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 March 31, 2022

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: As of January 1, 2022, the registrant is a voluntary filer not subject to the filing requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934. However, 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 Income	2
	Balance Sheets	3
	Statements of Member’s Equity (Deficit)	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 and Cash Equivalents	6
	Note 3—Trade and Other Receivables, Net of Current Expected Credit Losses	7
	Note 4—Inventory	7
	Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation	7
	Note 6—Derivative Instruments	7
	Note 7—Accrued Liabilities	10
	Note 8—Debt	11
	Note 9—Revenues from Contracts with Customers	12
	Note 10—Related Party Transactions	14
	Note 11—Customer Concentration	17
	Note 12—Supplemental Cash Flow Information	17
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	24
Item 4.	Controls and Procedures	24
Part II. Other Information
Item 1.	Legal Proceedings	25
Item 1A.	Risk Factors	25
Item 6.	Exhibits	26
	Signatures	27

i

DEFINITIONS

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

Common Industry and Other Terms

ASU	Accounting Standards Update
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
FASB	Financial Accounting Standards Board
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
IPM agreements	integrated production marketing agreements in which the gas producer sells to us gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs
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

Affiliate Entity Abbreviations 

Cheniere	Cheniere Energy, Inc.
Cheniere Investments	Cheniere Energy Investments, LLC
Cheniere Marketing	Cheniere Marketing, LLC and its subsidiaries
CQP	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 INCOME

(in millions)

(unaudited)

	Three Months Ended March 31,
	2022		2021
Revenues
LNG revenues	$	2,488	$	1,669
LNG revenues—affiliate	757		214
Total revenues	3,245		1,883
Operating costs and expenses
Cost of sales (excluding items shown separately below)	2,561		948
Cost of sales—affiliate	18		52
Operating and maintenance expense	148		130
Operating and maintenance expense—affiliate	117		113
Operating and maintenance expense—related party	12		10
General and administrative expense	1		1
General and administrative expense—affiliate	17		15
Depreciation and amortization expense	130		117
Total operating costs and expenses	3,004		1,386
Income from operations	241		497
Other expense
Interest expense, net of capitalized interest	(156)		(160)
Total other expense	(156)		(160)
Net income	$	85	$	337

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

2

SABINE PASS LIQUEFACTION, LLC

BALANCE SHEETS

(in millions)

	March 31,		December 31,
	2022		2021
ASSETS	(unaudited)
Current assets
Restricted cash and cash equivalents	$	136	$	98
Trade and other receivables, net of current expected credit losses	430		571
Accounts receivable—affiliate	289		232
Accounts receivable—related party	—		1
Advances to affiliate	132		127
Inventory	132		159
Current derivative assets	24		21
Other current assets	64		60
Other current assets—affiliate	23		21
Total current assets	1,230		1,290
Property, plant and equipment, net of accumulated depreciation	14,540		14,433
Debt issuance costs, net of accumulated amortization	7		7
Derivative assets	30		33
Other non-current assets, net	172		171
Total assets	$	15,979	$	15,934
LIABILITIES AND MEMBER'S EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	23	$	18
Accrued liabilities	1,082		1,012
Accrued liabilities—related party	5		4
Due to affiliates	35		73
Deferred revenue	94		132
Current derivative liabilities	256		16
Total current liabilities	1,495		1,255
Long-term debt, net of premium, discount and debt issuance costs	13,029		13,023
Derivative liabilities	2,999		11
Other non-current liabilities	7		7
Other non-current liabilities—affiliate	18		17
Member's equity (deficit)	(1,569)		1,621
Total liabilities and member's equity (deficit)	$	15,979	$	15,934

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

3

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF MEMBER’S EQUITY (DEFICIT)

(in millions)

(unaudited)

Three Months Ended March 31, 2022
	Sabine Pass LNG-LP, LLC		Total Member’s Deficit
Balance at December 31, 2021	$	1,621	$	1,621
Non-cash distribution (see Note 12)	(2,712)		(2,712)
Distributions	(563)		(563)
Net income	85		85
Balance at March 31, 2022	$	(1,569)	$	(1,569)

Three Months Ended March 31, 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

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

4

SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Three Months Ended March 31,
	2022		2021
Cash flows from operating activities
Net income	$	85	$	337
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	130		117
Amortization of debt issuance costs, premium and discount	5		6
Total losses on derivatives instruments, net	525		2
Net cash provided by (used for) settlement of derivative instruments	(9)		20
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	83		(60)
Accounts receivable—affiliate	(73)		86
Advances to affiliate	(5)		15
Inventory	26		4
Accounts payable and accrued liabilities	(5)		5
Accrued liabilities—related party	1		(1)
Due to affiliates	(21)		(22)
Deferred revenue	(38)		(35)
Deferred revenue—affiliate	—		5
Other, net	(19)		(4)
Other, net—affiliate	1		—
Net cash provided by operating activities	686		475
Cash flows from investing activities
Property, plant and equipment	(85)		(138)
Net cash used in investing activities	(85)		(138)
Cash flows from financing activities
Debt issuance and other financing costs	—		(1)
Distributions	(563)		(310)
Net cash used in financing activities	(563)		(311)
Net increase in restricted cash and cash equivalents	38		26
Restricted cash and cash equivalents—beginning of period	98		97
Restricted cash and cash equivalents—end of period	$	136	$	123

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

We are a Delaware limited liability company formed by CQP. We are a Houston-based company with one member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of CQP. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of CQP, a publicly traded limited partnership (NYSE MKT: CQP). CQP is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses. Cheniere also owns 100% of the general partner interest in CQP through ownership in Cheniere Energy Partners GP, LLC.

The natural gas liquefaction and export facility in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) has six operational Trains, with Train 6 achieving substantial completion on February 4, 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 in accordance 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, 2021. Reclassifications that are not material to our Financial Statements, if any, are made to prior period financial information to conform to the current year presentation.

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 CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP’s 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 months ended March 31, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.

Recent Accounting Standards

ASU 2020-04

In March 2020, the FASB issued 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 AND CASH EQUIVALENTS

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal. As of March 31, 2022 and December 31, 2021, we had $136 million and $98 million of restricted cash and cash equivalents, 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.

6

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 3—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

Trade and other receivables, net of current expected credit losses consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Trade receivables	$	411	$	546
Other receivables	19		25
Total trade and other receivables, net of current expected credit losses	$	430	$	571

NOTE 4—INVENTORY

Inventory consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Materials	$	74	$	71
LNG	32		44
Natural gas	25		43
Other	1		1
Total inventory	$	132	$	159

NOTE 5—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
LNG terminal
LNG terminal	$	16,195	$	13,751
LNG terminal construction-in-process	492		2,699
Accumulated depreciation	(2,149)		(2,021)
Total LNG terminal, net of accumulated depreciation	14,538		14,429
Fixed assets
Fixed assets	18		19
Accumulated depreciation	(16)		(15)
Total fixed assets, net of accumulated depreciation	2		4
Property, plant and equipment, net of accumulated depreciation	$	14,540	$	14,433

The following table shows depreciation expense and offsets to LNG terminal costs (in millions):

	Three Months Ended March 31,
	2022		2021
Depreciation expense	$	129	$	116
Offsets to LNG terminal costs (1)	148		—

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

NOTE 6—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts, including those under our assigned IPM agreement, 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”).

7

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Statements of Income 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 (in millions):

	Fair Value Measurements as of
	March 31, 2022								December 31, 2021
	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)	$	(26)	$	(13)	$	(3,162)	$	(3,201)	$	2	$	(13)	$	38	$	27

We value our Liquefaction Supply Derivatives using a market-based approach or option-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, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

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 and volatility.

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 and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2022:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(3,162)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.578) - $0.215 / $(0.004)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	104% - 459% / 206%

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

(2)Spread contemplates U.S. dollar-denominated pricing.

Increases or decreases in basis or pricing spreads, 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 (in millions):

	Three Months Ended March 31,
	2022		2021
Balance, beginning of period	$	38	$	(21)
Realized and mark-to-market gains losses:
Included in cost of sales	(53)		(12)
Purchases and settlements:
Purchases (1)	(3,141)		1
Settlements	(6)		(4)
Balance, end of period	$	(3,162)	$	(36)
Change in unrealized losses relating to instruments still held at end of period	$	(53)	$	(12)

(1)Includes any assignments during the period.

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 Liquefaction Supply Derivatives.  The remaining minimum terms of the physical natural gas supply contracts range up to 15 years, some of which commence upon the satisfaction of certain conditions precedent. The terms of the Financial Liquefaction Supply Derivatives range up to approximately two years.

The forward notional amount for our Liquefaction Supply Derivatives was approximately 5,550 TBtu and 5,194 TBtu as of March 31, 2022 and December 31, 2021, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of March 31, 2022.

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	March 31, 2022		December 31, 2021
Current derivative assets	$	24	$	21
Derivative assets	30		33
Total derivative assets	54		54
Current derivative liabilities	(256)		(16)
Derivative liabilities	(2,999)		(11)
Total derivative liabilities	(3,255)		(27)
Derivative asset (liability), net	$	(3,201)	$	27

(1)Does not include collateral posted with counterparties by us of $32 million and $7 million, which are included in other current assets in our Balance Sheets as of March 31, 2022 and December 31, 2021, respectively.

9

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Income (in millions):

	Loss Recognized in Statements of Income
Statements of Income Location (1)	Three Months Ended March 31,
	2022		2021
Cost of sales	$	(525)	$	(2)

(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 March 31, 2022
Gross assets	$	74
Offsetting amounts	(20)
Net assets	$	54
Gross liabilities	$	(3,266)
Offsetting amounts	11
Net liabilities	$	(3,255)
As of December 31, 2021
Gross assets	$	79
Offsetting amounts	(25)
Net assets	$	54
Gross liabilities	$	(33)
Offsetting amounts	6
Net liabilities	$	(27)

NOTE 7—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Accrued natural gas purchases	$	692	$	786
Interest costs and related debt fees	156		133
Liquefaction Project costs	230		89
Other accrued liabilities	4		4
Total accrued liabilities	$	1,082	$	1,012

10

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—DEBT

Our debt consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Senior Secured Notes:
5.625% due 2023	$	1,500	$	1,500
5.75% due 2024	2,000		2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.27% weighted average rate due 2037	1,282		1,282
Total Senior Secured Notes	13,132		13,132
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”)	—		—
Total debt	13,132		13,132
Unamortized premium, discount and debt issuance costs, net	(103)		(109)
Total debt, net of premium, discount and debt issuance costs	$	13,029	$	13,023

2020 Working Capital Facility

Below is a summary of our 2020 Working Capital Facility as of March 31, 2022 (in millions):

	2020 Working Capital Facility
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	368
Available commitment	$	832
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
Commitment fees on undrawn balance	0.20%
Maturity date	March 19, 2025

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. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, deposits are made into any required debt service reserve accounts and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

As of March 31, 2022, we were in compliance with all covenants related to our debt agreements.

11

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Interest Expense

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

	Three Months Ended March 31,
	2022		2021
Total interest cost	$	177	$	190
Capitalized interest	(21)		(30)
Total interest expense, net of capitalized interest	$	156	$	160

Fair Value Disclosures

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

	March 31, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	11,850	$	12,447	$	11,850	$	13,128
Senior notes — Level 3 (2)	1,282		1,297		1,282		1,466

(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. 

The estimated fair value of our 2020 Working Capital Facility approximates the principal amount outstanding 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 (in millions):

	Three Months Ended March 31,
	2022		2021
LNG revenues	$	2,488	$	1,669
LNG revenues—affiliate	757		214
Total revenues	$	3,245	$	1,883

Contract Assets and Liabilities

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):

	March 31,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	1	$	1

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

	Three Months Ended March 31, 2022
Deferred revenue, beginning of period	$	132
Cash received but not yet recognized in revenue	94
Revenue recognized from prior period deferral	(132)
Deferred revenue, end of period	$	94

12

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Three Months Ended March 31, 2022
Deferred revenue—affiliate, beginning of period	$	2
Cash received but not yet recognized in revenue	3
Revenue recognized from prior period deferral	(2)
Deferred revenue—affiliate, end of period	$	3

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of March 31, 2022 and December 31, 2021:

	March 31, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	51.2	8	$	49.3	9
LNG revenues—affiliate	2.0		3	2.1		3
Total revenues	$	53.2		$	51.4

(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 67% and 51% of our LNG revenues from contracts included in the table above during the three months ended March 31, 2022 and 2021, respectively, were related to variable consideration received from customers. 100% of our LNG revenues—affiliate from contracts included in the table above during both the three months ended March 31, 2022 and 2021 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.

13

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 Income (in millions):

	Three Months Ended March 31,
	2022		2021
LNG revenues—affiliate
Cheniere Marketing Agreements	$	745	$	210
Contracts for Sale and Purchase of Natural Gas and LNG	12		4
Total LNG revenues—affiliate	757		214
Cost of sales—affiliate
Cheniere Marketing Agreements	—		34
Cargo loading fees under TUA	13		11
Contracts for Sale and Purchase of Natural Gas and LNG	5		7
Total cost of sales—affiliate	18		52
Operating and maintenance expense—affiliate
TUA	66		66
Natural Gas Transportation Agreement	20		20
Services Agreements	31		27
Total operating and maintenance expense—affiliate	117		113
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		10
General and administrative expense—affiliate
Services Agreements	17		15

As of March 31, 2022 and December 31, 2021, we had $289 million and $232 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.

CQP 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.

14

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

Cheniere Marketing Letter Agreements

Cheniere Marketing has letter agreements with us to purchase up to 306 cargoes to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub.

In December 2020, we and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes that were delivered in 2021 at a price of 115% of Henry Hub plus $0.728 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 CQP, 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 March 31, 2022 and December 31, 2021, we recorded due to affiliates of $8 million 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 CQP’s limited partner interests in September 2020. In addition to the amounts recorded on our Statements of Income in the table above, we recorded accrued liabilities—related party of $5 million and $4 million as of March 31, 2022 and December 31, 2021, respectively, with this related party.

Services Agreements

As of March 31, 2022 and December 31, 2021, we had $132 million and $127 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.

15

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Liquefaction O&M Agreement

We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of CQP, 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.

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 did not convey any assets to SPLNG under this agreement during the three months ended March 31, 2022 and 2021.

Contracts for Sale and Purchase of Natural Gas and LNG

We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“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

16

SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

(unaudited)

basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing 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 trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, 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 Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended March 31,		March 31,	December 31,
	2022	2021	2022	2021
Customer A	29%	28%	32%	29%
Customer B	14%	15%	15%	*
Customer C	18%	19%	15%	14%
Customer D	15%	15%	17%	17%
Customer E	10%	*	*	13%
Customer F	*	*	*	12%

* Less than 10%

NOTE 12—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2022		2021
Cash paid during the period for interest, net of amounts capitalized	$	130	$	148
Non-cash investing and financing activities:
Property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)	386		222
Novation of IPM agreement from Cheniere Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)	(2,712)		—

Novation of IPM Agreement from CCL Stage III

In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, we and CCL Stage III, a wholly owned subsidiary of Cheniere, entered into an agreement to assign to us an IPM agreement to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023. The transaction has been accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $2.7 billion in distributions within our Statements of Member’s Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $0.1 billion and $2.6 billion, 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 regarding our future sources of liquidity and cash requirements;

•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 COVID-19 pandemic and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing creditworthiness 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

18

from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2021. 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 

•Overview of Significant Events

•Results of Operations

•Liquidity and Capital Resources

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Overview

We are a Delaware limited liability company formed by CQP. 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.

LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.

The natural gas liquefaction and export facility in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, has six operational Trains, with Train 6 achieving substantial completion on February 4, 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 and operated by SPLNG.

Our customer arrangements provide us with significant, stable and long-term cash flows. We contract our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted approximately 80% of the total production capacity from the Liquefaction Project with approximately 16 years of weighted average remaining life as of March 31, 2022. In March 2022, the DOE authorized the export of an additional 152.64 Bcf/yr of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050 to non-FTA countries, that were previously authorized for FTA countries only. For further discussion of the contracted future

19

cash flows under our revenue arrangements, see the liquidity and capital resources disclosures in our annual report on Form 10-K for the fiscal year ended December 31, 2021.

We remain focused on operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. Further development of the Sabine Pass LNG Terminal will require, among other things, acceptable commercial and financing arrangements before we can make a final investment decision.

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 April 2022, Cheniere announced a collaboration with natural gas midstream companies, methane detection technology providers and leading academic institutions to implement quantification, monitoring, reporting and verification of greenhouse gas emissions at natural gas gathering, processing, transmission and storage systems specific to our supply chain. 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, 2022 and through the filing date of this Form 10-Q include the following:

Strategic

•In February 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project:

◦Cheniere Marketing, LLC entered into agreements to novate to us SPAs entered into with ENN LNG (Singapore) Pte Ltd. and a subsidiary of Glencore plc, with effective dates of January 1, 2023 and February 17, 2022, respectively, aggregating approximately 21 million tonnes of LNG to be delivered between 2023 and 2035.

◦The Board of Directors of CQP approved our entry into (i) an agreement to novate to us an IPM agreement between Cheniere Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”), a wholly owned subsidiary of Cheniere (as purchaser), and Tourmaline Oil Marketing Corp., a subsidiary of Tourmaline Oil Corp (as supplier), to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023 (the “Tourmaline IPM”) and (ii) a free on board SPA with Cheniere Marketing International LLP to sell LNG associated with the natural gas to be supplied under the IPM agreement. The agreement to assign the Tourmaline IPM agreement from CCL Stage III to us was executed and the assignment was effective on March 15, 2022.

Operational

•As of April 30, 2022, over 1,600 cumulative LNG cargoes totaling over 110 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

•On February 4, 2022, substantial completion of Train 6 of the Liquefaction Project was achieved.

20

Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Project during the three months ended March 31, 2022 and 2021:

(1) The three months ended March 31, 2021 excludes eight TBtu that were loaded at our affiliate’s facility.

Net income

Our net income was $85 million for the three months ended March 31, 2022, compared to $337 million in the three months ended March 31, 2021. This $252 million decrease in net income was primarily a result of a loss on the derivative liability associated with the Tourmaline IPM agreement following its assignment to us from CCL Stage III in March 2022. See Overview of Significant Events for further discussion of the assignment. The associated loss following the assignment was primarily attributed to our lower credit risk profile relative to that of CCL Stage III, resulting in a higher derivative liability given reduced risk of our own nonperformance.

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.

Revenues

	Three Months Ended March 31,
(in millions, except volumes)	2022		2021		Variance
LNG revenues	$	2,488	$	1,669	$	819
LNG revenues—affiliate	757		214		543
Total revenues	$	3,245	$	1,883	$	1,362
LNG volumes recognized as revenues (in TBtu) (1)	372		325		47

(1)The three months ended March 31, 2021 includes eight TBtu that were loaded at our affiliate’s facility.

21

Total revenues increased by approximately $1.4 billion during the three months ended March 31, 2022 from the three months ended March 31, 2021 primarily due to increased revenues per MMBtu as a result of increases in Henry Hub prices and, to a lesser extent, higher volumes of LNG delivered between the periods as a result of production from Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the three months ended March 31, 2022, we realized offsets to LNG terminal costs of $148 million, corresponding to 13 TBtu that were related to the sale of commissioning cargoes from the Liquefaction Project. We did not realize any offsets to LNG terminal costs during the three months ended March 31, 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 $54 million and $48 million during the three months ended March 31, 2022 and 2021, respectively, related to these transactions.

Operating costs and expenses

	Three Months Ended March 31,
(in millions)	2022		2021		Variance
Cost of sales	$	2,561	$	948	$	1,613
Cost of sales—affiliate	18		52		(34)
Operating and maintenance expense	148		130		18
Operating and maintenance expense—affiliate	117		113		4
Operating and maintenance expense—related party	12		10		2
General and administrative expense	1		1		—
General and administrative expense—affiliate	17		15		2
Depreciation and amortization expense	130		117		13
Total operating costs and expenses	$	3,004	$	1,386	$	(1,182)

Total operating costs and expenses increased during the three months ended March 31, 2022 from the three months ended March 31, 2021, 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 months ended March 31, 2022 from the comparable 2021 period primarily as a result of the increased cost of natural gas feedstock as a result of higher US natural gas prices and, to a lesser extent, from increased volume of LNG delivered. Cost of sales also includes change in fair value of commodity derivatives to secure natural gas feedstock for the Liquefaction Project, costs associated with the sale of certain unutilized natural gas procured for the liquefaction process, variable transportation and storage costs and other costs to convert natural gas into LNG. During the three months ended March 31, 2022, cost of sales additionally included an unfavorable change in the valuation associated with the Tourmaline IPM agreement that was assigned to us in March 2022, primarily as a result of credit risk as described in the Net income section above.

Operating and maintenance expense (including affiliate and related party) primarily includes costs associated with operating and maintaining the Liquefaction Project. During the three months ended March 31, 2022, operating and maintenance expense increased from the comparable period in 2021, primarily due to increased natural gas transportation and storage capacity demand charges, generally as a result of an additional Train in operation during the three months ended March 31, 2022. Operating and maintenance (including affiliates) also includes third party service and maintenance, insurance, regulatory costs and other operating costs.

Other expense

	Three Months Ended March 31,
(in millions)	2022		2021		Variance
Interest expense, net of capitalized interest	$	156	$	160	$	(4)
Total other expense	$	156	$	160	$	(4)

22

Interest expense, net of capitalized interest, decreased during the three months ended March 31, 2022 from the comparable period in 2021 primarily as a result of the reduction of outstanding debt between the periods, which was offset by the reduction in the portion of total interest costs eligible for capitalization as construction of Train 6 of the Liquefaction Project which achieved substantial completion on February 4, 2022. During the three months ended March 31, 2022 and 2021, we incurred $177 million and $190 million of total interest cost, respectively, of which we capitalized $21 million and $30 million, respectively.

Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.

	March 31, 2022
Restricted cash and cash equivalents designated for the Liquefaction Project	$	136
Available commitments under our $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”) (1)	832
Total available liquidity	$	968

(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under the 2020 Working Capital Facility as of March 31, 2022. See Note 8—Debt of our Notes to Financial Statements for additional information on the 2020 Working Capital Facility and other debt instruments.

Our liquidity position subsequent to March 31, 2022 is driven by future sources of liquidity and future cash requirements. Future sources of liquidity are expected to be composed of (1) cash receipts from executed contracts, under which we are contractually entitled to future revenues, and (2) additional sources of liquidity, from which we expect to receive cash although the cash is not underpinned by executed contracts. Future cash requirements are expected to be composed of (1) cash payments under executed contracts, under which we are contractually obligated to make payments, and (2) additional cash requirements, under which we expect to make payments although we are not contractually obligated to make the payments under executed contracts.

Sources and Uses of Cash

The following table summarizes the sources and uses of our restricted cash and cash equivalents (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.

	Three Months Ended March 31,
	2022		2021
Net cash provided by operating activities	$	686	$	475
Net cash used in investing activities	(85)		(138)
Net cash used in financing activities	(563)		(311)
Net increase in restricted cash and cash equivalents	$	38	$	26

Operating Cash Flows

Our operating cash net inflows during the three months ended March 31, 2022 and 2021 were $686 million and $475 million, respectively. The $211 million increase in operating cash inflows in 2022 compared to 2021 was primarily related to increases in cash payments on LNG delivered due to increases in price per MMBtu and volume delivered, partially offset by higher operating cash outflows primarily due to higher natural gas feedstock costs.

23

Investing Cash Flows

Cash outflows for property, plant and equipment were primarily for the construction costs for Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022. These costs are capitalized as construction-in-process until achievement of substantial completion.

Financing Cash Flows

During the three months ended March 31, 2022 and 2021, we made distributions of $563 million and $310 million, respectively, to CQP.

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, 2021.

Recent Accounting Standards 

For a summary 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):

	March 31, 2022				December 31, 2021
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(3,201)	$	518	$	27	$	1

See Note 6—Derivative Instruments of our Notes to Financial Statements 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. 

24

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, 2021.

Louisiana Department of Environmental Quality (“LDEQ”) Matter

Certain of Cheniere’s subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG Terminal and the commissioning of the Liquefaction Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of Cheniere’s subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of Cheniere’s subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.

Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Matter

In February 2018, the 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 (the “2018 tank incident”). 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. PHMSA notified us in a letter dated November 9, 2021 that the case was considered “closed.” On March 9, 2022, PHMSA and FERC issued conditional approval to return one of the two tanks to service. We continue to coordinate with PHMSA and FERC to address the matters relating to the 2018 tank incident, 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, 2021.

25

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-00058 COVID-19 Impacts 3Q2021, dated January 6, 2022, (ii) CO-00059 Spill Containment SIL 2 Interlock, dated January 11, 2022, (iii) the Change Order CO-00060 Third Berth Soil Preparation Provisional Sum Closure, dated March 15, 2022, (iv) the Change Order CO-00061 COVID-19 Impacts 4Q2021, dated March 15, 2022 and (v) the Change Order CO-00062 FERC Condition 61, dated March 15, 2022
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.

26

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:	May 3, 2022	By:	/s/ Zach Davis
			Zach Davis
			Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	May 3, 2022	By:	/s/ David Slack
			David Slack
			Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

27

EX-10.1

Exhibit 10.1

CHANGE ORDER

COVID-19 Impacts 3Q2021

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-00058 DATE OF CHANGE ORDER: January 6, 2022

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 third quarter of 2021 (“Q3”) (actuals July 2021 through September 2021), in response to the novel coronavirus (COVID-19) outbreak event.

This Change Order is based on the following assumptions and qualifications for Q3:

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 shutdowns in Q3.

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 Q3. 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 Q3 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 30 September 2021. 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, 45-49, 51, 53-57)	$	18,111,175
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,035,003,748
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	1,718,311
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	$	2,036,722,059

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)	$	2,488,721,212
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	1,718,311
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,490,439,523

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
January 12, 2022	January 6, 2022
Date of Signing	Date of Signing

CHANGE ORDER

Spill Containment SIL 2 Interlock

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-00059 DATE OF CHANGE ORDER: January 11, 2022

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 costs to implement Spill Containment SIL 2 Interlock for the Third Berth Project as requested by FERC.

Owner requests Contractor to design and implement SIL 2 rated Safety Instrument Function (flow-based solution) within the loading lines to limit flow to the Third Berth in the event of full guillotine failure of a loading line as documented in DECN No. 26012-100-M6N-DK-24011, Rev 001; including:

•High-level transients for a single pump trip scenario at increased pumping rate of 13,000 m3/hr. Contractor shall run transients for the following cases, report results in excel spreadsheet (original vs. new), and identify any exceedances from the original:

i.Single pump trip at 12,000m3/hr (6,000 m3/hr from Phase 1 tanks; 6,000 m3/hr from Phase 2 tanks)

ii.Single pump trip at 12,000m3/hr (10,000 m3/hr from Phase 1 tanks; 2,000 m3/hr from Phase 2 tanks)

iii.Single pump trip at 13,000m3/hr (6,500 m3/hr from Phase 1 tanks; 6,500 m3/hr from Phase 2 tanks)

iv.Single pump trip at 13,000m3/hr (10,500 m3/hr from Phase 1 tanks; 2,500 m3/hr from Phase 2 tanks)

•Stress comparison to identify if any exceedances of original design margins based on new dynamic loads from Cases (i) through (iv) above.

•FHA revision based on Owner’s update to facility siting study (through 3rd-party consultant, Blue Engineering)

2.Mitigation of any exceedance(s) (including re-running of transient at different conditions, and stress analysis to confirm such exceedance(s) are acceptable to mitigate any potential exceedances) are specifically excluded from this Change Order and shall be part of a separate Change Order in accordance with Section 6.1 of the Agreement, if requested by Owner.

3.The detailed cost breakdown for this Change Order is detailed 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, 45-49, 51, 53-58)	$	19,829,486
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,036,722,059
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	$	2,036,722,059

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 increased by this Change Order	$	654,482
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	$	454,371,946

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)	$	2,490,439,523
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	654,482
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,491,094,005

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

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
January 18, 2022	January 11, 2022
Date of Signing	Date of Signing

CHANGE ORDER

Third Berth Soil Preparation Provisional Sum Closure

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-00060 DATE OF CHANGE ORDER: March 15, 2022

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

1.Pursuant to the instructions in the Soils Preparation Provisional Sum in Section 2.6 of Attachment EE, Schedule EE-4 of the Agreement, this Change Order amends the Soils Preparation Provisional Sum amount based on Final Soils Preparation Basis Documents.

2.The original Soils Preparation Provisional Sum in Section 2.6 of Attachment EE, Schedule EE-4 of the Agreement was Five Million, Six Hundred Seventeen Thousand U.S. Dollars (U.S. $5,617,000).

3.The amended Soils Preparation Provisional Sum, pursuant to Change Order CO-00030, dated 16 September 2020, was Seven Million, Six Hundred Thousand, Two Hundred Sixty U.S. Dollars (U.S. $7,600,260).

4.The Soils Preparation Provisional Sum in Section 2.6 of Attachment EE, Schedule EE-4 of the Agreement is hereby increased by One Million, Three Hundred Fifty-Nine Thousand, Seven Hundred Three U.S. Dollars *U.S. $1,359,703); and therefore, the final Soils Preparation Provisional Sum as amended by this Change Order shall be Eight Million, Nine Hundred Fifty-Nine Thousand, Nine Hundred Sixty-Three U.S. Dollars (U.S. $8,959,963).

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

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

Adjustment to Contract Price 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, 53-57)	$	19,829,486
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,036,722,059
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	$	2,036,722,059

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)	$	(3,324,054)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	454,371,946
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 increased by this Change Order	$	1,359,703
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	455,731,649

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)	$	2,491,094,005
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	1,359,703
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,492,453,708

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

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
March 22, 2022	March 15, 2022
Date of Signing	Date of Signing

CHANGE ORDER

COVID-19 Impacts 4Q2021

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-00061 DATE OF CHANGE ORDER: March 15, 2022

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 fourth quarter of 2021 (“Q4”) (actuals September 2021 through December 2021), in response to the novel coronavirus (COVID-19) outbreak event.

This Change Order is based on the following assumptions and qualifications for Q4:

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 shutdowns in Q4.

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 Q4. 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 Q4 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 31 December 2021. 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, 45-49, 51, 53-57)	$	19,829,486
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,036,722,059
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	1,325,619
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	$	2,038,047,678

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)	$	(1,964,351)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	455,731,649
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	$	455,731,649

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)	$	2,492,453,708
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	1,325,619
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,493,779,327

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
March 22, 2022	March 15, 2022
Date of Signing	Date of Signing

CHANGE ORDER

FERC Condition 61

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-00062 DATE OF CHANGE ORDER: March 15, 2022

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 costs to implement modifications to the area class zone around the potential leak points in the onshore valve platform for the Third Berth to the below distances to satisfy FERC Condition 61:

•Twenty-five feet (25’) around the leak point;

•Twenty-five feet (25’) height to fifty feet (50’) wide around the leak point; and

•Two feet (2’) height to one hundred feet (100’) wide around the leak point.

These are the same distances as API RP 500 Figures 20/21.

2.To avoid encroachment of the new area class zone on to nearby non-hazardous rated equipment, the flow element type will be changed to welded V-Cone (FE-24998) and the instruments (Flow Transmitter (FT-24998A) and Pressure Indicator (PI-24992)) will be relocated outside of the area class zone by extending the tubing. The local control panel for the Sanitary Treatment Package will be elevated above the hazardous zone. Refer to Electrical Hazardous Area Classification 26012-100-E3-03A03-00001 Rev 001.

3.The detailed cost breakdown for this Change Order is detailed 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, 45-49, 51, 53-57)	$	21,155,105
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,038,047,678
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	$	2,038,047,678

2

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)	$	(1,964,351)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	455,731,649
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	106,684
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	$	455,838,333

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)	$	2,493,779,327
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	106,684
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,493,886,011

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

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
March 22, 2022	March 15, 2022
Date of Signing	Date of Signing

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

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

I, Jack A. Fusco, certify that:

1.    I have reviewed this quarterly report on Form 10-Q of 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: May 3, 2022

/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: May 3, 2022

/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 March 31, 2022, 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: May 3, 2022

/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 March 31, 2022, 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: May 3, 2022

/s/ Zach Davis

Zach Davis

Chief Financial Officer of

Sabine Pass Liquefaction, LLC

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2022 shares
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
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	2022
Document Fiscal Period Focus	Q1
No Trading Symbol Flag	true
Entity Common Stock, Shares Outstanding	0

XML

Statements of Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Revenues
Revenues	$ 3,245	$ 1,883
Operating costs and expenses
Cost of sales (excluding items shown separately below)	2,561	948
Cost of sales—affiliate	18	52
Operating and maintenance expense	148	130
Operating and maintenance expense—affiliate	117	113
Operating and maintenance expense—related party	12	10
General and administrative expense	1	1
General and administrative expense—affiliate	17	15
Depreciation and amortization expense	130	117
Total operating costs and expenses	3,004	1,386
Income from operations	241	497
Other expense
Interest expense, net of capitalized interest	(156)	(160)
Total other expense	(156)	(160)
Net income	85	337
LNG [Member]
Revenues
Revenues	2,488	1,669
Revenues from contracts with customers	2,488	1,669
LNG—affiliate
Revenues
Revenues from contracts with customers	$ 757	$ 214

XML

Balance Sheets - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Current assets
Restricted cash and cash equivalents	$ 136	$ 98
Trade and other receivables, net of current expected credit losses	430	571
Accounts receivable—affiliate	289	232
Accounts receivable—related party	0	1
Advances to affiliate	132	127
Inventory	132	159
Current derivative assets	24	21
Other current assets	64	60
Other current assets—affiliate	23	21
Total current assets	1,230	1,290
Property, plant and equipment, net of accumulated depreciation	14,540	14,433
Debt issuance costs, net of accumulated amortization	7	7
Derivative assets	30	33
Other non-current assets, net	172	171
Total assets	15,979	15,934
Current liabilities
Accounts payable	23	18
Accrued liabilities	1,082	1,012
Accrued liabilities—related party	5	4
Due to affiliates	35	73
Deferred revenue	94	132
Current derivative liabilities	256	16
Total current liabilities	1,495	1,255
Long-term debt, net of premium, discount and debt issuance costs	13,029	13,023
Derivative liabilities	2,999	11
Other non-current liabilities	7	7
Other non-current liabilities—affiliate	18	17
Member's equity (deficit)	(1,569)	1,621
Total liabilities and member's equity (deficit)	$ 15,979	$ 15,934

XML

Statements of Member's Equity - USD ($) $ in Millions	Total	Sabine Pass LNG-LP, LLC [Member]
Members' equity, beginning of period at Dec. 31, 2020	$ 958	$ 958
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions	(310)	(310)
Net income	337	337
Member's equity, end of period at Mar. 31, 2021	985	985
Members' equity, beginning of period at Dec. 31, 2021	1,621	1,621
Increase (Decrease) in Partners' Capital [Roll Forward]
Non-cash distribution	(2,712)	(2,712)
Distributions	(563)	(563)
Net income	85	85
Member's equity, end of period at Mar. 31, 2022	$ (1,569)	$ (1,569)

XML

Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Cash flows from operating activities
Net income	$ 85	$ 337
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	130	117
Amortization of debt issuance costs, premium and discount	5	6
Total losses on derivatives instruments, net	525	2
Net cash provided by (used for) settlement of derivative instruments	(9)	20
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	83	(60)
Accounts receivable—affiliate	(73)	86
Advances to affiliate	(5)	15
Inventory	26	4
Accounts payable and accrued liabilities	(5)	5
Accrued liabilities—related party	1	(1)
Due to affiliates	(21)	(22)
Deferred revenue	(38)	(35)
Deferred revenue—affiliate	0	5
Other, net	(19)	(4)
Other, net—affiliate	1	0
Net cash provided by operating activities	686	475
Cash flows from investing activities
Property, plant and equipment	(85)	(138)
Net cash used in investing activities	(85)	(138)
Cash flows from financing activities
Debt issuance and other financing costs	0	(1)
Distributions	(563)	(310)
Net cash used in financing activities	(563)	(311)
Net increase in restricted cash and cash equivalents	38	26
Restricted cash and cash equivalents—beginning of period	98	97
Restricted cash and cash equivalents—end of period	$ 136	$ 123

XML

Organization and Nature of Operations

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We are a Delaware limited liability company formed by CQP. We are a Houston-based company with one member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of CQP. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of CQP, a publicly traded limited partnership (NYSE MKT: CQP). CQP is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses. Cheniere also owns 100% of the general partner interest in CQP through ownership in Cheniere Energy Partners GP, LLC.

The natural gas liquefaction and export facility in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) has six operational Trains, with Train 6 achieving substantial completion on February 4, 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 in accordance 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, 2021. Reclassifications that are not material to our Financial Statements, if any, are made to prior period financial information to conform to the current year presentation.

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 CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP’s 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 months ended March 31, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.

Recent Accounting Standards

ASU 2020-04

In March 2020, the FASB issued 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 and Cash Equivalents	3 Months Ended
	Mar. 31, 2022
Restricted Cash and Cash Equivalents [Abstract]
Restricted Cash and Cash Equivalents	RESTRICTED CASH AND CASH EQUIVALENTSRestricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal. As of March 31, 2022 and December 31, 2021, we had $136 million and $98 million of restricted cash and cash equivalents, 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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Trade and Other Receivables, Net of Current Expected Credit Losses

3 Months Ended

Mar. 31, 2022

Receivables [Abstract]

Trade and Other Receivables, Net of Current Expected Credit Losses

TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

Trade and other receivables, net of current expected credit losses consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Trade receivables	$	411	$	546
Other receivables	19		25
Total trade and other receivables, net of current expected credit losses	$	430	$	571

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Inventory

3 Months Ended

Mar. 31, 2022

Inventory Disclosure [Abstract]

Inventory

INVENTORY

Inventory consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Materials	$	74	$	71
LNG	32		44
Natural gas	25		43
Other	1		1
Total inventory	$	132	$	159

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Property, Plant and Equipment, Net of Accumulated Depreciation

3 Months Ended

Mar. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
LNG terminal
LNG terminal	$	16,195	$	13,751
LNG terminal construction-in-process	492		2,699
Accumulated depreciation	(2,149)		(2,021)
Total LNG terminal, net of accumulated depreciation	14,538		14,429
Fixed assets
Fixed assets	18		19
Accumulated depreciation	(16)		(15)
Total fixed assets, net of accumulated depreciation	2		4
Property, plant and equipment, net of accumulated depreciation	$	14,540	$	14,433

The following table shows depreciation expense and offsets to LNG terminal costs (in millions):

	Three Months Ended March 31,
	2022		2021
Depreciation expense	$	129	$	116
Offsets to LNG terminal costs (1)	148		—

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

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Derivative Instruments

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTSWe have entered into commodity derivatives consisting of natural gas supply contracts, including those under our assigned IPM agreement, 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 Income 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 (in millions):

	Fair Value Measurements as of
	March 31, 2022								December 31, 2021
	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)	$	(26)	$	(13)	$	(3,162)	$	(3,201)	$	2	$	(13)	$	38	$	27

We value our Liquefaction Supply Derivatives using a market-based approach or option-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, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

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 and volatility.

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 and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2022:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(3,162)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.578) - $0.215 / $(0.004)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	104% - 459% / 206%

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

(2)Spread contemplates U.S. dollar-denominated pricing.

Increases or decreases in basis or pricing spreads, 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 (in millions):

	Three Months Ended March 31,
	2022		2021
Balance, beginning of period	$	38	$	(21)
Realized and mark-to-market gains losses:
Included in cost of sales	(53)		(12)
Purchases and settlements:
Purchases (1)	(3,141)		1
Settlements	(6)		(4)
Balance, end of period	$	(3,162)	$	(36)
Change in unrealized losses relating to instruments still held at end of period	$	(53)	$	(12)

(1)Includes any assignments during the period.

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 Liquefaction Supply Derivatives.  The remaining minimum terms of the physical natural gas supply contracts range up to 15 years, some of which commence upon the satisfaction of certain conditions precedent. The terms of the Financial Liquefaction Supply Derivatives range up to approximately two years.

The forward notional amount for our Liquefaction Supply Derivatives was approximately 5,550 TBtu and 5,194 TBtu as of March 31, 2022 and December 31, 2021, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of March 31, 2022.

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	March 31, 2022		December 31, 2021
Current derivative assets	$	24	$	21
Derivative assets	30		33
Total derivative assets	54		54
Current derivative liabilities	(256)		(16)
Derivative liabilities	(2,999)		(11)
Total derivative liabilities	(3,255)		(27)
Derivative asset (liability), net	$	(3,201)	$	27

(1)Does not include collateral posted with counterparties by us of $32 million and $7 million, which are included in other current assets in our Balance Sheets as of March 31, 2022 and December 31, 2021, respectively.

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Income (in millions):

	Loss Recognized in Statements of Income
Statements of Income Location (1)	Three Months Ended March 31,
	2022		2021
Cost of sales	$	(525)	$	(2)

(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 March 31, 2022
Gross assets	$	74
Offsetting amounts	(20)
Net assets	$	54
Gross liabilities	$	(3,266)
Offsetting amounts	11
Net liabilities	$	(3,255)
As of December 31, 2021
Gross assets	$	79
Offsetting amounts	(25)
Net assets	$	54
Gross liabilities	$	(33)
Offsetting amounts	6
Net liabilities	$	(27)

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Accrued Liabilities

3 Months Ended

Mar. 31, 2022

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Accrued natural gas purchases	$	692	$	786
Interest costs and related debt fees	156		133
Liquefaction Project costs	230		89
Other accrued liabilities	4		4
Total accrued liabilities	$	1,082	$	1,012

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Debt

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Debt

DEBT

Our debt consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Senior Secured Notes:
5.625% due 2023	$	1,500	$	1,500
5.75% due 2024	2,000		2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.27% weighted average rate due 2037	1,282		1,282
Total Senior Secured Notes	13,132		13,132
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”)	—		—
Total debt	13,132		13,132
Unamortized premium, discount and debt issuance costs, net	(103)		(109)
Total debt, net of premium, discount and debt issuance costs	$	13,029	$	13,023

2020 Working Capital Facility

Below is a summary of our 2020 Working Capital Facility as of March 31, 2022 (in millions):

	2020 Working Capital Facility
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	368
Available commitment	$	832
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
Commitment fees on undrawn balance	0.20%
Maturity date	March 19, 2025

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. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, deposits are made into any required debt service reserve accounts and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

As of March 31, 2022, 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 March 31,
	2022		2021
Total interest cost	$	177	$	190
Capitalized interest	(21)		(30)
Total interest expense, net of capitalized interest	$	156	$	160

Fair Value Disclosures

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

	March 31, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	11,850	$	12,447	$	11,850	$	13,128
Senior notes — Level 3 (2)	1,282		1,297		1,282		1,466

(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. 

The estimated fair value of our 2020 Working Capital Facility approximates the principal amount outstanding because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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Revenues from Contracts with Customers

3 Months Ended

Mar. 31, 2022

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 (in millions):

	Three Months Ended March 31,
	2022		2021
LNG revenues	$	2,488	$	1,669
LNG revenues—affiliate	757		214
Total revenues	$	3,245	$	1,883

Contract Assets and Liabilities

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):

	March 31,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	1	$	1

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

	Three Months Ended March 31, 2022
Deferred revenue, beginning of period	$	132
Cash received but not yet recognized in revenue	94
Revenue recognized from prior period deferral	(132)
Deferred revenue, end of period	$	94

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

	Three Months Ended March 31, 2022
Deferred revenue—affiliate, beginning of period	$	2
Cash received but not yet recognized in revenue	3
Revenue recognized from prior period deferral	(2)
Deferred revenue—affiliate, end of period	$	3

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of March 31, 2022 and December 31, 2021:

	March 31, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	51.2	8	$	49.3	9
LNG revenues—affiliate	2.0		3	2.1		3
Total revenues	$	53.2		$	51.4

(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 67% and 51% of our LNG revenues from contracts included in the table above during the three months ended March 31, 2022 and 2021, respectively, were related to variable consideration received from customers. 100% of our LNG revenues—affiliate from contracts included in the table above during both the three months ended March 31, 2022 and 2021 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

3 Months Ended

Mar. 31, 2022

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 Income (in millions):

	Three Months Ended March 31,
	2022		2021
LNG revenues—affiliate
Cheniere Marketing Agreements	$	745	$	210
Contracts for Sale and Purchase of Natural Gas and LNG	12		4
Total LNG revenues—affiliate	757		214
Cost of sales—affiliate
Cheniere Marketing Agreements	—		34
Cargo loading fees under TUA	13		11
Contracts for Sale and Purchase of Natural Gas and LNG	5		7
Total cost of sales—affiliate	18		52
Operating and maintenance expense—affiliate
TUA	66		66
Natural Gas Transportation Agreement	20		20
Services Agreements	31		27
Total operating and maintenance expense—affiliate	117		113
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		10
General and administrative expense—affiliate
Services Agreements	17		15

As of March 31, 2022 and December 31, 2021, we had $289 million and $232 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.

CQP 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.

Cheniere Marketing Letter Agreements

Cheniere Marketing has letter agreements with us to purchase up to 306 cargoes to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub.

In December 2020, we and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes that were delivered in 2021 at a price of 115% of Henry Hub plus $0.728 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 CQP, 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 March 31, 2022 and December 31, 2021, we recorded due to affiliates of $8 million 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 CQP’s limited partner interests in September 2020. In addition to the amounts recorded on our Statements of Income in the table above, we recorded accrued liabilities—related party of $5 million and $4 million as of March 31, 2022 and December 31, 2021, respectively, with this related party.

Services Agreements

As of March 31, 2022 and December 31, 2021, we had $132 million and $127 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 CQP, 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.

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 did not convey any assets to SPLNG under this agreement during the three months ended March 31, 2022 and 2021.

Contracts for Sale and Purchase of Natural Gas and LNG

We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“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. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreement. The agreement is effective for tax returns due on or after August 2012.

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Customer Concentration

3 Months Ended

Mar. 31, 2022

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 trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, 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 Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended March 31,		March 31,	December 31,
	2022	2021	2022	2021
Customer A	29%	28%	32%	29%
Customer B	14%	15%	15%	*
Customer C	18%	19%	15%	14%
Customer D	15%	15%	17%	17%
Customer E	10%	*	*	13%
Customer F	*	*	*	12%

* Less than 10%

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2022

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2022		2021
Cash paid during the period for interest, net of amounts capitalized	$	130	$	148
Non-cash investing and financing activities:
Property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)	386		222
Novation of IPM agreement from Cheniere Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)	(2,712)		—

Novation of IPM Agreement from CCL Stage III

In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, we and CCL Stage III, a wholly owned subsidiary of Cheniere, entered into an agreement to assign to us an IPM agreement to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023. The transaction has been accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $2.7 billion in distributions within our Statements of Member’s Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $0.1 billion and $2.6 billion, respectively.

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Nature of Operations and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2022

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 in accordance 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, 2021. Reclassifications that are not material to our Financial Statements, if any, are made to prior period financial information to conform to the current year presentation.

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 CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP’s 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

ASU 2020-04

In March 2020, the FASB issued 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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Trade and Other Receivables, Net of Current Expected Credit Losses (Tables)

3 Months Ended

Mar. 31, 2022

Receivables [Abstract]

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

Trade and other receivables, net of current expected credit losses consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Trade receivables	$	411	$	546
Other receivables	19		25
Total trade and other receivables, net of current expected credit losses	$	430	$	571

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Inventory (Tables)

3 Months Ended

Mar. 31, 2022

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Materials	$	74	$	71
LNG	32		44
Natural gas	25		43
Other	1		1
Total inventory	$	132	$	159

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

3 Months Ended

Mar. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
LNG terminal
LNG terminal	$	16,195	$	13,751
LNG terminal construction-in-process	492		2,699
Accumulated depreciation	(2,149)		(2,021)
Total LNG terminal, net of accumulated depreciation	14,538		14,429
Fixed assets
Fixed assets	18		19
Accumulated depreciation	(16)		(15)
Total fixed assets, net of accumulated depreciation	2		4
Property, plant and equipment, net of accumulated depreciation	$	14,540	$	14,433

Schedule of Depreciation and Offsets to LNG Terminal Costs

The following table shows depreciation expense and offsets to LNG terminal costs (in millions):

	Three Months Ended March 31,
	2022		2021
Depreciation expense	$	129	$	116
Offsets to LNG terminal costs (1)	148		—

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2022

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 (in millions):

	Fair Value Measurements as of
	March 31, 2022								December 31, 2021
	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)	$	(26)	$	(13)	$	(3,162)	$	(3,201)	$	2	$	(13)	$	38	$	27

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 March 31, 2022:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(3,162)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.578) - $0.215 / $(0.004)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	104% - 459% / 206%

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

(2)Spread contemplates U.S. dollar-denominated pricing.

Fair Value, Liabilities 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 (in millions):

	Three Months Ended March 31,
	2022		2021
Balance, beginning of period	$	38	$	(21)
Realized and mark-to-market gains losses:
Included in cost of sales	(53)		(12)
Purchases and settlements:
Purchases (1)	(3,141)		1
Settlements	(6)		(4)
Balance, end of period	$	(3,162)	$	(36)
Change in unrealized losses relating to instruments still held at end of period	$	(53)	$	(12)

(1)Includes any assignments during the period.

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	March 31, 2022		December 31, 2021
Current derivative assets	$	24	$	21
Derivative assets	30		33
Total derivative assets	54		54
Current derivative liabilities	(256)		(16)
Derivative liabilities	(2,999)		(11)
Total derivative liabilities	(3,255)		(27)
Derivative asset (liability), net	$	(3,201)	$	27

(1)Does not include collateral posted with counterparties by us of $32 million and $7 million, which are included in other current assets in our Balance Sheets as of March 31, 2022 and December 31, 2021, respectively.

Derivative Instruments, Gain (Loss)

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Income (in millions):

	Loss Recognized in Statements of Income
Statements of Income Location (1)	Three Months Ended March 31,
	2022		2021
Cost of sales	$	(525)	$	(2)

(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 March 31, 2022
Gross assets	$	74
Offsetting amounts	(20)
Net assets	$	54
Gross liabilities	$	(3,266)
Offsetting amounts	11
Net liabilities	$	(3,255)
As of December 31, 2021
Gross assets	$	79
Offsetting amounts	(25)
Net assets	$	54
Gross liabilities	$	(33)
Offsetting amounts	6
Net liabilities	$	(27)

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Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2022

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Accrued natural gas purchases	$	692	$	786
Interest costs and related debt fees	156		133
Liquefaction Project costs	230		89
Other accrued liabilities	4		4
Total accrued liabilities	$	1,082	$	1,012

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Debt (Tables)

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Schedule of Debt Instruments

Our debt consisted of the following (in millions):

	March 31,		December 31,
	2022		2021
Senior Secured Notes:
5.625% due 2023	$	1,500	$	1,500
5.75% due 2024	2,000		2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.27% weighted average rate due 2037	1,282		1,282
Total Senior Secured Notes	13,132		13,132
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”)	—		—
Total debt	13,132		13,132
Unamortized premium, discount and debt issuance costs, net	(103)		(109)
Total debt, net of premium, discount and debt issuance costs	$	13,029	$	13,023

Schedule of Line of Credit Facilities

Below is a summary of our 2020 Working Capital Facility as of March 31, 2022 (in millions):

	2020 Working Capital Facility
Original facility size	$	1,200
Less:
Outstanding balance	—
Letters of credit issued	368
Available commitment	$	832
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
Commitment fees on undrawn balance	0.20%
Maturity date	March 19, 2025

Schedule of Interest Expense

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

	Three Months Ended March 31,
	2022		2021
Total interest cost	$	177	$	190
Capitalized interest	(21)		(30)
Total interest expense, net of capitalized interest	$	156	$	160

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	March 31, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	11,850	$	12,447	$	11,850	$	13,128
Senior notes — Level 3 (2)	1,282		1,297		1,282		1,466

(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.

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Revenues from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table represents a disaggregation of revenue earned from contracts with customers (in millions):

	Three Months Ended March 31,
	2022		2021
LNG revenues	$	2,488	$	1,669
LNG revenues—affiliate	757		214
Total revenues	$	3,245	$	1,883

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):

	March 31,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	1	$	1

Contract Balances Reconciliation

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

	Three Months Ended March 31, 2022
Deferred revenue, beginning of period	$	132
Cash received but not yet recognized in revenue	94
Revenue recognized from prior period deferral	(132)
Deferred revenue, end of period	$	94

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

	Three Months Ended March 31, 2022
Deferred revenue—affiliate, beginning of period	$	2
Cash received but not yet recognized in revenue	3
Revenue recognized from prior period deferral	(2)
Deferred revenue—affiliate, end of period	$	3

Transaction Price Allocated to Future Performance Obligations

The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of March 31, 2022 and December 31, 2021:

	March 31, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	51.2	8	$	49.3	9
LNG revenues—affiliate	2.0		3	2.1		3
Total revenues	$	53.2		$	51.4

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

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2022

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary of our related party transactions as reported on our Statements of Income (in millions):

	Three Months Ended March 31,
	2022		2021
LNG revenues—affiliate
Cheniere Marketing Agreements	$	745	$	210
Contracts for Sale and Purchase of Natural Gas and LNG	12		4
Total LNG revenues—affiliate	757		214
Cost of sales—affiliate
Cheniere Marketing Agreements	—		34
Cargo loading fees under TUA	13		11
Contracts for Sale and Purchase of Natural Gas and LNG	5		7
Total cost of sales—affiliate	18		52
Operating and maintenance expense—affiliate
TUA	66		66
Natural Gas Transportation Agreement	20		20
Services Agreements	31		27
Total operating and maintenance expense—affiliate	117		113
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	12		10
General and administrative expense—affiliate
Services Agreements	17		15

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Customer Concentration (Tables)

3 Months Ended

Mar. 31, 2022

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 trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, 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 Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended March 31,		March 31,	December 31,
	2022	2021	2022	2021
Customer A	29%	28%	32%	29%
Customer B	14%	15%	15%	*
Customer C	18%	19%	15%	14%
Customer D	15%	15%	17%	17%
Customer E	10%	*	*	13%
Customer F	*	*	*	12%

* Less than 10%

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2022

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Three Months Ended March 31,
	2022		2021
Cash paid during the period for interest, net of amounts capitalized	$	130	$	148
Non-cash investing and financing activities:
Property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)	386		222
Novation of IPM agreement from Cheniere Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)	(2,712)		—

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Organization and Nature of Operations (Details)	3 Months Ended
	Mar. 31, 2022 milliontonnes / yr members trains
Nature of Operations and Basis of Presentation [Line Items]
Limited Liability Company (LLC) Number Of Members | members	1
Cheniere Energy Partners, LP | Cheniere [Member]
Nature of Operations and Basis of Presentation [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	48.60%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	100.00%
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains Operating | trains	6
Total Production Capability | milliontonnes / yr	30

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Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 136	$ 98
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 136	$ 98

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Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Receivables [Abstract]
Trade receivables	$ 411	$ 546
Other receivables	19	25
Total trade and other receivables, net of current expected credit losses	$ 430	$ 571

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Inventory (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Inventory [Line Items]
Inventory	$ 132	$ 159
Materials [Member]
Inventory [Line Items]
Inventory	74	71
LNG [Member]
Inventory [Line Items]
Inventory	32	44
Natural gas [Member]
Inventory [Line Items]
Inventory	25	43
Other [Member]
Inventory [Line Items]
Inventory	$ 1	$ 1

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 14,540	$ 14,433
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(2,149)	(2,021)
Property, plant and equipment, net of accumulated depreciation	14,538	14,429
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	16,195	13,751
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	492	2,699
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	18	19
Accumulated depreciation	(16)	(15)
Property, plant and equipment, net of accumulated depreciation	$ 2	$ 4

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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
		Mar. 31, 2022	Mar. 31, 2021
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 129	$ 116
Offsets to LNG terminal costs	[1]	$ 148	$ 0

[1] We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

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Derivative Instruments - Narrative (Details) - tbtu	3 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	5,550	5,194
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	15 years
Financial Liquefaction Supply Derivatives | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	2 years

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (3,201)	$ 27
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	(26)	2
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	(13)	(13)
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	$ (3,162)	$ 38

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - USD ($)		3 Months Ended
		Mar. 31, 2022	Dec. 31, 2021
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		$ (3,201,000,000)	$ 27,000,000
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		(3,162,000,000)	$ 38,000,000
Physical Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		(3,162,000,000)
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Market Approach
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	[1]	$ (1.578)
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation Technique, Option Pricing Model
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	104.00%
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Market Approach
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	[1]	$ 0.215
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation Technique, Option Pricing Model
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	459.00%
Physical Liquefaction Supply Derivatives [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Market Approach
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	[1]	$ (0.004)
Physical Liquefaction Supply Derivatives [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation Technique, Option Pricing Model
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	206.00%

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

[2] Spread contemplates U.S. dollar-denominated pricing.

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Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2022	Mar. 31, 2021
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ 38	$ (21)
Realized and mark-to-market losses:
Included in cost of sales		(53)	(12)
Purchases and settlements:
Purchases	[1]	(3,141)	1
Settlements		(6)	(4)
Balance, end of period		(3,162)	(36)
Change in unrealized losses relating to instruments still held at end of period		$ (53)	$ (12)

[1] Includes any assignments during the period.

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Mar. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Current derivative assets		$ 24	$ 21
Derivative assets		30	33
Total derivative assets	[1]	54	54
Current derivative liabilities		(256)	(16)
Derivative liabilities		(2,999)	(11)
Total derivative liabilities	[1]	(3,255)	(27)
Derivative asset (liability), net	[1]	(3,201)	27
Derivative, collateral posted by us		32	7
Current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[1]	24	21
Derivative assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	30	33
Current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities	[1]	(256)	(16)
Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	$ (2,999)	$ (11)

[1] Does not include collateral posted with counterparties by us of $32 million and $7 million, which are included in other current assets in our Balance Sheets as of March 31, 2022 and December 31, 2021, respectively.

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Derivative Instruments - Derivative Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2022	Mar. 31, 2021
Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative loss, net	[1]	$ (525)	$ (2)

[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	Mar. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Net Amounts Presented in our Balance Sheets	$ (3,201)	$ 27
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	74	79
Derivative Asset, Gross Amounts Offset in the Balance Sheets	(20)	(25)
Net Amounts Presented in our Balance Sheets	54	54
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(3,266)	(33)
Derivative Liability, Gross Amounts Offset in the Balance Sheets	11	6
Net Amounts Presented in our Balance Sheets	$ (3,255)	$ (27)

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Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Accrued Liabilities, Current [Abstract]
Accrued natural gas purchases	$ 692	$ 786
Interest costs and related debt fees	156	133
Liquefaction Project costs	230	89
Other accrued liabilities	4	4
Total accrued liabilities	$ 1,082	$ 1,012

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 13,132	$ 13,132
Unamortized premium, discount and debt issuance costs, net	(103)	(109)
Total debt, net of premium, discount and debt issuance costs	13,029	13,023
Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	13,132	13,132
2023 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2024 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%
2025 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2026 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2028 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,350	1,350
Debt Instrument, Interest Rate, Stated Percentage	4.20%
2030 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage	4.50%
2037 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,282	1,282
2037 Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.27%
2020 Working Capital Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	$ 0
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,200

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Debt - Credit Facilities (Details) $ in Millions	3 Months Ended
	Mar. 31, 2022 USD ($) unit Rate	Dec. 31, 2021 USD ($)
Line of Credit Facility [Line Items]
Outstanding balance	$ 13,132	$ 13,132
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio | unit	1.25
2020 Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	$ 1,200
Outstanding balance	0	$ 0
Letters of credit issued	368
Available commitment	$ 832
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Line of Credit Facility, Commitment Fee Percentage	0.20%
Debt Instrument, Maturity Date	Mar. 19, 2025
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 | Rate	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 | Rate	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 | Rate	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 | Rate	0.75%

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Debt Disclosure [Abstract]
Total interest cost	$ 177	$ 190
Capitalized interest	(21)	(30)
Total interest expense, net of capitalized interest	$ 156	$ 160

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - Senior Notes [Member] - USD ($) $ in Millions		Mar. 31, 2022	Dec. 31, 2021
Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[1]	$ 11,850	$ 11,850
Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[2]	1,282	1,282
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]	12,447	13,128
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]	$ 1,297	$ 1,466

[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.

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Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Disaggregation of Revenue [Line Items]
Revenues	$ 3,245	$ 1,883
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,488	1,669
Revenues	2,488	1,669
LNG—affiliate
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 757	$ 214

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Revenues from Contracts with Customers - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 1	$ 1
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	132
Cash received but not yet recognized in revenue	94
Revenue recognized from prior period deferral	(132)
Deferred revenue, end of period	94
Deferred revenue, beginning of period	2
Cash received but not yet recognized in revenue	3
Revenue recognized from prior period deferral	(2)
Deferred revenue, end of period	$ 3

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Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		3 Months Ended
		Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price				$ 51.4
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 53.2
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		67.00%	51.00%
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price				$ 49.3
Weighted Average Recognition Timing	[1]			9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 51.2
Weighted Average Recognition Timing	[1]	8 years
LNG—affiliate
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		100.00%	100.00%
LNG—affiliate | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price				$ 2.1
Weighted Average Recognition Timing	[1]			3 years
LNG—affiliate | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 2.0
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
	Mar. 31, 2022	Mar. 31, 2021
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 757	$ 214
Cost of sales—affiliate	18	52
Operating and maintenance expense—affiliate	117	113
Operating and maintenance expense—related party	12	10
General and administrative expense—affiliate	17	15
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	745	210
Cost of sales—affiliate	0	34
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	12	4
Cost of sales—affiliate	5	7
Terminal Use Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—affiliate	13	11
Operating and maintenance expense—affiliate	66	66
Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	20	20
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—related party	12	10
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	31	27
General and administrative expense—affiliate	$ 17	$ 15

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Related Party Transactions - Narrative (Details)	3 Months Ended
	Mar. 31, 2022 USD ($) bcf / d Cargo item	Dec. 31, 2021 USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate	$ 289,000,000	$ 232,000,000
Due to affiliates	35,000,000	73,000,000
Accrued liabilities—related party	5,000,000	4,000,000
Advances to affiliate	$ 132,000,000	127,000,000
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	4,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to affiliate	$ 132,000,000	127,000,000
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
Review Period for Inflation Adjustment	5 years
SPLNG [Member] | Cooperation Agreement [Member]
Related Party Transaction [Line Items]
Assets conveyed under the agreement	$ 0
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
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] | 2022-2027 Letter Agreement
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Weighted Average Purchase Price Per MMBtu	$ 1.95
Cheniere Marketing [Member] | 2022-2027 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	306
Cheniere Marketing [Member] | 2021 Letter Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price	$ 0.728
Cheniere Marketing [Member] | 2021 Letter Agreement [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	30
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
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	$ 8,000,000	$ 8,000,000

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Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	3 Months Ended		12 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	29.00%	28.00%
Customer A [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	32.00%		29.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	14.00%	15.00%
Customer B [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	19.00%
Customer C [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%		14.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%	15.00%
Customer D [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%		17.00%
Customer E [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Customer E [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			13.00%
Customer F [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			12.00%

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Supplemental Cash Flow Information (Details) - USD ($)		3 Months Ended
	Mar. 15, 2022	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized		$ 130,000,000	$ 148,000,000
Balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)		386,000,000	222,000,000
Novation of IPM agreement from Cheniere Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)		(2,712,000,000)	$ 0
Nonmonetary Transaction [Line Items]
Partners Capital Account Distributions, Non-Cash		2,712,000,000
Current derivative liabilities		256,000,000		$ 16,000,000
Derivative liabilities		$ 2,999,000,000		$ 11,000,000
Novation of IPM Agreement | Cheniere Corpus Christi Liquefaction Stage III
Nonmonetary Transaction [Line Items]
Contract Volume		140,000
IPM Agreement, Term of Agreement		15 years
Partners Capital Account Distributions, Non-Cash	$ 2,700,000,000
Current derivative liabilities	100,000,000
Derivative liabilities	$ 2,600,000,000