30, 2020	907	907
Members' equity, beginning of period at Dec. 31, 2020	958	958
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions	(310)	(310)
Net income (loss)	337	337
Member's equity, end of period at Mar. 31, 2021	985	985
Members' equity, beginning of period at Dec. 31, 2020	958	958
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	1,010
Member's equity, end of period at Sep. 30, 2021	1,089	1,089
Members' equity, beginning of period at Mar. 31, 2021	985	985
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions	(328)	(328)
Net income (loss)	333	333
Member's equity, end of period at Jun. 30, 2021	990	990
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions	(241)	(241)
Net income (loss)	340	340
Member's equity, end of period at Sep. 30, 2021	$ 1,089	$ 1,089

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Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Cash flows from operating activities
Net income	$ 1,010	$ 597
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	351	348
Amortization of debt issuance costs, premium and discount	17	19
Loss on modification of debt	0	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	2	0
Changes in operating assets and liabilities:
Accounts and other receivables, net of current expected credit losses	(42)	95
Accounts receivable—affiliate	(14)	22
Advances to affiliate	6	28
Inventory	(25)	2
Accounts payable and accrued liabilities	147	(166)
Accrued liabilities—related party	1	2
Due to affiliates	(10)	(3)
Deferred revenue	30	26
Deferred revenue—affiliate	4	0
Other, net	(42)	(29)
Net cash provided by operating activities	1,381	1,020
Cash flows from investing activities
Property, plant and equipment	(465)	(747)
Net cash used in investing activities	(465)	(747)
Cash flows from financing activities
Proceeds from issuances of debt	0	1,995
Repayments of Debt	0	(2,000)
Debt issuance and other financing costs	(1)	(34)
Debt extinguishment costs	0	(39)
Capital contributions	0	487
Distributions	(879)	(706)
Net cash used in financing activities	(880)	(297)
Net increase (decrease) in restricted cash	36	(24)
Restricted cash—beginning of period	97	181
Restricted cash—end of period	$ 133	$ 157

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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 currently has 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 is located in Cameron Parish, Louisiana, adjacent to the existing regasification facilities owned by SPLNG.

Basis of Presentation

The accompanying unaudited Financial Statements of SPL 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 Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2020.

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss is included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Cheniere Partners is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of Cheniere Partners taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

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.

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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Restricted Cash	9 Months Ended
	Sep. 30, 2021
Restricted Cash [Abstract]
Restricted Cash	RESTRICTED CASHRestricted 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 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 our debt holders, we are 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
Trade receivable	$	338	$	300
Other accounts receivable	14		9
Total accounts and other receivables, net of current expected credit losses	$	352	$	309

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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	$	68	$	68
LNG	33		8
Natural gas	16		17
Other	1		—
Total inventory	$	118	$	93

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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	$	13,742	$	13,711
LNG terminal construction-in-process	2,564		2,100
Accumulated depreciation	(1,906)		(1,561)
Total LNG terminal, net of accumulated depreciation	14,400		14,250
Fixed assets
Fixed assets	19		19
Accumulated depreciation	(15)		(14)
Total fixed assets, net of accumulated depreciation	4		5
Property, plant and equipment, net of accumulated depreciation	$	14,404	$	14,255

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	$	116	$	114	$	347	$	345

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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 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

We have 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 we have with a related party.

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

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

	Fair Value Measurements as of (1)
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 Balance Sheets as of September 30, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that we have 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 Statements of Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Gain (Loss) Recognized in Statements of Operations
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.

Balance Sheets Presentation

Our derivative instruments are presented on a net basis on our 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	$	158	$	150
Accrued natural gas purchases	523		374
Liquefaction Project costs	77		64
Other accrued liabilities	3		3
Total accrued liabilities	$	761	$	591

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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:
4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 Working Capital Facility”) (1)	$	13,446	$	13,650
Unamortized premium, discount and debt issuance costs, net of accumulated amortization	(110)		(130)
Total long-term debt, net of premium, discount and debt issuance costs	13,336		13,520
Current debt:
Current portion of 6.25% senior secured notes due March 2022 (the “2022 Senior Notes”) (1)	204		—
Unamortized discount and debt issuance costs, net of accumulated amortization	(1)		—
Total current debt, net of discount and debt issuance costs	203		—
Total debt, net of premium, discount and debt issuance costs	$	13,539	$	13,520

(1)A portion of the 2022 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 Senior Notes and pay related fees, costs and expenses. An additional $318 million of the 2022 Senior Notes was redeemed in October 2021 with capital contributions received from Cheniere Partners subsequent to the balance sheet date, and thus is also categorized as long-term debt.

2020 Working Capital Facility

Below is a summary of our 2020 Working Capital Facility as of September 30, 2021 (in millions):

	2020 Working Capital Facility (1)
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	396
Available commitment	$	804
Priority ranking	Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%
Weighted average interest rate of outstanding balance	n/a
Maturity date	March 19, 2025

(1)The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. We pay a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on our then-current rating), 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 our ability to make certain investments or pay dividends or distributions.

As of September 30, 2021, we were in compliance with all covenants related to our 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	$	189	$	189	$	569	$	589
Capitalized interest	(34)		(25)		(96)		(66)
Total interest expense, net of capitalized interest	$	155	$	164	$	473	$	523

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)	$	12,850	$	14,409	$	12,850	$	14,834
Senior notes — Level 3 (2)	800		997		800		1,036
Working capital facility — 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
Total revenues from customers	2,244		903		5,935		3,937
Net derivative loss (2)	—		7		—		3
Total revenues	$	2,244	$	910	$	5,935	$	3,940

(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 6—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 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 Balance Sheets (in millions):

	Nine Months Ended September 30, 2021
Deferred revenue, beginning of period	$	114
Cash received but not yet recognized in revenue	144
Revenue recognized from prior period deferral	(114)
Deferred revenue, end of period	$	144

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

	Nine Months Ended September 30, 2021
Deferred revenue—affiliate, beginning of period	$	—
Cash received but not yet recognized in revenue	4
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
Total revenues	$	50.8		$	52.2

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

We 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. 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.

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 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
Cargo loading fees under TUA	10		5		32		23
Contracts for Sale and Purchase of Natural Gas and LNG	7		—		27		5
Total cost of sales—affiliate	17		37		93		60
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	—		—		1		—
Operating and maintenance expense—affiliate
TUA	66		67		199		200
Natural Gas Transportation Agreement	21		20		61		61
Services Agreements	26		27		80		90
LNG Site Sublease Agreement	—		—		1		1
Total operating and maintenance expense—affiliate	113		114		341		352
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		—		34		—
General and administrative expense—affiliate
Services Agreements	16		17		45		54

As of September 30, 2021 and December 31, 2020, we had $198 million and $185 million, respectively, of accounts receivable—affiliate under the agreements described below.

LNG Terminal-Related Agreements

Terminal Use Agreements

We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA.

Cheniere Partners has guaranteed our obligations under our TUA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process.

Cheniere Marketing Agreements

Cheniere Marketing SPA

Cheniere Marketing has an SPA (“Base SPA”) with us to purchase, at Cheniere Marketing’s option, any LNG produced by us 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, we 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 us 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

We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. We 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, we 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, we 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, we 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, we 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, we 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

To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. These agreements with CTPL have a primary term that continues until 20 years from May 2016 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to two consecutive terms of 10 years. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise. As of both September 30, 2021 and December 31, 2020, we recorded due to affiliates of $7 million and $6 million, respectively, related to this agreement.

We are also party to various natural gas transportation and storage agreements 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 the investment management company that indirectly acquired a portion of Cheniere Partners’ limited partner interests in September 2020. 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 $114 million and $122 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 Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere 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.

Liquefaction O&M Agreement

We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners, pursuant to which we receive 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 our behalf, 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, we are 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, we 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.

Liquefaction MSA

We have a management services agreement (the “Liquefaction 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 Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our 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, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

Natural Gas Supply Agreement

We are a 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 Cheniere Partners’ 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.

LNG Site Sublease Agreement

We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple periods of 10 years with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements.

Cooperation Agreement

We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We conveyed $5 million in assets to SPLNG under this agreement during the nine months ended September 30, 2020. We did not convey any assets to SPLNG under this agreement during the three and nine months ended September 30, 2021 and the three months ended September 30, 2020.

Contracts for Sale and Purchase of Natural Gas and LNG

We have agreements with SPLNG, CTPL and CCL that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements 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 these agreements is recorded as LNG revenues—affiliate.

State Tax Sharing Agreement

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

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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	21%	*	25%	23%	27%	32%
Customer B	17%	15%	16%	16%	18%	21%
Customer C	19%	28%	18%	19%	18%	*
Customer D	20%	24%	18%	19%	17%	22%
Customer E	*	*	*	10%	*	*

* 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, net of amounts capitalized	$	451	$	527
Non-cash distributions to affiliates for conveyance of assets	—		5

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $228 million and $217 million as of 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 Financial Statements of SPL 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 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 a disregarded entity for federal and state income tax purposes. Our taxable income or loss is included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Cheniere Partners is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of Cheniere Partners taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying 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
Trade receivable	$	338	$	300
Other accounts receivable	14		9
Total accounts and other receivables, net of current expected credit losses	$	352	$	309

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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	$	68	$	68
LNG	33		8
Natural gas	16		17
Other	1		—
Total inventory	$	118	$	93

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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	$	13,742	$	13,711
LNG terminal construction-in-process	2,564		2,100
Accumulated depreciation	(1,906)		(1,561)
Total LNG terminal, net of accumulated depreciation	14,400		14,250
Fixed assets
Fixed assets	19		19
Accumulated depreciation	(15)		(14)
Total fixed assets, net of accumulated depreciation	4		5
Property, plant and equipment, net of accumulated depreciation	$	14,404	$	14,255

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	$	116	$	114	$	347	$	345

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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 Balance Sheets (in millions):

	Fair Value Measurements as of (1)
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 Balance Sheets as of September 30, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that we have 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 Statements of Operations during the three and nine months ended September 30, 2021 and 2020 (in millions):

	Gain (Loss) Recognized in Statements of Operations
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 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	$	158	$	150
Accrued natural gas purchases	523		374
Liquefaction Project costs	77		64
Other accrued liabilities	3		3
Total accrued liabilities	$	761	$	591

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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:
4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 Working Capital Facility”) (1)	$	13,446	$	13,650
Unamortized premium, discount and debt issuance costs, net of accumulated amortization	(110)		(130)
Total long-term debt, net of premium, discount and debt issuance costs	13,336		13,520
Current debt:
Current portion of 6.25% senior secured notes due March 2022 (the “2022 Senior Notes”) (1)	204		—
Unamortized discount and debt issuance costs, net of accumulated amortization	(1)		—
Total current debt, net of discount and debt issuance costs	203		—
Total debt, net of premium, discount and debt issuance costs	$	13,539	$	13,520

(1)A portion of the 2022 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 Senior Notes and pay related fees, costs and expenses. An additional $318 million of the 2022 Senior Notes was redeemed in October 2021 with capital contributions received from Cheniere Partners subsequent to the balance sheet date, and thus is also categorized as long-term debt.

Schedule of Line of Credit Facilities

Below is a summary of our 2020 Working Capital Facility as of September 30, 2021 (in millions):

	2020 Working Capital Facility (1)
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	396
Available commitment	$	804
Priority ranking	Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%
Weighted average interest rate of outstanding balance	n/a
Maturity date	March 19, 2025

(1)The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. We pay a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on our then-current rating), 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	$	189	$	189	$	569	$	589
Capitalized interest	(34)		(25)		(96)		(66)
Total interest expense, net of capitalized interest	$	155	$	164	$	473	$	523

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)	$	12,850	$	14,409	$	12,850	$	14,834
Senior notes — Level 3 (2)	800		997		800		1,036
Working capital facility — 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
Total revenues from customers	2,244		903		5,935		3,937
Net derivative loss (2)	—		7		—		3
Total revenues	$	2,244	$	910	$	5,935	$	3,940

(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 6—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 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 Balance Sheets (in millions):

	Nine Months Ended September 30, 2021
Deferred revenue, beginning of period	$	114
Cash received but not yet recognized in revenue	144
Revenue recognized from prior period deferral	(114)
Deferred revenue, end of period	$	144

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

	Nine Months Ended September 30, 2021
Deferred revenue—affiliate, beginning of period	$	—
Cash received but not yet recognized in revenue	4
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
Total revenues	$	50.8		$	52.2

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

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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 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
Cargo loading fees under TUA	10		5		32		23
Contracts for Sale and Purchase of Natural Gas and LNG	7		—		27		5
Total cost of sales—affiliate	17		37		93		60
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	—		—		1		—
Operating and maintenance expense—affiliate
TUA	66		67		199		200
Natural Gas Transportation Agreement	21		20		61		61
Services Agreements	26		27		80		90
LNG Site Sublease Agreement	—		—		1		1
Total operating and maintenance expense—affiliate	113		114		341		352
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		—		34		—
General and administrative expense—affiliate
Services Agreements	16		17		45		54

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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	21%	*	25%	23%	27%	32%
Customer B	17%	15%	16%	16%	18%	21%
Customer C	19%	28%	18%	19%	18%	*
Customer D	20%	24%	18%	19%	17%	22%
Customer E	*	*	*	10%	*	*

* 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, net of amounts capitalized	$	451	$	527
Non-cash distributions to affiliates for conveyance of assets	—		5

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Nature of Operations and Basis of Presentation (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($) milliontonnes / yr trains	Sep. 30, 2020 USD ($)
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	5
Number of Liquefaction LNG Trains Commissioning	1
Total Production Capability | milliontonnes / yr	30

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Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 133	$ 97
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
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]
Trade receivable	$ 338	$ 300
Other accounts receivable	14	9
Total accounts and other receivables, net of current expected credit losses	$ 352	$ 309

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Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Inventory [Line Items]
Inventory	$ 118	$ 93
Materials [Member]
Inventory [Line Items]
Inventory	68	68
LNG [Member]
Inventory [Line Items]
Inventory	33	8
Natural gas [Member]
Inventory [Line Items]
Inventory	16	17
Other [Member]
Inventory [Line Items]
Inventory	$ 1	$ 0

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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	$ 14,404	$ 14,255
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(1,906)	(1,561)
Property, plant and equipment, net of accumulated depreciation	14,400	14,250
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	13,742	13,711
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,564	2,100
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19	19
Accumulated depreciation	(15)	(14)
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	$ 116	$ 114	$ 347	$ 345

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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
Natural Gas Supply Agreement [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	99	91
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

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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 Inputs 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 Inputs 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 Inputs 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 Balance Sheets as of September 30, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that we have 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 Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2021	Sep. 30, 2020	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 - Derivative Net Presentation on Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative [Line Items]
Net Amounts Presented in our Balance Sheets	$ 33	$ (21)
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	76	69
Derivative Asset, Gross Amounts Offset in the Balance Sheets	(7)	(44)
Net Amounts Presented in our Balance Sheets	69	25
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(43)	(48)
Derivative Liability, Gross Amounts Offset in the Balance Sheets	7	2
Net Amounts Presented in our Balance Sheets	$ (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	$ 158	$ 150
Accrued natural gas purchases	523	374
Liquefaction Project costs	77	64
Other accrued liabilities	3	3
Total accrued liabilities	$ 761	$ 591

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions		1 Months Ended
		Oct. 31, 2021	Sep. 30, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-term Debt, Gross	[1]		$ 13,446	$ 13,650
Long-term Debt, Net of Premium, Discount and Debt Issuance Costs			13,336	13,520
Total current debt, net of discount and debt issuance costs			203	0
Total Debt, Net of Premium, Discount and Debt Issuance Costs			13,539	13,520
Long-term Debt [Member]
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net of accumulated amortization			(110)	(130)
2022 Senior Notes [Member]
Debt Instrument [Line Items]
Current portion of senior secured notes	[1]		$ 204	0
Debt Instrument, Interest Rate, Stated Percentage			6.25%
2022 Senior Notes [Member] | Subsequent Event
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 318
Short-term Debt [Member]
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net of accumulated amortization			$ (1)	$ 0
2037 Private Placement Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 482
Minimum [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.20%
Maximum [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.25%

[1] A portion of the 2022 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 Senior Notes and pay related fees, costs and expenses. An additional $318 million of the 2022 Senior Notes was redeemed in October 2021 with capital contributions received from Cheniere Partners subsequent to the balance sheet date, and thus is also categorized as long-term debt.

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Debt - Credit Facilities (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Outstanding balance	[1]	$ 13,446	$ 13,650
2020 Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	[2]	1,200
Outstanding balance	[2]	0
Letters of credit issued	[2]	396
Available commitment	[2]	$ 804
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date	[2]	Mar. 19, 2025
2020 Working Capital Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage		0.10%
2020 Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage		0.30%
2020 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	[2]	1.125%
2020 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	[2]	1.75%
2020 Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	0.125%
2020 Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	0.75%

[1] A portion of the 2022 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 Senior Notes and pay related fees, costs and expenses. An additional $318 million of the 2022 Senior Notes was redeemed in October 2021 with capital contributions received from Cheniere Partners subsequent to the balance sheet date, and thus is also categorized as long-term debt.

[2] The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. We pay a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on our then-current rating), 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	$ 189	$ 189	$ 569	$ 589
Capitalized interest	(34)	(25)	(96)	(66)
Total interest expense, net of capitalized interest	$ 155	$ 164	$ 473	$ 523

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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]
Debt, Carrying Value		$ 13,539	$ 13,520
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[1]	12,850	12,850
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[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]	14,409	14,834
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
Working Capital Facility [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[3]	0	0
Working Capital Facility [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%
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		$ 2,244	$ 903	$ 5,935	$ 3,937
Net derivative loss	[1]	0	7	0	3
Revenues		2,244	910	5,935	3,940
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	[2]	1,791	800	5,057	3,585
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

[1] See Note 6—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 revenue, beginning of period	114
Cash received but not yet recognized in revenue	144
Revenue recognized from prior period deferral	(114)
Deferred revenue, end of period	144
Deferred revenue—affiliate, beginning of period	0
Cash received but not yet recognized in revenue	4
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			$ 52.2
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		$ 50.8
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

[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	17	37	93	60
Cost of sales—related party	0	0	1	0
Operating and maintenance expense—affiliate	113	114	341	352
Operating and maintenance expense—related party	12	0	34	0
General and administrative expense—affiliate	16	17	45	54
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	7	0	27	5
Terminal Use Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—affiliate	10	5	32	23
Operating and maintenance expense—affiliate	66	67	199	200
Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	21	20	61	61
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
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	26	27	80	90
General and administrative expense—affiliate	16	17	45	54
LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	$ 0	$ 0	$ 1	$ 1

XML

Related Party Transactions - Narrative (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($) bcf / d Cargo item	Sep. 30, 2020 USD ($)	Dec. 31, 2020 USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate	$ 198,000,000		$ 198,000,000		$ 185,000,000
Due to affiliates	48,000,000		48,000,000		59,000,000
Accrued liabilities—related party	5,000,000		5,000,000		4,000,000
Advances to affiliate	114,000,000		114,000,000		122,000,000
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
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term			10 years
Accrued liabilities—related party	5,000,000		$ 5,000,000		4,000,000
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
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to affiliate	$ 114,000,000		$ 114,000,000		122,000,000
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term			5 years
Affiliated Entity [Member] | Facility Swap Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
SPLNG [Member] | Terminal Use Agreement [Member]
Related Party Transaction [Line Items]
Regasification Capacity | bcf / d			2
Related Party Transaction, Committed Annual Fee			$ 250,000,000
SPLNG [Member] | LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Annual Sublease Payment			$ 1,000,000
Term of available extension	10 years		10 years
Review Period for Inflation Adjustment			5 years
SPLNG [Member] | Cooperation Agreement [Member]
Related Party Transaction [Line Items]
Assets conveyed under the agreement	$ 0	$ 0	$ 0	$ 5,000,000
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		$ 83,333
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			$ 3.00
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			$ 1.96
Cheniere Marketing [Member] | 2021-2027 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo			81
Cheniere Marketing [Member] | 2022 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			$ 1.768
Cheniere Marketing [Member] | 2022 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			$ 1.952
Cheniere Marketing [Member] | 2022 Letter Agreement | 2023
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
LNG Volume, Purchase Price			$ 1.768
Cheniere Marketing [Member] | 2022 Letter Agreement | Maximum [Member] | 2022 | Plus $1.768 per MMBtu
Related Party Transaction [Line Items]
Contract Cargoes | Cargo			6
Cheniere Marketing [Member] | 2022 Letter Agreement | Maximum [Member] | 2022 | plus $1.952 per MMBtu
Related Party Transaction [Line Items]
Contract Cargoes | Cargo			6
Cheniere Marketing [Member] | 2022 Letter Agreement | Maximum [Member] | 2023
Related Party Transaction [Line Items]
Contract Cargoes | Cargo			6
Cheniere Marketing [Member] | 2021 Letter Agreement
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
LNG Volume, Purchase Price			$ 0.728
Cheniere Marketing [Member] | 2021 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo			30
Cheniere Marketing [Member] | 2020 Letter Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
LNG Volume, Purchase Price			$ 1.67
Cheniere Marketing [Member] | 2020 Letter Agreement [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo			43
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		$ 541,667
Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net			$ 0
CTPL [Member] | Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term			20 years
Related Party Agreement, Termination Notice Period			1 year
Related Party Agreement, Number Of Available Extensions | item			2
Related Party Agreement, Term Of Available Extension			10 years
Due to affiliates	$ 7,000,000		$ 7,000,000		$ 6,000,000

XML

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	21.00%		25.00%	23.00%
Customer A [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			27.00%		32.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%	15.00%	16.00%	16.00%
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	19.00%	28.00%	18.00%	19.00%
Customer C [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			18.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	20.00%	24.00%	18.00%	19.00%
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				10.00%

XML

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, net of amounts capitalized	$ 451	$ 527
Non-cash distributions to affiliates for conveyance of assets	0	5
Balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)	$ 228	$ 217