Sabine Pass Liquefaction 10-K 24 Feb 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2021USD ($)shares
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Document Transition Report	false
Entity File Number	333-192373
Entity Registrant Name	Sabine Pass Liquefaction, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	27-3235920
Entity Address, Address Line One	700 Milam Street
Entity Address, Address Line Two	Suite 1900
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	375-5000
Title of 12(b) Security	None
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
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
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float | $	$ 0
Documents Incorporated by Reference	None
Entity Central Index Key	0001499200
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
No Trading Symbol Flag	true
Entity Common Stock, Shares Outstanding | shares	0

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	Houston, Texas
Auditor Firm ID	185

Statements of Income

Statements of Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues
Revenues		$ 9,112	$ 5,857	$ 6,523
Revenues from contracts with customers		9,113	5,857	6,522
Operating costs and expenses
Cost of sales (excluding items shown separately below)		5,289	2,504	3,373
Cost of sales—affiliate		128	110	47
Cost of sales—related party		17	0	0
Operating and maintenance expense		548	547	547
Operating and maintenance expense—affiliate		457	466	450
Operating and maintenance expense—related party		46	13	0
General and administrative expense		4	9	6
General and administrative expense—affiliate		61	71	79
Depreciation and amortization expense		468	465	447
Impairment expense and loss on disposal of assets		6	1	6
Total operating costs and expenses		7,024	4,186	4,955
Income from operations		2,088	1,671	1,568
Other income (expense)
Interest expense, net of capitalized interest		(622)	(685)	(705)
Loss on modification or extinguishment of debt		(5)	(43)	0
Other income, net		0	0	10
Total other expense		(627)	(728)	(695)
Net income		1,461	943	873
LNG [Member]
Revenues
Revenues		7,639	5,195	5,211
Revenues from contracts with customers	[1]	7,640	5,195	5,210
LNG—affiliate
Revenues
Revenues from contracts with customers		1,472	662	1,312
LNG—related party [Member]
Revenues
Revenues from contracts with customers		$ 1	$ 0	$ 0
[1]	LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2021 and 2019. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

Balance Sheets

Balance Sheets - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current assets
Restricted cash and cash equivalents	$ 98	$ 97
Accounts and other receivables, net of current expected credit losses	571	309
Accounts receivable—affiliate	232	185
Accounts receivable—related party	1	0
Advances to affiliate	127	122
Inventory	159	93
Current derivative assets	21	14
Other current assets	60	41
Other current assets—affiliate	21	21
Total current assets	1,290	882
Property, plant and equipment, net of accumulated depreciation	14,433	14,255
Debt issuance costs, net of accumulated amortization	7	10
Derivative assets	33	11
Other non-current assets, net	171	165
Total assets	15,934	15,323
Current liabilities
Accounts payable	18	8
Accrued liabilities	1,012	591
Accrued liabilities—related party	4	4
Due to affiliates	73	59
Deferred revenue	132	114
Current derivative liabilities	16	11
Total current liabilities	1,255	787
Long-term debt, net of premium, discount and debt issuance costs	13,023	13,520
Derivative liabilities	11	35
Other non-current liabilities	7	8
Other non-current liabilities—affiliate	17	15
Commitments and Contingencies
Member’s equity	1,621	958
Total liabilities and member’s equity	$ 15,934	$ 15,323

Statements of Member's Equity

Statements of Member's Equity - USD ($) $ in Millions	Total	Sabine Pass LNG-LP, LLC [Member]
Members' equity, beginning of period at Dec. 31, 2018	$ 466	$ 466
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	1,046	1,046
Distributions	(1,851)	(1,851)
Net income	873	873
Member's equity, end of period at Dec. 31, 2019	534	534
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	488	488
Distributions	(1,007)	(1,007)
Net income	943	943
Member's equity, end of period at Dec. 31, 2020	958	958
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	821	821
Distributions	(1,619)	(1,619)
Net income	1,461	1,461
Member's equity, end of period at Dec. 31, 2021	$ 1,621	$ 1,621

Statements of Cash Flows

Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities
Net income	$ 1,461	$ 943	$ 873
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	468	465	447
Amortization of debt issuance costs, premium and discount	22	24	27
Loss on modification of debt	5	43	0
Total losses (gains) on derivatives, net	(29)	49	(72)
Total gains on derivatives, net—related party	(2)	0	0
Net cash provided by (used for) settlement of derivative instruments	(17)	(4)	5
Impairment expense and loss on disposal of assets	6	1	6
Changes in operating assets and liabilities:
Accounts and other receivables, net of current expected credit losses	(203)	(17)	19
Accounts receivable—affiliate	(32)	(80)	9
Accounts receivable—related party	(1)	0	0
Advances to affiliate	(5)	5	(34)
Inventory	(66)	9	(16)
Accounts payable and accrued liabilities	326	2	(138)
Accrued liabilities—related party	(1)	4	0
Due to affiliates	(1)	9	8
Deferred revenue	18	(18)	40
Deferred revenue—affiliate	0	(10)	(13)
Other, net	(14)	(1)	0
Other, net—affiliate	2	0	0
Net cash provided by operating activities	1,937	1,424	1,161
Cash flows from investing activities
Property, plant and equipment	(612)	(916)	(1,282)
Other	0	0	(1)
Net cash used in investing activities	(612)	(916)	(1,283)
Cash flows from financing activities
Proceeds from issuances of debt	482	1,995	0
Redemptions and repayments of debt	(1,000)	(2,000)	0
Debt issuance and other financing costs	(5)	(35)	0
Debt extinguishment costs	(3)	(39)	0
Capital contributions	821	488	1,046
Distributions	(1,619)	(1,001)	(1,499)
Net cash used in financing activities	(1,324)	(592)	(453)
Net increase (decrease) in restricted cash and cash equivalents	1	(84)	(575)
Restricted cash and cash equivalents—beginning of period	97	181	756
Restricted cash and cash equivalents—end of period	$ 98	$ 97	$ 181

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	ORGANIZATION AND NATURE OF OPERATIONS 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 Sabine Pass LNG terminal currently has six operational natural gas liquefaction 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Our Financial Statements have been prepared in accordance with GAAP. When necessary, reclassifications that are not material to our Financial Statements are made to prior period financial information to conform to the current year presentation. Use of 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. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment and asset retirement obligations (“AROs”) as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market. In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates. Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments . The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt , are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Revenue Recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 11—Revenues from Contracts with Customers for further discussion of our revenue streams and accounting policies related to revenue recognition. Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. Accounts and Other Receivables Accounts and other receivables are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Statements of Income. As of both December 31, 2021 and 2020, we had current expected credit losses on our accounts and other receivables of $5 million. Inventory LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or capitalized to property, plant and equipment when issued, primarily using the weighted average method. Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train. Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives. Refer to Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets. Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We recorded $5 million of impairments related to property, plant and equipment during the year ended December 31, 2021. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2020 and 2019. Interest Capitalization We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset. Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis. Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2021, 2020 and 2019. See Note 7—Derivative Instruments for additional details about our derivative instruments. Concentration of Credit Risk Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments. We have entered into fixed price long-term SPAs generally with terms of 20 years with eight third parties and have entered into agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 14—Customer Concentration for additional details about our customer concentration. Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Debt Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors. Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in loss on modification or extinguishment of debt on our Statements of Income. We classify debt on our Balance Sheets based on contractual maturity, with the following exceptions: • We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement. • We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date. Asset Retirement Obligations We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial. Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss 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 taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2021, the tax basis of our assets and liabilities was $7.2 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our tax sharing agreement. Business Segment Our liquefaction operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of SPL in total when evaluating financial performance and for purposes of allocating resources. Recent Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting . This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

Restricted Cash and Cash Equiva

Restricted Cash and Cash Equivalents	12 Months Ended
	Dec. 31, 2021
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 and have been presented separately from cash and cash equivalents on our Balance Sheets. As of December 31, 2021 and 2020, we had $98 million and $97 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.

Accounts and Other Receivables,

Accounts and Other Receivables, Net of Current Expected Credit Losses	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
Accounts and Other Receivables, Net of Current Expected Credit Losses	ACCOUNTS AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES As of December 31, 2021 and 2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions): December 31, 2021 2020 Trade receivable $ 546 $ 300 Other accounts receivable 25 9 Total accounts and other receivables, net of current expected credit losses $ 571 $ 309

Inventory

Inventory	12 Months Ended
	Dec. 31, 2021
Inventory Disclosure [Abstract]
Inventory	INVENTORY As of December 31, 2021 and 2020, inventory consisted of the following (in millions): December 31, 2021 2020 Materials $ 71 $ 68 LNG 44 8 Natural gas 43 17 Other 1 — Total inventory $ 159 $ 93

Property, Plant and Equipment,

Property, Plant and Equipment, Net of Accumulated Depreciation	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net of Accumulated Depreciation	PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION As of December 31, 2021 and 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions): December 31, 2021 2020 LNG terminal LNG terminal $ 13,751 $ 13,711 LNG terminal construction-in-process 2,699 2,100 Accumulated depreciation (2,021) (1,561) Total LNG terminal, net of accumulated depreciation 14,429 14,250 Fixed assets Fixed assets 19 19 Accumulated depreciation (15) (14) Total fixed assets, net of accumulated depreciation 4 5 Property, plant and equipment, net of accumulated depreciation $ 14,433 $ 14,255 The following table shows depreciation expense and offsets to LNG terminal costs during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 Depreciation expense $ 463 $ 460 $ 442 Offsets to LNG terminal costs (1) 105 — 48 (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. LNG Terminal Costs LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and 50 years, as follows: Components Useful life (years) Water pipelines 30 Liquefaction processing equipment 6-50 Other 10-30 Fixed Assets Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	DERIVATIVE INSTRUMENTS We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”). We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Statements of Operations to the extent not utilized for the commissioning process, in which case it is capitalized. The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2021 and 2020 (in millions): Fair Value Measurements as of December 31, 2021 December 31, 2020 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Liquefaction Supply Derivatives asset (liability) $ 2 $ (13) $ 38 $ 27 $ 1 $ (1) $ (21) $ (21) We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data. The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value. We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration. The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2021: Net Fair Value Asset Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1) Physical Liquefaction Supply Derivatives $38 Market approach incorporating present value techniques Henry Hub basis spread $(1.368) - $0.250 / $0.012 (1) Unobservable inputs were weighted by the relative fair value of the instruments. Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives. The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 Balance, beginning of period $ (21) $ 24 $ (25) Realized and mark-to-market gains (losses): Included in cost of sales 74 (43) 6 Purchases and settlements: Purchases (10) 5 — Settlements (5) (7) 42 Transfers out of Level 3, net (1) — — 1 Balance, end of period $ 38 $ (21) $ 24 Change in unrealized gain (loss) relating to instruments still held at end of period $ 74 $ (43) $ 6 (1) Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements. All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees. Liquefaction Supply Derivatives We have entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 5,194 TBtu and 4,970 TBtu as of December 31, 2021 and 2020, respectively. 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 December 31, 2021 December 31, 2020 Current derivative assets $ 21 $ 14 Derivative assets 33 11 Total derivative assets 54 25 Current derivative liabilities (16) (11) Derivative liabilities (11) (35) Total derivative liabilities (27) (46) Derivative asset (liability), net $ 27 $ (21) (1) Does not include collateral posted with counterparties by us of $7 million and $4 million, which are included in other current assets in our Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract that we had with a related party, which had a fair value of zero as of December 31, 2020. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12—Related Party Transactions . The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions): Gain (Loss) Recognized in Statements of Operations Statements of Operations Location (1) Year Ended December 31, 2021 2020 2019 LNG revenues $ (1) $ — $ 1 Cost of sales 30 (49) 71 Cost of sales—related party (2) 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. (2) Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 1 2 —Related Party Transactions . 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 December 31, 2021 Gross assets $ 79 Offsetting amounts (25) Net assets $ 54 Gross liabilities $ (33) Offsetting amounts 6 Net liabilities $ (27) As of December 31, 2020 Gross assets $ 69 Offsetting amounts (44) Net assets $ 25 Gross liabilities $ (48) Offsetting amounts 2 Net liabilities $ (46)

Other Non-Current Assets, Net

Other Non-Current Assets, Net	12 Months Ended
	Dec. 31, 2021
Other Assets, Noncurrent [Abstract]
Other Non-Current Assets, Net	OTHER NON-CURRENT ASSETS, NET As of December 31, 2021 and 2020, other non-current assets, net consisted of the following (in millions): December 31, 2021 2020 Advances made to municipalities for water system enhancements $ 81 $ 84 Advances and other asset conveyances to third parties to support LNG terminal 37 33 Operating lease assets 23 23 Advances made under EPC and non-EPC contracts 5 9 Information technology service prepayments 4 5 Other 21 11 Total other non-current assets, net $ 171 $ 165

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2021
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	ACCRUED LIABILITIES As of December 31, 2021 and 2020, accrued liabilities consisted of the following (in millions): December 31, 2021 2020 Accrued natural gas purchases $ 786 $ 374 Interest costs and related debt fees 133 150 Liquefaction Project costs 89 64 Other accrued liabilities 4 3 Total accrued liabilities $ 1,012 $ 591

Debt

Debt	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Debt	DEBT As of December 31, 2021 and 2020, our debt consisted of the following (in millions): December 31, 2021 2020 Senior Secured Notes: 6.25% due 2022 $ — $ 1,000 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 1,282 800 Total Senior Secured Notes 13,132 13,650 $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”) — — Total debt 13,132 13,650 Unamortized premium, discount and debt issuance costs, net (109) (130) Total debt, net of premium, discount and debt issuance costs $ 13,023 $ 13,520 Senior Secured Notes The Senior Secured Notes are our senior secured obligations, ranking equally in right of payment with our other existing and future senior debt and secured by the same collateral and senior in right of payment to any of its future subordinated debt. Subject to permitted liens, the Senior Secured Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in us and substantially all of our assets. We may, at any time, redeem all or part of the Senior Secured Notes at specified prices set forth in the respective indentures governing the Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. The series of Senior Secured Notes due in 2037 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures. Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2021 (in millions): Years Ending December 31, Principal Payments 2022 $ — 2023 1,500 2024 2,000 2025 2,037 2026 1,579 Thereafter 6,016 Total $ 13,132 2020 Working Capital Facility Below is a summary of our 2020 Working Capital Facility as of December 31, 2021 (in millions): 2020 Working Capital Facility (1) Original facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 395 Available commitment $ 805 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 (1) Our obligations under the 2020 Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu basis by a first priority lien with the Senior Secured Notes. 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 December 31, 2021, we were in compliance with all covenants related to our debt agreements. Interest Expense Total interest expense, net of capitalized interest consisted of the following (in millions): Year Ended December 31, 2021 2020 2019 Total interest cost $ 754 $ 779 $ 790 Capitalized interest (132) (94) (85) Total interest expense, net of capitalized interest $ 622 $ 685 $ 705 Fair Value Disclosures The following table shows the carrying amount and estimated fair value of our debt (in millions): December 31, 2021 December 31, 2020 Carrying Estimated Carrying Estimated Senior notes — Level 2 (1) $ 11,850 $ 13,128 $ 12,850 $ 14,834 Senior notes — Level 3 (2) 1,282 1,466 800 1,036 Working capital facility — Level 3 (3) — — — — (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

Revenues from Contracts with Cu

Revenues from Contracts with Customers	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Revenues from Contracts with Customers	REVENUES FROM CONTRACTS WITH CUSTOMERS The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 LNG revenues (1) $ 7,640 $ 5,195 $ 5,210 LNG revenues—affiliate 1,472 662 1,312 LNG revenues—related party 1 — — Total revenues from customers 9,113 5,857 6,522 Net derivative gain (loss) (2) (1) — 1 Total revenues $ 9,112 $ 5,857 $ 6,523 (1) LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2021 and 2019. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. (2) See Note 7—Derivative Instruments for additional information about our derivatives. LNG Revenues We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 12—Related Party Transactions for additional information regarding these agreements. Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price. Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use. 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): December 31, 2021 2020 Contract assets, net of current expected credit losses $ 1 $ — Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the year ended December 31, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due. The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions): Year Ended December 31, 2021 Deferred revenue, beginning of period $ 114 Cash received but not yet recognized in revenue 132 Revenue recognized from prior period deferral (114) Deferred revenue, end of period $ 132 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): Year Ended December 31, 2021 Deferred revenue—affiliate, beginning of period $ — Cash received but not yet recognized in revenue 2 Deferred revenue—affiliate, end of period $ 2 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 December 31, 2021 and 2020: December 31, 2021 December 31, 2020 Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) LNG revenues $ 49.3 9 $ 52.1 9 LNG revenues—affiliate 2.1 3 0.1 1 Total revenues $ 51.4 $ 52.2 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price. We have elected the following exemptions which omit certain potential future sources of revenue from the table above: (1) We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less. (2) The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 61% and 42% of our LNG revenues from contracts included in the table above during the years ended December 31, 2021 and 2020, respectively, were related to variable consideration received from customers. Approximately 96% and 100% of our LNG revenues—affiliate from contracts included in the table above during the years ended December 31, 2021 and 2020, respectively, 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.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS Below is a summary of our related party transactions as reported on our Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 LNG revenues—affiliate Cheniere Marketing Agreements $ 1,453 $ 632 $ 1,309 Contracts for Sale and Purchase of Natural Gas and LNG 19 30 3 Total LNG revenues—affiliate 1,472 662 1,312 LNG revenues—related party Natural Gas Transportation and Storage Agreements 1 — — Cost of sales—affiliate Cheniere Marketing Agreements 34 61 — Cargo loading fees under TUA 43 33 40 Contracts for Sale and Purchase of Natural Gas and LNG 51 16 7 Total cost of sales—affiliate 128 110 47 Cost of sales—related party Natural Gas Transportation and Storage Agreements 1 — — Natural Gas Supply Agreements (1) 16 — — Total cost of sales—related party 17 — — Operating and maintenance expense—affiliate TUA 266 265 261 Natural Gas Transportation Agreement 81 82 81 Services Agreements 109 118 107 LNG Site Sublease Agreement 1 1 1 Total operating and maintenance expense—affiliate 457 466 450 Operating and maintenance expense—related party Natural Gas Transportation and Storage Agreements 46 13 — General and administrative expense—affiliate Services Agreements 61 71 79 (1) Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed below. As of December 31, 2021 and 2020, we had $232 million and $185 million, respectively, of accounts receivable—affiliate under the agreements described below. LNG Terminal-Related Agreements Terminal Use Agreements We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. 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. In December 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes that were delivered in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu. In May 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu that were delivered between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 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 December 31, 2021 and 2020, we recorded due to affiliates of $8 million and $6 million, respectively, related to this agreement. We are also party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by the investment management company that indirectly acquired a portion of CQP’s limited partner interests in September 2020. In addition to the amounts recorded on our Statements of Operations in the table above, we recorded accrued liabilities—related party of $4 million as of both December 31, 2021 and 2020 with this related party. Services Agreements As of December 31, 2021 and 2020, we had $127 million and $122 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate. Cheniere Investments Information Technology Services Agreement Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement. Liquefaction O&M Agreement We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of 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. Natural Gas Supply Agreement We were a party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party was partially owned by Blackstone, who also partially owns CQP’s limited partner interests. However, this entity was acquired by a non-related party on December 31, 2021; therefore, as of such date, this agreement ceased to be considered a related party agreement. LNG Site Sublease Agreement We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple periods of 10 years with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements. Cooperation Agreement We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We conveyed $6 million in assets to SPLNG under this agreement during the year ended December 31, 2020. We did not convey any assets to SPLNG under this agreement during the year ended December 31, 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. There have been no state and local taxes paid by Cheniere and Cheniere has not demanded any such payments from us under the agreement. The agreement is effective for tax returns due on or after August 2012.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain unconditional purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2021, are not recognized as liabilities but require disclosures in our Financial Statements. LNG Terminal Commitments and Contingencies EPC Contract We have a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the EPC of Train 6 of the Liquefaction Project. The total contract price of the EPC contract for Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction is approximately $2.5 billion, reflecting amounts incurred under change orders through December 31, 2021. As of December 31, 2021, we had approximately $0.2 billion remaining under this contract. Natural Gas Supply, Transportation and Storage Service Agreements We have physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 10 years. Additionally, we have natural gas transportation and storage service agreements for the Liquefaction Project. The initial term of the natural gas transportation agreements range up to 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The initial terms of our natural gas storage service agreements range up to 10 years. As of December 31, 2021, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in billions): Years Ending December 31, Payments Due (1) 2022 $ 5.3 2023 3.7 2024 2.6 2025 1.7 2026 1.1 Thereafter 5.7 Total $ 20.1 (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread . Amounts included are based on estimated forward prices and basis spreads as of December 31, 2021. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services. LNG TUAs We have a TUA with SPLNG pursuant to which we have reserved approximately 2 Bcf/d of regasification capacity. See Note 12—Related Party Transactions for additional information regarding this TUA. Additionally, we have a partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 5, we gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. Services Agreements We have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements. Environmental and Regulatory Matters The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows. Legal Proceedings

Customer Concentration

Customer Concentration	12 Months Ended
	Dec. 31, 2021
Risks and Uncertainties [Abstract]
Customer Concentration	CUSTOMER CONCENTRATION The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivable, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivable, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively: Percentage of Total Revenues from External Customers Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers Year Ended December 31, December 31, 2021 2020 2019 2021 2020 Customer A 25% 25% 29% 29% 32% Customer B 18% 19% 21% 17% 22% Customer C 17% 18% 21% * * Customer D 16% 16% 19% 14% 21% Customer E 10% * * 13% * Customer F * * * 12% * * Less than 10% The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States. Revenues from External Customers Year Ended December 31, 2021 2020 2019 United States $ 2,550 $ 1,975 $ 1,854 India 1,342 970 1,113 South Korea 1,336 924 1,071 Ireland 1,237 842 989 United Kingdom 966 456 184 Other countries 208 28 — Total $ 7,639 $ 5,195 $ 5,211

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	SUPPLEMENTAL CASH FLOW INFORMATION The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2021 2020 2019 Cash paid during the period for interest, net of amounts capitalized $ 615 $ 692 $ 678 Non-cash distributions to affiliates for conveyance of assets — 6 351 Right-of-use assets obtained in exchange for new operating lease liabilities — 3 — The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $322 million, $207 million and $276 million as of December 31, 2021, 2020 and 2019, respectively.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Basis of Presentation, Policy	Basis of Presentation Our Financial Statements have been prepared in accordance with GAAP. When necessary, reclassifications that are not material to our Financial Statements are made to prior period financial information to conform to the current year presentation.
Use of Estimates, Policy	Use of EstimatesThe 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. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment and asset retirement obligations (“AROs”) as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements, Policy	Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market. In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates. Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments . The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt
Revenue Recognition, Policy	Revenue Recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 11—Revenues from Contracts with Customers for further discussion of our revenue streams and accounting policies related to revenue recognition.
Cash and Cash Equivalents, Policy	Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents, Policy	Restricted Cash and Cash EquivalentsRestricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets.
Accounts Receivable, Policy	Accounts and Other Receivables Accounts and other receivables are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Statements of Income. As of both December 31, 2021 and 2020, we had current expected credit losses on our accounts and other receivables of $5 million.
Inventory, Policy	InventoryLNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or capitalized to property, plant and equipment when issued, primarily using the weighted average method.
Property, Plant and Equipment, Policy	Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train. Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives. Refer to Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets. Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.
Interest Capitalization, Policy	Interest Capitalization We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.
Derivative Instruments, Policy	Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis. Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2021, 2020 and 2019. See Note 7—Derivative Instruments
Concentration of Credit Risk, Policy	Concentration of Credit Risk Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments. We have entered into fixed price long-term SPAs generally with terms of 20 years with eight third parties and have entered into agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 14—Customer Concentration for additional details about our customer concentration.
Debt, Policy	Debt Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors. Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in loss on modification or extinguishment of debt on our Statements of Income. We classify debt on our Balance Sheets based on contractual maturity, with the following exceptions: • We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.
Asset Retirement Obligations, Policy	Asset Retirement Obligations We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
Income Taxes, Policy	Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss 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 taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2021, the tax basis of our assets and liabilities was $7.2 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our tax sharing agreement.
Business Segment, Policy	Business Segment Our liquefaction operations at the Sabine Pass LNG terminal represent a single reportable segment. Our
Recent Accounting Standards	Recent Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting . This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

Accounts and Other Receivable_2

Accounts and Other Receivables, Net of Current Expected Credit Losses (Tables)	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
Schedule of Accounts and Other Receivables, Net of Current Expected Credit Losses	As of December 31, 2021 and 2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions): December 31, 2021 2020 Trade receivable $ 546 $ 300 Other accounts receivable 25 9 Total accounts and other receivables, net of current expected credit losses $ 571 $ 309

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2021
Inventory Disclosure [Abstract]
Schedule of Inventory	As of December 31, 2021 and 2020, inventory consisted of the following (in millions): December 31, 2021 2020 Materials $ 71 $ 68 LNG 44 8 Natural gas 43 17 Other 1 — Total inventory $ 159 $ 93

Property, Plant and Equipment_2

Property, Plant and Equipment, Net of Accumulated Depreciation (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net of Accumulated Depreciation	As of December 31, 2021 and 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions): December 31, 2021 2020 LNG terminal LNG terminal $ 13,751 $ 13,711 LNG terminal construction-in-process 2,699 2,100 Accumulated depreciation (2,021) (1,561) Total LNG terminal, net of accumulated depreciation 14,429 14,250 Fixed assets Fixed assets 19 19 Accumulated depreciation (15) (14) Total fixed assets, net of accumulated depreciation 4 5 Property, plant and equipment, net of accumulated depreciation $ 14,433 $ 14,255
Schedule of Depreciation and Offsets to LNG Terminal Costs	The following table shows depreciation expense and offsets to LNG terminal costs during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 Depreciation expense $ 463 $ 460 $ 442 Offsets to LNG terminal costs (1) 105 — 48
Property Plant and Equipment Estimated Useful Lives	LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and 50 years, as follows: Components Useful life (years) Water pipelines 30 Liquefaction processing equipment 6-50 Other 10-30

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair Value of Derivative Assets and Liabilities	The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2021 and 2020 (in millions): Fair Value Measurements as of December 31, 2021 December 31, 2020 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Liquefaction Supply Derivatives asset (liability) $ 2 $ (13) $ 38 $ 27 $ 1 $ (1) $ (21) $ (21)
Fair Value Measurement Inputs and Valuation Techniques	The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2021: Net Fair Value Asset Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1) Physical Liquefaction Supply Derivatives $38 Market approach incorporating present value techniques Henry Hub basis spread $(1.368) - $0.250 / $0.012 (1) Unobservable inputs were weighted by the relative fair value of the instruments.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 Balance, beginning of period $ (21) $ 24 $ (25) Realized and mark-to-market gains (losses): Included in cost of sales 74 (43) 6 Purchases and settlements: Purchases (10) 5 — Settlements (5) (7) 42 Transfers out of Level 3, net (1) — — 1 Balance, end of period $ 38 $ (21) $ 24 Change in unrealized gain (loss) relating to instruments still held at end of period $ 74 $ (43) $ 6 (1) Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
Fair Value of Derivative Instruments by Balance Sheet Location	The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions): Fair Value Measurements as of (1) Balance Sheets Location December 31, 2021 December 31, 2020 Current derivative assets $ 21 $ 14 Derivative assets 33 11 Total derivative assets 54 25 Current derivative liabilities (16) (11) Derivative liabilities (11) (35) Total derivative liabilities (27) (46) Derivative asset (liability), net $ 27 $ (21) (1) Does not include collateral posted with counterparties by us of $7 million and $4 million, which are included in other current assets in our Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract that we had with a related party, which had a fair value of zero as of December 31, 2020. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12—Related Party Transactions
Derivative Instruments, Gain (Loss)	The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions): Gain (Loss) Recognized in Statements of Operations Statements of Operations Location (1) Year Ended December 31, 2021 2020 2019 LNG revenues $ (1) $ — $ 1 Cost of sales 30 (49) 71 Cost of sales—related party (2) 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. (2) Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 1 2 —Related Party Transactions .
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 December 31, 2021 Gross assets $ 79 Offsetting amounts (25) Net assets $ 54 Gross liabilities $ (33) Offsetting amounts 6 Net liabilities $ (27) As of December 31, 2020 Gross assets $ 69 Offsetting amounts (44) Net assets $ 25 Gross liabilities $ (48) Offsetting amounts 2 Net liabilities $ (46)

Other Non-Current Assets, Net (

Other Non-Current Assets, Net (Tables)	12 Months Ended
	Dec. 31, 2021
Other Assets, Noncurrent [Abstract]
Schedule of Other Non-Current Assets	As of December 31, 2021 and 2020, other non-current assets, net consisted of the following (in millions): December 31, 2021 2020 Advances made to municipalities for water system enhancements $ 81 $ 84 Advances and other asset conveyances to third parties to support LNG terminal 37 33 Operating lease assets 23 23 Advances made under EPC and non-EPC contracts 5 9 Information technology service prepayments 4 5 Other 21 11 Total other non-current assets, net $ 171 $ 165

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Accrued Liabilities, Current [Abstract]
Schedule of Accrued Liabilities	As of December 31, 2021 and 2020, accrued liabilities consisted of the following (in millions): December 31, 2021 2020 Accrued natural gas purchases $ 786 $ 374 Interest costs and related debt fees 133 150 Liquefaction Project costs 89 64 Other accrued liabilities 4 3 Total accrued liabilities $ 1,012 $ 591

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Schedule of Debt Instruments	As of December 31, 2021 and 2020, our debt consisted of the following (in millions): December 31, 2021 2020 Senior Secured Notes: 6.25% due 2022 $ — $ 1,000 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 1,282 800 Total Senior Secured Notes 13,132 13,650 $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”) — — Total debt 13,132 13,650 Unamortized premium, discount and debt issuance costs, net (109) (130) Total debt, net of premium, discount and debt issuance costs $ 13,023 $ 13,520
Schedule of Maturities of Long-term Debt	Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2021 (in millions): Years Ending December 31, Principal Payments 2022 $ — 2023 1,500 2024 2,000 2025 2,037 2026 1,579 Thereafter 6,016 Total $ 13,132
Schedule of Line of Credit Facilities	Below is a summary of our 2020 Working Capital Facility as of December 31, 2021 (in millions): 2020 Working Capital Facility (1) Original facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 395 Available commitment $ 805 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 (1) Our obligations under the 2020 Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu
Schedule of Interest Expense	Total interest expense, net of capitalized interest consisted of the following (in millions): Year Ended December 31, 2021 2020 2019 Total interest cost $ 754 $ 779 $ 790 Capitalized interest (132) (94) (85) Total interest expense, net of capitalized interest $ 622 $ 685 $ 705
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): December 31, 2021 December 31, 2020 Carrying Estimated Carrying Estimated Senior notes — Level 2 (1) $ 11,850 $ 13,128 $ 12,850 $ 14,834 Senior notes — Level 3 (2) 1,282 1,466 800 1,036 Working capital facility — Level 3 (3) — — — — (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

Revenues from Contracts with _2

Revenues from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 LNG revenues (1) $ 7,640 $ 5,195 $ 5,210 LNG revenues—affiliate 1,472 662 1,312 LNG revenues—related party 1 — — Total revenues from customers 9,113 5,857 6,522 Net derivative gain (loss) (2) (1) — 1 Total revenues $ 9,112 $ 5,857 $ 6,523 (1) LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2021 and 2019. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. (2) See Note 7—Derivative Instruments
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): December 31, 2021 2020 Contract assets, net of current expected credit losses $ 1 $ —
Contract Balances Reconciliation	The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions): Year Ended December 31, 2021 Deferred revenue, beginning of period $ 114 Cash received but not yet recognized in revenue 132 Revenue recognized from prior period deferral (114) Deferred revenue, end of period $ 132 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): Year Ended December 31, 2021 Deferred revenue—affiliate, beginning of period $ — Cash received but not yet recognized in revenue 2 Deferred revenue—affiliate, end of period $ 2
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 December 31, 2021 and 2020: December 31, 2021 December 31, 2020 Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) LNG revenues $ 49.3 9 $ 52.1 9 LNG revenues—affiliate 2.1 3 0.1 1 Total revenues $ 51.4 $ 52.2 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Below is a summary of our related party transactions as reported on our Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 LNG revenues—affiliate Cheniere Marketing Agreements $ 1,453 $ 632 $ 1,309 Contracts for Sale and Purchase of Natural Gas and LNG 19 30 3 Total LNG revenues—affiliate 1,472 662 1,312 LNG revenues—related party Natural Gas Transportation and Storage Agreements 1 — — Cost of sales—affiliate Cheniere Marketing Agreements 34 61 — Cargo loading fees under TUA 43 33 40 Contracts for Sale and Purchase of Natural Gas and LNG 51 16 7 Total cost of sales—affiliate 128 110 47 Cost of sales—related party Natural Gas Transportation and Storage Agreements 1 — — Natural Gas Supply Agreements (1) 16 — — Total cost of sales—related party 17 — — Operating and maintenance expense—affiliate TUA 266 265 261 Natural Gas Transportation Agreement 81 82 81 Services Agreements 109 118 107 LNG Site Sublease Agreement 1 1 1 Total operating and maintenance expense—affiliate 457 466 450 Operating and maintenance expense—related party Natural Gas Transportation and Storage Agreements 46 13 — General and administrative expense—affiliate Services Agreements 61 71 79 (1) Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed below.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Natural Gas Supply, Transportation And Storage Service Agreements [Member]
Long-term Purchase Commitment [Line Items]
Contractual Obligation, Fiscal Year Maturity Schedule	As of December 31, 2021, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in billions): Years Ending December 31, Payments Due (1) 2022 $ 5.3 2023 3.7 2024 2.6 2025 1.7 2026 1.1 Thereafter 5.7 Total $ 20.1 (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread . Amounts included are based on estimated forward prices and basis spreads as of December 31, 2021. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

Customer Concentration (Tables)

Customer Concentration (Tables)	12 Months Ended
	Dec. 31, 2021
Risks and Uncertainties [Abstract]
Schedule of Revenue and Accounts Receivable by Major Customers	The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivable, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivable, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively: Percentage of Total Revenues from External Customers Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers Year Ended December 31, December 31, 2021 2020 2019 2021 2020 Customer A 25% 25% 29% 29% 32% Customer B 18% 19% 21% 17% 22% Customer C 17% 18% 21% * * Customer D 16% 16% 19% 14% 21% Customer E 10% * * 13% * Customer F * * * 12% * * Less than 10%
Schedule of Revenue from External Customers by Country	The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States. Revenues from External Customers Year Ended December 31, 2021 2020 2019 United States $ 2,550 $ 1,975 $ 1,854 India 1,342 970 1,113 South Korea 1,336 924 1,071 Ireland 1,237 842 989 United Kingdom 966 456 184 Other countries 208 28 — Total $ 7,639 $ 5,195 $ 5,211

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2021 2020 2019 Cash paid during the period for interest, net of amounts capitalized $ 615 $ 692 $ 678 Non-cash distributions to affiliates for conveyance of assets — 6 351 Right-of-use assets obtained in exchange for new operating lease liabilities — 3 —

Organization and Nature of Op_2

Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2021milliontonnes / yrtrainsmembers
Organization and Nature of Operations [Line Items]
Limited Liability Company (LLC) Number Of Members | members	1
Cheniere Energy Partners, LP | Cheniere [Member]
Organization and Nature of Operations [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]
Organization and Nature of Operations [Line Items]
Number of Liquefaction LNG Trains Operating | trains	6
Total Production Capability | milliontonnes / yr	30

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)membersunit	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Accounts Receivable, Allowance for Credit Loss, Current	$ 5	$ 5
Impairment of Long-Lived Assets Held-for-use	5	0	$ 0
Derivative instruments designated as cash flow hedges	0	$ 0	$ 0
Income Tax Expense (Benefit)	0
Taxes, Difference in Bases, Amount	$ 7,200
Number of Reportable Segments | unit	1
Sabine Pass LNG Terminal [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Asset Retirement Obligation	$ 0
Customer Concentration Risk [Member] | SPA Customers [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
SPA, Term of Agreement	20 years
Concentration Risk, Number of Significant Customers | members	8
Maximum [Member] | Sabine Pass LNG Terminal [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Property Lease Term	90 years

Restricted Cash and Cash Equi_2

Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 98	$ 97
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 98	$ 97

Accounts and Other Receivable_3

Accounts and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Receivables [Abstract]
Trade receivable	$ 546	$ 300
Other accounts receivable	25	9
Total accounts and other receivables, net of current expected credit losses	$ 571	$ 309

Inventory (Details)

Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Inventory [Line Items]
Inventory	$ 159	$ 93
Materials [Member]
Inventory [Line Items]
Inventory	71	68
LNG [Member]
Inventory [Line Items]
Inventory	44	8
Natural gas [Member]
Inventory [Line Items]
Inventory	43	17
Other [Member]
Inventory [Line Items]
Inventory	$ 1	$ 0

Property, Plant and Equipment_3

Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 14,433	$ 14,255
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(2,021)	(1,561)
Property, plant and equipment, net of accumulated depreciation	14,429	14,250
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	13,751	13,711
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,699	2,100
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19	19
Accumulated depreciation	(15)	(14)
Property, plant and equipment, net of accumulated depreciation	$ 4	$ 5

Property, Plant and Equipment_4

Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 463	$ 460	$ 442
Offsets to LNG terminal costs	[1]	$ 105	$ 0	$ 48
[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.

Property, Plant and Equipment_5

Property, Plant and Equipment, Net of Accumulated Depreciation - Estimated Useful Lives (Details)	12 Months Ended
	Dec. 31, 2021
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	6 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Water pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years
Liquefaction processing equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	6 years
Liquefaction processing equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details) - tbtu	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	5,194	4,970
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	10 years
Financial Liquefaction Supply Derivatives | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	3 years

Derivative Instruments - Fair V

Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 27	$ (21)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	2	1
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(13)	(1)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 38	$ (21)

Derivative Instruments - Fair_2

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		$ 27,000,000	$ (21,000,000)
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		38,000,000	$ (21,000,000)
Physical Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset		38,000,000
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range		(1.368)
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range		0.250
Physical Liquefaction Supply Derivatives [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	[1]	$ 0.012
[1]	Unobservable inputs were weighted by the relative fair value of the instruments.

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (21)	$ 24	$ (25)
Realized and mark-to-market gains (losses):
Included in cost of sales		74	(43)	6
Purchases and settlements:
Purchases		(10)	5	0
Settlements		(5)	(7)	42
Transfers out of Level 3, net	[1]	0	0	1
Balance, end of period		38	(21)	24
Change in unrealized gain (loss) relating to instruments still held at end of period		$ 74	$ (43)	$ 6
[1]	Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

Derivative Instruments - Fair_3

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Current derivative assets		$ 21	$ 14
Derivative assets		33	11
Total derivative assets	[1]	54	25
Current derivative liabilities		(16)	(11)
Derivative liabilities		(11)	(35)
Total derivative liabilities	[1]	(27)	(46)
Derivative asset (liability), net	[1]	27	(21)
Derivative, collateral posted by us		7	4
Natural Gas Supply Agreement [Member]
Derivatives, Fair Value [Line Items]
Derivative asset (liability), net			0
Current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[1]	21	14
Derivative assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	33	11
Current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities	[1]	(16)	(11)
Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	$ (11)	$ (35)
[1]	Does not include collateral posted with counterparties by us of $7 million and $4 million, which are included in other current assets in our Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract that we had with a related party, which had a fair value of zero as of December 31, 2020. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12—Related Party Transactions

Derivative Instruments - Deriva

Derivative Instruments - Derivative Gain (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ (1)	$ 0	$ 1
Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	30	(49)	71
Cost of Sales, Related Party
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	$ 2	$ 0	$ 0
[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.
[2]	Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 1 2 —Related Party Transactions .

Derivative Instruments - Deri_2

Derivative Instruments - Derivative Net Presentation on Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Net Amounts Presented in our Balance Sheets	$ 27	$ (21)
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	79	69
Derivative Asset, Gross Amounts Offset in the Balance Sheets	(25)	(44)
Net Amounts Presented in our Balance Sheets	54	25
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(33)	(48)
Derivative Liability, Gross Amounts Offset in the Balance Sheets	6	2
Net Amounts Presented in our Balance Sheets	$ (27)	$ (46)

Other Non-Current Assets, Net_2

Other Non-Current Assets, Net (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Other Assets, Noncurrent [Abstract]
Advances made to municipalities for water system enhancements	$ 81	$ 84
Advances and other asset conveyances to third parties to support LNG terminal	37	33
Operating lease assets	23	23
Advances made under EPC and non-EPC contracts	5	9
Information technology service prepayments	4	5
Other	21	11
Other non-current assets, net	$ 171	$ 165

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Accrued Liabilities, Current [Abstract]
Accrued natural gas purchases	$ 786	$ 374
Interest costs and related debt fees	133	150
Liquefaction Project costs	89	64
Other accrued liabilities	4	3
Total accrued liabilities	$ 1,012	$ 591

Debt - Schedule of Debt Instrum

Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2021		Dec. 31, 2020
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 13,132		$ 13,650
Unamortized premium, discount and debt issuance costs, net	(109)		(130)
Total debt, net of premium, discount and debt issuance costs	13,023		13,520
Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	13,132		13,650
2022 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0		1,000
Debt Instrument, Interest Rate, Stated Percentage	6.25%
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		800
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	[1]	$ 0
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,200
[1]	Our obligations under the 2020 Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu

Debt - Schedule of Maturities (

Debt - Schedule of Maturities (Details) $ in Millions	Dec. 31, 2021USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2022	$ 0
2023	1,500
2024	2,000
2025	2,037
2026	1,579
Thereafter	6,016
Total	$ 13,132

Debt - Credit Facilities (Detai

Debt - Credit Facilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2021USD ($)unitRate		Dec. 31, 2020USD ($)
Line of Credit Facility [Line Items]
Outstanding balance		$ 13,132		$ 13,650
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]	$ 1,200
Outstanding balance		0	[1]	$ 0
Letters of credit issued	[1]	395
Available commitment	[1]	$ 805
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%
[1]	Our obligations under the 2020 Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu

Debt - Interest Expense (Detail

Debt - Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Total interest cost	$ 754	$ 779	$ 790
Capitalized interest	(132)	(94)	(85)
Total interest expense, net of capitalized interest	$ 622	$ 685	$ 705

Debt - Schedule of Carrying Val

Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[1]	$ 11,850	$ 12,850
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[2]	1,282	800
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	13,128	14,834
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	1,466	1,036
Working Capital Facility [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[3]	0	0
Working Capital Facility [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[3]	$ 0	$ 0
[1]	The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
[2]	The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
[3]	The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

Revenues from Contracts with _3

Revenues from Contracts with Customers - Narrative (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	61.00%	42.00%
LNG—affiliate
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	96.00%	100.00%

Revenues from Contracts with _4

Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 9,113	$ 5,857	$ 6,522
Net derivative loss	[1]	(1)	0	1
Revenues		9,112	5,857	6,523
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	[2]	7,640	5,195	5,210
Revenues		7,639	5,195	5,211
Suspension Fees and LNG Cover Damages Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		0	553	0
LNG—affiliate
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		1,472	662	1,312
LNG—related party [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 1	$ 0	$ 0
[1]	See Note 7—Derivative Instruments
[2]	LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2021 and 2019. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

Revenues from Contracts with _5

Revenues from Contracts with Customers - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 1	$ 0
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	114
Cash received but not yet recognized in revenue	132
Revenue recognized from prior period deferral	(114)
Deferred revenue, end of period	132
Deferred revenue, beginning of period	0
Cash received but not yet recognized in revenue	2
Deferred revenue, end of period	$ 2

Revenues from Contracts with _6

Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Dec. 31, 2021	Dec. 31, 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 52.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 51.4
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 52.1
Weighted Average Recognition Timing	[1]		9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 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—affiliate | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 0.1
Weighted Average Recognition Timing	[1]		1 year
LNG—affiliate | 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
[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.

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
LNG revenues—affiliate		$ 1,472	$ 662	$ 1,312
Cost of sales—affiliate		128	110	47
Cost of sales—related party		17	0	0
Operating and maintenance expense—affiliate		457	466	450
Operating and maintenance expense—related party		46	13	0
General and administrative expense—affiliate		61	71	79
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate		1,453	632	1,309
Cost of sales—affiliate		34	61	0
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate		19	30	3
Cost of sales—affiliate		51	16	7
Terminal Use Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—affiliate		43	33	40
Operating and maintenance expense—affiliate		266	265	261
Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate		81	82	81
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—related party		1	0	0
Cost of sales—related party		1	0	0
Operating and maintenance expense—related party		46	13	0
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate		109	118	107
General and administrative expense—affiliate		61	71	79
LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate		1	1	1
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—related party	[1]	$ 16	$ 0	$ 0
[1]	Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed below.

Related Party Transactions - Na

Related Party Transactions - Narrative (Details)	12 Months Ended
	Dec. 31, 2021USD ($)bcf / dMMBTUCargoitem	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate	$ 232,000,000	$ 185,000,000
Regasification Capacity | bcf / d	2
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
Due to affiliates	$ 73,000,000	59,000,000
Accrued liabilities—related party	4,000,000	4,000,000
Advances to affiliate	127,000,000	122,000,000
Operating and maintenance expense—related party	46,000,000	13,000,000	$ 0
Cost of sales—related party	$ 17,000,000	0	0
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term	10 years
Accrued liabilities—related party	$ 4,000,000	4,000,000
Operating and maintenance expense—related party	46,000,000	13,000,000	0
Cost of sales—related party	1,000,000	0	$ 0
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to affiliate	$ 127,000,000	122,000,000
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	6,000,000
Cheniere Investments [Member] | Operation and Maintenance Agreement [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	0.60%
Related Party Transaction, Committed Monthly Fee	$ 83,333
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
Cheniere Marketing [Member] | 2021-2027 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] | 2021-2027 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	306
Cheniere Marketing [Member] | 2021 Letter Agreement
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price	$ 0.728
Cheniere Marketing [Member] | 2021 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	30
Cheniere Marketing [Member] | 2020 Letter Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price	$ 1.67
Cheniere Marketing [Member] | 2020 Letter Agreement [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	43
Cheniere Marketing [Member] | 2019 Letter Agreement
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
Contract Volume | MMBTU	70,000,000
LNG Volume, Purchase Price	$ 2
Cheniere Marketing [Member] | 2019 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	20
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	$ 6,000,000

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)bcf / ditem
Commitments and Contingencies [Line Items]
Regasification Capacity | bcf / d	2
Loss Contingency, Pending Claims, Number | item	0
Bechtel EPC Contract, Train 6 [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Amount	$ 2,500
Purchase Commitment, Remaining Minimum Amount Committed	$ 200
Natural Gas Supply Agreement [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	10 years
Natural Gas Transportation Agreements [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	20 years
Natural Gas Storage Service Agreements [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	10 years

Commitments and Contingencies_2

Commitments and Contingencies - Purchase Obligations Table (Details) - Natural Gas Supply, Transportation And Storage Service Agreements [Member] $ in Billions	Dec. 31, 2021USD ($)	[1]
Long-term Purchase Commitment [Line Items]
2022	$ 5.3
2023	3.7
2024	2.6
2025	1.7
2026	1.1
Thereafter	5.7
Total	$ 20.1
[1]	Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread . Amounts included are based on estimated forward prices and basis spreads as of December 31, 2021. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

Customer Concentration - Schedu

Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	25.00%	25.00%	29.00%
Customer A [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	29.00%	32.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	19.00%	21.00%
Customer B [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%	22.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%	18.00%	21.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%	16.00%	19.00%
Customer D [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	14.00%	21.00%
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%

Customer Concentration - Sche_2

Customer Concentration - Schedule of Revenues from External Customers by Country (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Concentration Risk [Line Items]
Revenues from External Customers	$ 9,112	$ 5,857	$ 6,523
Geographic Concentration Risk [Member]
Concentration Risk [Line Items]
Revenues from External Customers	7,639	5,195	5,211
Geographic Concentration Risk [Member] | United States
Concentration Risk [Line Items]
Revenues from External Customers	2,550	1,975	1,854
Geographic Concentration Risk [Member] | India
Concentration Risk [Line Items]
Revenues from External Customers	1,342	970	1,113
Geographic Concentration Risk [Member] | South Korea
Concentration Risk [Line Items]
Revenues from External Customers	1,336	924	1,071
Geographic Concentration Risk [Member] | Ireland
Concentration Risk [Line Items]
Revenues from External Customers	1,237	842	989
Geographic Concentration Risk [Member] | United Kingdom
Concentration Risk [Line Items]
Revenues from External Customers	966	456	184
Geographic Concentration Risk [Member] | Other Countries
Concentration Risk [Line Items]
Revenues from External Customers	$ 208	$ 28	$ 0

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 615	$ 692	$ 678
Non-cash distributions to affiliates for conveyance of assets	0	6	351
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	0	3	0
Balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)	$ 322	$ 207	$ 276