Cheniere Corpus Christi 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	333-215435
Entity Registrant Name	Cheniere Corpus Christi Holdings, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-1929160
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	0001693317
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

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues
Revenues		$ 5,794	$ 2,529	$ 1,405
Revenues from contracts with customers		5,790	2,530	1,405
Operating costs and expenses
Cost of sales (excluding items shown separately below)		4,326	901	691
Cost of sales—affiliate		50	30	3
Cost of sales—related party		146	114	86
Operating and maintenance expense		423	347	242
Operating and maintenance expense—affiliate		106	90	59
Operating and maintenance expense—related party		9	6	0
Development expense		0	0	1
General and administrative expense		7	7	6
General and administrative expense—affiliate		28	20	11
Depreciation and amortization expense		420	342	231
Impairment expense and loss on disposal of assets		2	1	0
Total operating costs and expenses		5,517	1,858	1,330
Income from operations		277	671	75
Other income (expense)
Interest expense, net of capitalized interest		(447)	(365)	(278)
Loss on modification or extinguishment of debt		(9)	(9)	(41)
Interest rate derivative loss, net		(1)	(233)	(134)
Other income (expense), net		0	(1)	4
Total other expense		(457)	(608)	(449)
Net income (loss)		(180)	63	(374)
LNG [Member]
Revenues
Revenues		3,907	2,046	679
Revenues from contracts with customers	[1]	3,903	2,047	679
LNG—affiliate [Member]
Revenues
Revenues from contracts with customers		$ 1,887	$ 483	$ 726
[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 $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized during the year ended December 31, 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the 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.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current assets
Restricted cash and cash equivalents	$ 44	$ 70
Accounts and other receivables, net of current expected credit losses	280	198
Accounts receivable—affiliate	315	42
Advances to affiliate	128	144
Inventory	156	89
Current derivative assets	17	10
Current derivative assets—related party	0	3
Other current assets	28	17
Other current assets—affiliate	0	1
Total current assets	968	574
Property, plant and equipment, net of accumulated depreciation	12,607	12,853
Debt issuance and deferred financing costs, net of accumulated amortization	7	11
Derivative assets	37	114
Derivative assets—related party	0	1
Other non-current assets, net	145	87
Total assets	13,764	13,640
Current liabilities
Accounts payable	119	19
Accrued liabilities	631	318
Accrued liabilities—related party	1	16
Current debt, net of discount and debt issuance costs	366	269
Due to affiliates	35	32
Current derivative liabilities	668	143
Other current liabilities	1	0
Total current liabilities	1,821	797
Long-term debt, net of discount and debt issuance costs	9,986	10,101
Derivative liabilities	638	114
Other non-current liabilities	38	4
Commitments and Contingencies
Member’s equity	1,281	2,624
Total liabilities and member’s equity	$ 13,764	$ 13,640

Consolidated Statements of Memb

Consolidated Statements of Member's Equity - USD ($) $ in Millions	Total	Cheniere CCH HoldCo I, LLC [Member]
Member's equity, beginning of period at Dec. 31, 2018	$ 2,081	$ 2,081
Capital contributions	711	711
Net income (loss)	(374)	(374)
Member's equity, end of period at Dec. 31, 2019	2,418	2,418
Capital contributions	145	145
Distributions	(2)	(2)
Net income (loss)	63	63
Member's equity, end of period at Dec. 31, 2020	2,624	2,624
Distributions	(1,163)	(1,163)
Net income (loss)	(180)	(180)
Member's equity, end of period at Dec. 31, 2021	$ 1,281	$ 1,281

Consolidated Statements of Cash

Consolidated 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 (loss)	$ (180)	$ 63	$ (374)
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization expense	420	342	231
Amortization of discount and debt issuance costs	24	20	16
Loss on modification or extinguishment of debt	9	9	41
Total losses on derivatives, net	1,241	261	88
Total losses (gains) on derivatives, net—related party	(11)	1	1
Net cash used for settlement of derivative instruments	(107)	(174)	(30)
Impairment expense and loss on disposal of assets	2	1	0
Other	1	3	2
Changes in operating assets and liabilities:
Accounts receivable	(84)	(138)	(58)
Accounts receivable—affiliate	(273)	15	(57)
Advances to affiliate	14	(11)	(53)
Inventory	(62)	(18)	(37)
Accounts payable and accrued liabilities	468	63	174
Accrued liabilities—related party	(14)	11	3
Due to affiliates	9	5	15
Other, net	(33)	(56)	5
Other, net—affiliate	0	(1)	0
Net cash provided by (used in) operating activities	1,424	396	(33)
Cash flows from investing activities
Property, plant and equipment	(238)	(790)	(1,517)
Other	(2)	(6)	(2)
Net cash used in investing activities	(240)	(796)	(1,519)
Cash flows from financing activities
Proceeds from issuances of debt	1,150	1,050	4,203
Repayments of debt	(1,188)	(797)	(3,544)
Debt issuance and deferred financing costs	(4)	(8)	(16)
Debt extinguishment costs	(5)	0	(11)
Capital contributions	0	145	711
Distributions	(1,163)	0	0
Net cash provided by (used in) financing activities	(1,210)	390	1,343
Net decrease in restricted cash	(26)	(10)	(209)
Restricted cash and cash equivalents—beginning of period	70	80	289
Restricted cash and cash equivalents—end of period	$ 44	$ 70	$ 80

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	NATURE OF OPERATIONS We operate a natural gas liquefaction and export facility (the “Liquefaction Facilities”) and operate a 21.5-mile natural gas supply pipeline that interconnects the natural gas liquefaction and export facility near Corpus Christi, Texas (the “Corpus Christi LNG terminal”) with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries CCL and CCP, respectively. We operate three Trains

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 Consolidated Financial Statements have been prepared in accordance with GAAP. Our Consolidated Financial Statements include the accounts of CCH and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. When necessary, reclassifications that are not material to our Consolidated Financial Statements are made to prior period financial information to conform to the current year presentation. Use of Estimates The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. 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 restricted cash and cash equivalents, accounts receivable and accounts payable reported on the Consolidated 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 Consolidated 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 Consolidated Statements of Operations. We did not have any current expected credit losses on our accounts and other receivables as of December 31, 2021 and 2020. 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 our LNG terminal once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project 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 our LNG terminal. 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 $2 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. Regulated Natural Gas Pipelines The Corpus Christi Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to write off the associated regulatory assets and liabilities. Items that may influence our assessment are: • inability to recover cost increases due to rate caps and rate case moratoriums; • inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings; • excess capacity; • increased competition and discounting in the markets we serve; and • impacts of ongoing regulatory initiatives in the natural gas industry. Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipeline. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipeline is placed in service. Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated 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. 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. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. 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. CCL has entered into fixed price long-term SPAs generally with terms of 20 years with 10 third parties and have entered into agreements with Cheniere Marketing International LLP (“Cheniere Marketing”). CCL is 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 Consolidated 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 Consolidated 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 Consolidated Statements of Operations. We classify debt on our Consolidated 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 Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly. Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements. Business Segment Our liquefaction and pipeline business at the Corpus Christi LNG terminal represents a single reportable segment. Our chief operating decision maker reviews the financial results of CCH 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 contracts expected to arise from the market transition from LIBOR to alternative reference rates. The transition period under this standard is effective March 12, 2020 and will apply through December 31, 2022. We have various credit facilities and interest rate swaps indexed to LIBOR, as further described in Note 1 0 —Debt . To date, we have amended certain of our credit facilities to incorporate a fallback replacement rate indexed to SOFR as a result of the expected LIBOR transition. We elected to apply the optional expedients as applicable to certain modified terms, however the impact of applying the optional expedients has not been material thus far. We will continue to elect to apply the optional expedients to qualifying contract modifications in the future.

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 consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2021 and 2020, we had $44 million and $70 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 $ 256 $ 182 Other accounts receivable 24 16 Total accounts and other receivables, net of current expected credit losses $ 280 $ 198

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 $ 88 $ 69 LNG 45 11 Natural gas 21 9 Other 2 — Total inventory $ 156 $ 89

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 and interconnecting pipeline facilities $ 13,222 $ 10,176 LNG site and related costs 294 276 LNG terminal construction-in-process 66 2,960 Accumulated depreciation (981) (568) Total LNG terminal, net of accumulated depreciation 12,601 12,844 Fixed assets Fixed assets 23 22 Accumulated depreciation (17) (13) Total fixed assets, net of accumulated depreciation 6 9 Property, plant and equipment, net of accumulated depreciation $ 12,607 $ 12,853 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 $ 419 $ 341 $ 230 Offsets to LNG terminal costs (1) 143 32 156 (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 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) LNG storage tanks 50 Natural gas pipeline facilities 40 Marine berth, electrical, facility and roads 35 Water pipelines 30 Liquefaction processing equipment 6-50 Other 15-30 Fixed Assets and Other Our fixed assets and other 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 the following derivative instruments that are reported at fair value: • interest rate swaps (“CCH Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on our amended and restated term loan credit facility (the “CCH Credit Facility”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt (“CCH Interest Rate Forward Start Derivatives” and, collectively with the CCH Interest Rate Derivatives, the “Interest Rate Derivatives”) and • commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”). We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process, in which case it is capitalized. The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of 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 CCH Interest Rate Derivatives liability $ — $ (40) $ — $ (40) $ — $ (140) $ — $ (140) Liquefaction Supply Derivatives asset (liability) 5 4 (1,221) (1,212) 4 (5) 12 11 We value our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data. The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed. We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, 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 and international LNG 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 Liability Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1) Physical Liquefaction Supply Derivatives $(1,221) Market approach incorporating present value techniques Henry Hub basis spread $(0.380) - $0.628 / $(0.035) Option pricing model International LNG pricing spread, relative to Henry Hub (2) 199% - 662% / 326% (1) Unobservable inputs were weighted by the relative fair value of the instruments. (2) Spread contemplates U.S. dollar-denominated pricing. Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives. The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives, including those with related parties, during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 Balance, beginning of period $ 12 $ 35 $ (4) Realized and mark-to-market gains (losses): Included in cost of sales (1,276) 28 (83) Purchases and settlements: Purchases 9 — 121 Settlements 34 (58) 1 Transfers into Level 3, net (1) — 7 — Balance, end of period $ (1,221) $ 12 $ 35 Change in unrealized gain (loss) relating to instruments still held at end of period $ (1,276) $ 28 $ (83) (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. Interest Rate Derivatives We have entered into interest rate swaps to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility. We previously also had interest rate swaps to hedge against changes in interest rates that could impact the anticipated future issuance of debt. In August 2020, we settled the outstanding CCH Interest Rate Forward Start Derivatives. As of December 31, 2021, we had the following Interest Rate Derivatives outstanding: Notional Amounts December 31, 2021 December 31, 2020 Latest Maturity Date Weighted Average Fixed Interest Rate Paid Variable Interest Rate Received CCH Interest Rate Derivatives $4.5 billion $4.6 billion May 31, 2022 2.30% One-month LIBOR The following table shows the effect and location of our Interest Rate Derivatives on our Consolidated Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions): Loss Recognized in Consolidated Statements of Operations Consolidated Statements of Operations Location Year Ended December 31, 2021 2020 2019 CCH Interest Rate Derivatives Interest rate derivative loss, net $ (1) $ (138) $ (101) CCH Interest Rate Forward Start Derivatives Interest rate derivative loss, net — (95) (33) Liquefaction Supply Derivatives CCL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges, including those associated with transactions under our IPM agreements, 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 conditions precedent. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years. The forward notional amount for our Liquefaction Supply Derivatives was approximately 2,915 TBtu and 3,152 TBtu as of December 31, 2021 and 2020, respectively. The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions): Gain (Loss) Recognized in Consolidated Statements of Operations Consolidated Statements of Operations Location (1) Year Ended December 31, 2021 2020 2019 LNG revenues $ 4 $ (1) $ — Cost of sales (1,244) (27) 46 Cost of sales—related party (2) 11 (1) (1) (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 12—Related Party Transactions . Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets The following table shows the fair value and location of our derivative instruments on our Consolidated Balance Sheets (in millions): December 31, 2021 CCH Interest Rate Derivatives Liquefaction Supply Derivatives (1) Total Consolidated Balance Sheets Location Current derivative assets $ — $ 17 $ 17 Derivative assets — 37 37 Total derivative assets — 54 54 Current derivative liabilities (40) (628) (668) Derivative liabilities — (638) (638) Total derivative liabilities (40) (1,266) (1,306) Derivative liability, net $ (40) $ (1,212) $ (1,252) December 31, 2020 CCH Interest Rate Derivatives Liquefaction Supply Derivatives (1) Total Consolidated Balance Sheets Location Current derivative assets $ — $ 10 $ 10 Current derivative assets—related party — 3 3 Derivative assets — 114 114 Derivative assets—related party — 1 1 Total derivative assets — 128 128 Current derivative liabilities (100) (43) (143) Derivative liabilities (40) (74) (114) Total derivative liabilities (140) (117) (257) Derivative asset (liability), net $ (140) $ 11 $ (129) (1) Does not include collateral posted with counterparties by us of $13 million and $5 million, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract 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 12—Related Party Transactions . Consolidated Balance Sheets Presentation Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions): CCH Interest Rate Derivatives Liquefaction Supply Derivatives As of December 31, 2021 Gross assets $ — $ 76 Offsetting amounts — (22) Net assets $ — $ 54 Gross liabilities $ (40) $ (1,295) Offsetting amounts — 29 Net liabilities $ (40) $ (1,266) As of December 31, 2020 Gross assets $ — $ 132 Offsetting amounts — (4) Net assets $ — $ 128 Gross liabilities $ (140) $ (136) Offsetting amounts — 19 Net liabilities $ (140) $ (117)

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 Contract assets, net of current expected credit losses $ 103 $ 48 Advances and other asset conveyances to third parties to support LNG terminal 24 22 Operating lease assets 4 5 Information technology service prepayments 3 3 Tax-related payments and receivables 2 3 Other 9 6 Total other non-current assets, net $ 145 $ 87

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 $ 531 $ 186 Interest costs and related debt fees 7 7 Liquefaction Project costs 43 76 Other 50 49 Total accrued liabilities $ 631 $ 318

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: 7.000% due 2024 $ 1,250 $ 1,250 5.875% due 2025 1,500 1,500 5.125% due 2027 1,500 1,500 3.700% due 2029 1,500 1,500 3.72% weighted average rate due 2039 2,721 1,971 Total Senior Secured Notes 8,471 7,721 CCH Credit Facility (1) 1,728 2,627 $1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) (2) 250 140 Total Debt 10,449 10,488 Current portion of long-term debt (117) (129) Short-term debt (250) (140) Unamortized discount and debt issuance costs, net (96) (118) Total long-term debt, net of discount and debt issuance costs $ 9,986 $ 10,101 (1) A portion of the outstanding balance that is due within one year is classified as current portion of long-term debt. (2) The CCH Working Capital Facility is classified as short-term debt. Senior Notes CCH Senior Secured Notes The senior secured notes due between 2024 and 2039, with a weighted average interest rate of 4.83% (“CCH Senior Secured Notes”) are jointly and severally guaranteed by our subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The CCH Senior Secured Notes are our senior secured obligations, ranking senior in right of payment to any and all of our future indebtedness that is subordinated to the CCH Senior Secured Notes and equal in right of payment with our other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Secured Notes. The CCH Senior Secured Notes are secured by a first-priority security interest in substantially all of our and the CCH Guarantors’ assets. We may, at any time, redeem all or part of the CCH Senior Secured Notes at specified prices set forth in the respective indentures governing the CCH Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2021 (in millions): Years Ending December 31, Principal Payments 2022 $ 367 2023 67 2024 2,794 2025 1,500 2026 — Thereafter 5,721 Total $ 10,449 Credit Facilities Below is a summary of our credit facilities outstanding as of December 31, 2021 (in millions): CCH Credit Facility (1) CCH Working Capital Facility (2) Original facility size $ 8,404 $ 350 Incremental commitments 1,566 850 Less: Outstanding balance 1,729 250 Commitments prepaid or terminated 8,241 — Letters of credit issued — 361 Available commitment $ — $ 589 Priority ranking Senior secured Senior secured Interest rate on available balance LIBOR plus 1.75% or base rate plus 0.75% (3) LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75% (3) Weighted average interest rate of outstanding balance 1.85% 3.50% Commitment fees on undrawn balance n/a 0.50% Maturity date June 30, 2024 June 29, 2023 (1) Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our and our subsidiaries assets and by a pledge by Cheniere CCH Holdco I, LLC of its limited liability company interests in us. (2) Our obligations under the CCH Working Capital Facility are secured by substantially all of our and the CCH Guarantors assets as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility. (3) These facilities were amended in 2021 to establish a SOFR-indexed replacement rate for LIBOR. Restrictive Debt Covenants The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain investments or pay dividends or distributions. As of 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 $ 473 $ 484 $ 539 Capitalized interest, including amounts capitalized as an AFUDC (26) (119) (261) Total interest expense, net of capitalized interest $ 447 $ 365 $ 278 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) $ 6,500 $ 7,095 $ 5,750 $ 6,669 Senior notes — Level 3 (2) 1,971 2,227 1,971 2,387 Credit facilities — Level 3 (3) 1,978 1,978 2,767 2,767 (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 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) $ 3,903 $ 2,047 $ 679 LNG revenues—affiliate 1,887 483 726 Total revenues from customers 5,790 2,530 1,405 Net derivative gain (loss) (2) 4 (1) — Total revenues $ 5,794 $ 2,529 $ 1,405 (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 $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized during the year ended December 31, 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the 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 Corpus Christi 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 Corpus Christi 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 Consolidated Balance Sheets (in millions): December 31, 2021 2020 Contract assets, net of current expected credit losses $ 104 $ 48 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 other non-current liabilities on our Consolidated Balance Sheets (in millions): Year Ended December 31, 2021 Deferred revenue, beginning of period $ — Cash received but not yet recognized in revenue 35 Revenue recognized from prior period deferral — Deferred revenue, end of period $ 35 We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2021 and 2020 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. 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 $ 31.7 9 $ 32.3 10 LNG revenues—affiliate 1.1 10 1.0 12 Total revenues $ 32.8 $ 33.3 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price. We have elected the following exemptions which omit certain potential future sources of revenue from the table above: (1) We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less. (2) The table above excludes substantially all variable consideration under our SPAs. 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 58% and 33% 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. None of our LNG revenues—affiliates from the contract included in the table above were related to variable consideration received from customers during the years ended December 31, 2021 and 2020. 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 Consolidated 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 $ 1,837 $ 468 $ 719 Contracts for Sale and Purchase of Natural Gas and LNG 50 15 7 Total LNG revenues—affiliate 1,887 483 726 Cost of sales—affiliate Contracts for Sale and Purchase of Natural Gas and LNG 19 30 3 Cheniere Marketing Agreements 31 — — Total cost of sales—affiliate 50 30 3 Cost of sales—related party Natural Gas Supply Agreement (1) 146 114 86 Operating and maintenance expense—affiliate Services Agreements 105 89 58 Land Agreements 1 1 1 Total operating and maintenance expense—affiliate 106 90 59 Operating and maintenance expense—related party Natural Gas Transportation Agreements 9 6 — General and administrative expense—affiliate Services Agreements 28 20 11 (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. We had $35 million and $32 million due to affiliates as of December 31, 2021 and 2020, respectively, under agreements with affiliates, as described below. Cheniere Marketing Agreements Cheniere Marketing SPA CCL has a fixed price SPA with Cheniere Marketing (the “Cheniere Marketing Base SPA”) with a term of 20 years which allows Cheniere Marketing to purchase, at its option, (1) up to a cumulative total of 150 TBtu of LNG within the commissioning periods for Trains 1 through 3 and (2) any excess LNG produced by the Liquefaction Facilities that is not committed to customers under third party SPAs. Under the Cheniere Marketing Base SPA, Cheniere Marketing may, without charge, elect to suspend deliveries of cargoes (other than commissioning cargoes) scheduled for any month under the applicable annual delivery program by providing specified notice in advance. Additionally, CCL has: (1) a fixed price SPA with a term through 2043 with Cheniere Marketing which allows them to purchase volumes of approximately 15 TBtu per annum of LNG and (2) an SPA with Cheniere Marketing for approximately 44 TBtu of LNG with a maximum term up to 2026 associated with the integrated production marketing gas supply agreement between CCL and EOG Resources, Inc. As of December 31, 2021 and 2020, CCL had $314 million and $39 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing. Facility Swap Agreement We have 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. Services Agreements Gas and Power Supply Services Agreement (“G&P Agreement”) CCL has a G&P Agreement with Cheniere Energy Shared Services, Inc. (“Shared Services”), a wholly owned subsidiary of Cheniere, pursuant to which Shared Services will manage the gas and power procurement requirements of CCL. The services include, among other services, exercising the day-to-day management of CCL’s natural gas and power supply requirements, negotiating agreements on CCL’s behalf and providing other administrative services. Prior to the substantial completion of each Train of the Liquefaction Facilities, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facilities, for services performed while the Liquefaction Facilities is operational, CCL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train. Operation and Maintenance Agreements (“O&M Agreements”) CCL has an O&M Agreement (“CCL O&M Agreement”) with Cheniere LNG O&M Services, LLC (“O&M Services”), a wholly owned subsidiary of Cheniere, pursuant to which CCL receives all of the necessary services required to construct, operate and maintain the Liquefaction Facilities. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors, administering various agreements, information technology services and other services required to operate and maintain the Liquefaction Facilities. Prior to the substantial completion of each Train of the Liquefaction Facilities, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facilities, for services performed while the Liquefaction Facilities is operational, CCL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train. CCP has an O&M Agreement (“CCP O&M Agreement”) with O&M Services pursuant to which CCP receives all of the necessary services required to construct, operate and maintain the Corpus Christi Pipeline. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors, information technology services and other services required to operate and maintain the Corpus Christi Pipeline. CCP is required to reimburse O&M Services for all operating expenses incurred on behalf of CCP. Management Services Agreements (“MSAs”) CCL has a MSA with Shared Services pursuant to which Shared Services manages the construction and operation of the Liquefaction Facilities, excluding those matters provided for under the G&P Agreement and the CCL O&M Agreement. The services include, among other services, exercising the day-to-day management of CCL’s affairs and business, managing CCL’s regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Liquefaction Facilities and obtaining insurance. Prior to the substantial completion of each Train of the Liquefaction Facilities, no monthly fee payment is required except for reimbursement of expenses. After substantial completion of each Train, CCL will pay, in addition to the reimbursement of related expenses, a monthly fee equal to 3% of the capital expenditures incurred in the previous month and a fixed monthly fee of $375,000 for services with respect to such Train. CCP has a MSA with Shared Services pursuant to which Shared Services manages CCP’s operations and business, excluding those matters provided for under the CCP O&M Agreement. The services include, among other services, exercising the day-to-day management of CCP’s affairs and business, managing CCP’s regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Corpus Christi Pipeline and obtaining insurance. CCP is required to reimburse Shared Services for the aggregate of all costs and expenses incurred in the course of performing the services under the MSA. Natural Gas Supply Agreement CCL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. However, this entity was acquired by a non-related party on November 1, 2021; therefore, as of such date, this agreement ceased to be considered a related party. In addition to the amounts recorded on our Consolidated Statements of Operations in the table above, CCL recorded accrued liabilities—related party of $13 million, current derivative assets—related party of $3 million and derivative assets—related party of $1 million as of December 31, 2020 related to this agreement. Natural Gas Transportation Agreements Agreements with Related Party CCL is party to natural gas transportation agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project, for a period of 10 years which began in May 2020. Cheniere accounts for its investment in this related party as an equity method investment. In addition to the amounts recorded on our Consolidated Statements of Operations in the table above, CCL recorded accrued liabilities—related party of $1 million as of both December 31, 2021 and 2020 related to this agreement. Agreements with Cheniere Corpus Christi Liquefaction Stage III, LLC Cheniere Corpus Christi Liquefaction Stage III, LLC, a wholly owned subsidiary of Cheniere, has a transportation precedent agreement with CCP to secure firm pipeline transportation capacity for the transportation of natural gas feedstock to the expansion of the Corpus Christi LNG terminal it is constructing adjacent to the Liquefaction Project. The agreement will have a primary term of 20 years from the service commencement date with right to extend the term for two successive five Contracts for Sale and Purchase of Natural Gas and LNG CCL has an agreement with Sabine Pass Liquefaction, LLC that allows them to sell and purchase natural gas with each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate. CCL also has an agreement with Midship Pipeline Company, LLC that allows them to sell and purchase natural gas with each other. Land Agreements Lease Agreements CCL has agreements with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, to lease the land owned by Cheniere Land Holdings for the Liquefaction Facilities. The total annual lease payment is $0.6 million and the terms of the agreements range from three Easement Agreements CCL has agreements with Cheniere Land Holdings which grant CCL easements on land owned by Cheniere Land Holdings for the Liquefaction Facilities. The total annual payment for easement agreements is $0.1 million, excluding any previously paid one-time payments, and the terms of the agreements range from three Dredge Material Disposal Agreement CCL has a dredge material disposal agreement with Cheniere Land Holdings that terminates in 2042 which grants CCL permission to use land owned by Cheniere Land Holdings for the deposit of dredge material from the construction and maintenance of the Liquefaction Facilities. Under the terms of the agreement, CCL will pay Cheniere Land Holdings $0.50 per cubic yard of dredge material deposits up to 5.0 million cubic yards and $4.62 per cubic yard for any quantities above that. Tug Hosting Agreement In February 2017, CCL entered into a tug hosting agreement with Corpus Christi Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of Cheniere, to provide certain marine structures, support services and access necessary at the Liquefaction Facilities for Tug Services to provide its customers with tug boat and marine services. Tug Services is required to reimburse CCL for any third party costs incurred by CCL in connection with providing the goods and services. State Tax Sharing Agreements CCL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CCL 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, CCL will pay to Cheniere an amount equal to the state and local tax that CCL would be required to pay if CCL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere and Cheniere has not demanded any such payments from CCL under the agreement. The agreement is effective for tax returns due on or after May 2015. CCP has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CCP 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, CCP will pay to Cheniere an amount equal to the state and local tax that CCP would be required to pay if CCP’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere and Cheniere has not demanded any such payments from CCP under the agreement. The agreement is effective for tax returns due on or after May 2015. Equity Contribution Agreements Equity Contribution Agreement

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 Consolidated 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 Consolidated Financial Statements. LNG Terminal Commitments and Contingencies Natural Gas Supply, Transportation and Storage Service Agreements CCL has 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, CCL has natural gas transportation and storage service agreements for the Liquefaction Project. The initial terms of the natural gas transportation agreements range up 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The initial term of the natural gas storage service agreements ranges up to five years. As of December 31, 2021, CCL’s 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 $ 3.5 2023 2.1 2024 1.6 2025 1.2 2026 1.0 Thereafter 3.6 Total $ 13.0 (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread, and pricing of IPM agreements are variable based on global gas market prices less fixed liquefaction fees and certain costs by us .. 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. Services Agreements CCL and CCP 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 We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In the opinion of management, as of December 31, 2021, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

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 21% 31% 57% * 15% Customer B 16% 16% 23% * * Customer C 15% 14% —% * 10% Customer D * * * * 16% Customer E * * —% 31% 27% Customer F * * —% * 11% Customer G * —% —% 11% —% * 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 Spain $ 1,432 $ 1,001 $ 451 Singapore 694 134 — Indonesia 618 336 155 Ireland 599 285 — France 423 136 — United States 141 154 73 Total $ 3,907 $ 2,046 $ 679

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 $ 423 $ 345 $ 258 Non-cash distributions to affiliates for conveyance of assets — 2 — The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $20 million, $86 million and $187 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 Consolidated Financial Statements have been prepared in accordance with GAAP. Our Consolidated Financial Statements include the accounts of CCH and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. When necessary, reclassifications that are not material to our Consolidated Financial Statements are made to prior period financial information to conform to the current year presentation.
Use of Estimates, Policy	Use of Estimates The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. 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 restricted cash and cash equivalents, accounts receivable and accounts payable reported on the Consolidated 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 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 Consolidated Balance Sheets.
Accounts Receivables, 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 Consolidated Statements of Operations. We did not have any current expected credit losses on our accounts and other receivables as of December 31, 2021 and 2020.
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 our LNG terminal once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project 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 our LNG terminal. 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 $2 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, 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.
Regulated Natural Gas Pipelines, Policy	Regulated Natural Gas Pipelines The Corpus Christi Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to write off the associated regulatory assets and liabilities. Items that may influence our assessment are: • inability to recover cost increases due to rate caps and rate case moratoriums; • inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings; • excess capacity; • increased competition and discounting in the markets we serve; and • impacts of ongoing regulatory initiatives in the natural gas industry. Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipeline. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipeline is placed in service.
Derivative Instruments, Policy	Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated 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. 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. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. 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. CCL has entered into fixed price long-term SPAs generally with terms of 20 years with 10 third parties and have entered into agreements with Cheniere Marketing International LLP (“Cheniere Marketing”). CCL is 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, 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 Consolidated 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 Consolidated 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 Consolidated Statements of Operations. We classify debt on our Consolidated 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, 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. We have not recorded an ARO associated with the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.
Income Taxes, Policy	Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.
Business Segment, Policy	Business Segment Our liquefaction and pipeline business at the Corpus Christi LNG terminal represents 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 contracts expected to arise from the market transition from LIBOR to alternative reference rates. The transition period under this standard is effective March 12, 2020 and will apply through December 31, 2022. We have various credit facilities and interest rate swaps indexed to LIBOR, as further described in Note 1 0 —Debt . To date, we have amended certain of our credit facilities to incorporate a fallback replacement rate indexed to SOFR as a result of the expected LIBOR transition. We elected to apply the optional expedients as applicable to certain modified terms, however the impact of applying the optional expedients has not been material thus far. We will continue to elect to apply the optional expedients to qualifying contract modifications in the future.

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	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 $ 256 $ 182 Other accounts receivable 24 16 Total accounts and other receivables, net of current expected credit losses $ 280 $ 198

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 $ 88 $ 69 LNG 45 11 Natural gas 21 9 Other 2 — Total inventory $ 156 $ 89

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	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 and interconnecting pipeline facilities $ 13,222 $ 10,176 LNG site and related costs 294 276 LNG terminal construction-in-process 66 2,960 Accumulated depreciation (981) (568) Total LNG terminal, net of accumulated depreciation 12,601 12,844 Fixed assets Fixed assets 23 22 Accumulated depreciation (17) (13) Total fixed assets, net of accumulated depreciation 6 9 Property, plant and equipment, net of accumulated depreciation $ 12,607 $ 12,853
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 $ 419 $ 341 $ 230 Offsets to LNG terminal costs (1) 143 32 156 (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 Liquefaction Project during the testing phase for its construction.
Property Plant And Equipment Estimated Useful Lives Table	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) LNG storage tanks 50 Natural gas pipeline facilities 40 Marine berth, electrical, facility and roads 35 Water pipelines 30 Liquefaction processing equipment 6-50 Other 15-30

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair Value of Derivative Assets and Liabilities	The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of 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 CCH Interest Rate Derivatives liability $ — $ (40) $ — $ (40) $ — $ (140) $ — $ (140) Liquefaction Supply Derivatives asset (liability) 5 4 (1,221) (1,212) 4 (5) 12 11
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 Liability Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1) Physical Liquefaction Supply Derivatives $(1,221) Market approach incorporating present value techniques Henry Hub basis spread $(0.380) - $0.628 / $(0.035) Option pricing model International LNG pricing spread, relative to Henry Hub (2) 199% - 662% / 326% (1) Unobservable inputs were weighted by the relative fair value of the instruments.
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation	The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives, including those with related parties, during the years ended December 31, 2021, 2020 and 2019 (in millions): Year Ended December 31, 2021 2020 2019 Balance, beginning of period $ 12 $ 35 $ (4) Realized and mark-to-market gains (losses): Included in cost of sales (1,276) 28 (83) Purchases and settlements: Purchases 9 — 121 Settlements 34 (58) 1 Transfers into Level 3, net (1) — 7 — Balance, end of period $ (1,221) $ 12 $ 35 Change in unrealized gain (loss) relating to instruments still held at end of period $ (1,276) $ 28 $ (83) (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 derivative instruments on our Consolidated Balance Sheets (in millions): December 31, 2021 CCH Interest Rate Derivatives Liquefaction Supply Derivatives (1) Total Consolidated Balance Sheets Location Current derivative assets $ — $ 17 $ 17 Derivative assets — 37 37 Total derivative assets — 54 54 Current derivative liabilities (40) (628) (668) Derivative liabilities — (638) (638) Total derivative liabilities (40) (1,266) (1,306) Derivative liability, net $ (40) $ (1,212) $ (1,252) December 31, 2020 CCH Interest Rate Derivatives Liquefaction Supply Derivatives (1) Total Consolidated Balance Sheets Location Current derivative assets $ — $ 10 $ 10 Current derivative assets—related party — 3 3 Derivative assets — 114 114 Derivative assets—related party — 1 1 Total derivative assets — 128 128 Current derivative liabilities (100) (43) (143) Derivative liabilities (40) (74) (114) Total derivative liabilities (140) (117) (257) Derivative asset (liability), net $ (140) $ 11 $ (129) (1) Does not include collateral posted with counterparties by us of $13 million and $5 million, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract 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 12—Related Party Transactions
Derivative Net Presentation on Consolidated Balance Sheets	The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions): CCH Interest Rate Derivatives Liquefaction Supply Derivatives As of December 31, 2021 Gross assets $ — $ 76 Offsetting amounts — (22) Net assets $ — $ 54 Gross liabilities $ (40) $ (1,295) Offsetting amounts — 29 Net liabilities $ (40) $ (1,266) As of December 31, 2020 Gross assets $ — $ 132 Offsetting amounts — (4) Net assets $ — $ 128 Gross liabilities $ (140) $ (136) Offsetting amounts — 19 Net liabilities $ (140) $ (117)
Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of December 31, 2021, we had the following Interest Rate Derivatives outstanding: Notional Amounts December 31, 2021 December 31, 2020 Latest Maturity Date Weighted Average Fixed Interest Rate Paid Variable Interest Rate Received CCH Interest Rate Derivatives $4.5 billion $4.6 billion May 31, 2022 2.30% One-month LIBOR
Derivative Instruments, Gain (Loss)	The following table shows the effect and location of our Interest Rate Derivatives on our Consolidated Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions): Loss Recognized in Consolidated Statements of Operations Consolidated Statements of Operations Location Year Ended December 31, 2021 2020 2019 CCH Interest Rate Derivatives Interest rate derivative loss, net $ (1) $ (138) $ (101) CCH Interest Rate Forward Start Derivatives Interest rate derivative loss, net — (95) (33)
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Instruments, Gain (Loss)	The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions): Gain (Loss) Recognized in Consolidated Statements of Operations Consolidated Statements of Operations Location (1) Year Ended December 31, 2021 2020 2019 LNG revenues $ 4 $ (1) $ — Cost of sales (1,244) (27) 46 Cost of sales—related party (2) 11 (1) (1) (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 12—Related Party Transactions .

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 Contract assets, net of current expected credit losses $ 103 $ 48 Advances and other asset conveyances to third parties to support LNG terminal 24 22 Operating lease assets 4 5 Information technology service prepayments 3 3 Tax-related payments and receivables 2 3 Other 9 6 Total other non-current assets, net $ 145 $ 87

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 $ 531 $ 186 Interest costs and related debt fees 7 7 Liquefaction Project costs 43 76 Other 50 49 Total accrued liabilities $ 631 $ 318

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: 7.000% due 2024 $ 1,250 $ 1,250 5.875% due 2025 1,500 1,500 5.125% due 2027 1,500 1,500 3.700% due 2029 1,500 1,500 3.72% weighted average rate due 2039 2,721 1,971 Total Senior Secured Notes 8,471 7,721 CCH Credit Facility (1) 1,728 2,627 $1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) (2) 250 140 Total Debt 10,449 10,488 Current portion of long-term debt (117) (129) Short-term debt (250) (140) Unamortized discount and debt issuance costs, net (96) (118) Total long-term debt, net of discount and debt issuance costs $ 9,986 $ 10,101 (1) A portion of the outstanding balance that is due within one year is classified as current portion of long-term debt. (2) The CCH Working Capital Facility is classified as short-term debt.
Schedule of Maturities of Long-term Debt	Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2021 (in millions): Years Ending December 31, Principal Payments 2022 $ 367 2023 67 2024 2,794 2025 1,500 2026 — Thereafter 5,721 Total $ 10,449
Schedule of Line of Credit Facilities	Below is a summary of our credit facilities outstanding as of December 31, 2021 (in millions): CCH Credit Facility (1) CCH Working Capital Facility (2) Original facility size $ 8,404 $ 350 Incremental commitments 1,566 850 Less: Outstanding balance 1,729 250 Commitments prepaid or terminated 8,241 — Letters of credit issued — 361 Available commitment $ — $ 589 Priority ranking Senior secured Senior secured Interest rate on available balance LIBOR plus 1.75% or base rate plus 0.75% (3) LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75% (3) Weighted average interest rate of outstanding balance 1.85% 3.50% Commitment fees on undrawn balance n/a 0.50% Maturity date June 30, 2024 June 29, 2023 (1) Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our and our subsidiaries assets and by a pledge by Cheniere CCH Holdco I, LLC of its limited liability company interests in us. (2) Our obligations under the CCH Working Capital Facility are secured by substantially all of our and the CCH Guarantors assets as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility. (3) These facilities were amended in 2021 to establish a SOFR-indexed replacement rate for LIBOR.
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 $ 473 $ 484 $ 539 Capitalized interest, including amounts capitalized as an AFUDC (26) (119) (261) Total interest expense, net of capitalized interest $ 447 $ 365 $ 278
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) $ 6,500 $ 7,095 $ 5,750 $ 6,669 Senior notes — Level 3 (2) 1,971 2,227 1,971 2,387 Credit facilities — Level 3 (3) 1,978 1,978 2,767 2,767 (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 _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) $ 3,903 $ 2,047 $ 679 LNG revenues—affiliate 1,887 483 726 Total revenues from customers 5,790 2,530 1,405 Net derivative gain (loss) (2) 4 (1) — Total revenues $ 5,794 $ 2,529 $ 1,405 (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 $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized during the year ended December 31, 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the 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 Consolidated Balance Sheets (in millions): December 31, 2021 2020 Contract assets, net of current expected credit losses $ 104 $ 48
Contract Balances Reconciliation	The following table reflects the changes in our contract liabilities, which we classify as other non-current liabilities on our Consolidated Balance Sheets (in millions): Year Ended December 31, 2021 Deferred revenue, beginning of period $ — Cash received but not yet recognized in revenue 35 Revenue recognized from prior period deferral — Deferred revenue, end of period $ 35
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 $ 31.7 9 $ 32.3 10 LNG revenues—affiliate 1.1 10 1.0 12 Total revenues $ 32.8 $ 33.3 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

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 Consolidated 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 $ 1,837 $ 468 $ 719 Contracts for Sale and Purchase of Natural Gas and LNG 50 15 7 Total LNG revenues—affiliate 1,887 483 726 Cost of sales—affiliate Contracts for Sale and Purchase of Natural Gas and LNG 19 30 3 Cheniere Marketing Agreements 31 — — Total cost of sales—affiliate 50 30 3 Cost of sales—related party Natural Gas Supply Agreement (1) 146 114 86 Operating and maintenance expense—affiliate Services Agreements 105 89 58 Land Agreements 1 1 1 Total operating and maintenance expense—affiliate 106 90 59 Operating and maintenance expense—related party Natural Gas Transportation Agreements 9 6 — General and administrative expense—affiliate Services Agreements 28 20 11 (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
CCL [Member] | 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, CCL’s 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 $ 3.5 2023 2.1 2024 1.6 2025 1.2 2026 1.0 Thereafter 3.6 Total $ 13.0 (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread, and pricing of IPM agreements are variable based on global gas market prices less fixed liquefaction fees and certain costs by us .. 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 21% 31% 57% * 15% Customer B 16% 16% 23% * * Customer C 15% 14% —% * 10% Customer D * * * * 16% Customer E * * —% 31% 27% Customer F * * —% * 11% Customer G * —% —% 11% —% * 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 Spain $ 1,432 $ 1,001 $ 451 Singapore 694 134 — Indonesia 618 336 155 Ireland 599 285 — France 423 136 — United States 141 154 73 Total $ 3,907 $ 2,046 $ 679

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 $ 423 $ 345 $ 258 Non-cash distributions to affiliates for conveyance of assets — 2 —

Organization and Nature of Op_2

Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2021milliontonnes / yrunititemmitrains
Corpus Christi Pipeline [Member]
Organization and Nature of Operations [Line Items]
Length Of Natural Gas Pipeline | mi	21.5
Corpus Christi LNG Terminal [Member]
Organization and Nature of Operations [Line Items]
Number of Liquefaction LNG Trains Operating | trains	3
Total Production Capability | milliontonnes / yr	15
Number of LNG Storage Tanks | unit	3
Number of Marine Berths | item	2

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2021USD ($)customer	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Accounts Receivable, Allowance for Credit Loss, Current	$ 0	$ 0
Impairment expense related to property, plant and equipment	2,000,000	0	$ 0
Derivative instruments designated as cash flow hedges	0	0	0
Income Tax Expense (Benefit)	$ 0	$ 0	$ 0
Number of Reportable Segments | customer	1
Corpus Christi Pipeline [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Asset Retirement Obligation	$ 0
CCL [Member] | 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 | customer	10

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	$ 44	$ 70
CCL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 44	$ 70

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	$ 256	$ 182
Other accounts receivable	24	16
Total accounts and other receivables, net of current expected credit losses	$ 280	$ 198

Inventory (Details)

Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Inventory [Line Items]
Inventory	$ 156	$ 89
Materials [Member]
Inventory [Line Items]
Inventory	88	69
LNG [Member]
Inventory [Line Items]
Inventory	45	11
Natural gas [Member]
Inventory [Line Items]
Inventory	21	9
Other [Member]
Inventory [Line Items]
Inventory	$ 2	$ 0

Property, Plant and Equipment_3

Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 12,607	$ 12,853
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(981)	(568)
Property, plant and equipment, net of accumulated depreciation	12,601	12,844
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	13,222	10,176
LNG site and related costs [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	294	276
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	66	2,960
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	23	22
Accumulated depreciation	(17)	(13)
Property, plant and equipment, net of accumulated depreciation	$ 6	$ 9

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		$ 419	$ 341	$ 230
Offsets to LNG terminal costs	[1]	$ 143	$ 32	$ 156
[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 Liquefaction Project during the testing phase for its construction.

Property, Plant and Equipment_5

Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of 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
LNG storage tanks
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Natural gas pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
marine berth, electrical, facility and roads
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	35 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	15 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) - CCL [Member] - tbtu	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	10 years
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	2,915	3,152
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
CCH Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (40)	$ (140)
CCH Interest Rate Derivatives [Member] | 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	0	0
CCH Interest Rate Derivatives [Member] | 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	(40)	(140)
CCH Interest Rate Derivatives [Member] | 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	0	0
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(1,212)	11
Liquefaction Supply Derivatives [Member] | 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	5	4
Liquefaction Supply Derivatives [Member] | 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	4	(5)
Liquefaction Supply Derivatives [Member] | 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	$ (1,221)	$ 12

Derivative Instruments - Fair_2

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	12 Months Ended
	Dec. 31, 2021USD ($)
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability	$ (1,221,000,000)
Valuation, Market Approach [Member] | Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread	(0.380)
Valuation, Market Approach [Member] | Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread	0.628
Valuation, Market Approach [Member] | Weighted Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread	$ (0.035)	[1]
Valuation Technique, Option Pricing Model [Member] | Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	199.00%	[2]
Valuation Technique, Option Pricing Model [Member] | Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	662.00%	[2]
Valuation Technique, Option Pricing Model [Member] | Weighted Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	326.00%	[1],[2]
[1]	Unobservable inputs were weighted by the relative fair value of the instruments.
[2]	Spread contemplates U.S. dollar-denominated pricing.

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 (Liabilities) Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ 12	$ 35	$ (4)
Realized and mark-to-market gains (losses):
Included in cost of sales		(1,276)	28	(83)
Purchases and settlements:
Purchases		9	0	121
Settlements		34	(58)	1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	[1]	0	7	0
Balance, end of period		(1,221)	12	35
Change in unrealized gain (loss) relating to instruments still held at end of period		$ (1,276)	$ 28	$ (83)
[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 - Sche_2

Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - CCH Interest Rate Derivatives [Member] - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Derivative, Notional Amount	$ 4.5	$ 4.6
Maturity Date	May 31, 2022
Weighted Average Fixed Interest Rate Paid	2.30%

Derivative Instruments - Deriva

Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
CCH Interest Rate Derivatives [Member] | Interest rate derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ (1)	$ (138)	$ (101)
CCH Interest Rate Forward Start Derivatives [Member] | Interest rate derivative loss, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		0	(95)	(33)
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	4	(1)	0
Liquefaction Supply Derivatives [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	(1,244)	(27)	46
Liquefaction Supply Derivatives [Member] | Cost of sales—related party [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	$ 11	$ (1)	$ (1)
[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 12—Related Party Transactions .

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		$ 17	$ 10
Current derivative assets—related party		0	3
Derivative assets		37	114
Derivative assets—related party		0	1
Total derivative assets		54	128
Current derivative liabilities		(668)	(143)
Derivative liabilities		(638)	(114)
Total derivative liabilities		(1,306)	(257)
Derivative asset (liability), net		(1,252)	(129)
Current derivative assets
Derivatives, Fair Value [Line Items]
Current derivative assets		17	10
Current derivative assets—related party
Derivatives, Fair Value [Line Items]
Current derivative assets—related party			3
Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets		37	114
Non-current derivative assets—related party
Derivatives, Fair Value [Line Items]
Derivative assets—related party			1
Current derivative liabilities
Derivatives, Fair Value [Line Items]
Current derivative liabilities		(668)	(143)
Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities		(638)	(114)
CCH Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		0	0
Total derivative liabilities		(40)	(140)
Derivative asset (liability), net		(40)	(140)
CCH Interest Rate Derivatives [Member] | Current derivative assets
Derivatives, Fair Value [Line Items]
Current derivative assets		0	0
CCH Interest Rate Derivatives [Member] | Current derivative assets—related party
Derivatives, Fair Value [Line Items]
Current derivative assets—related party			0
CCH Interest Rate Derivatives [Member] | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets		0	0
CCH Interest Rate Derivatives [Member] | Non-current derivative assets—related party
Derivatives, Fair Value [Line Items]
Derivative assets—related party			0
CCH Interest Rate Derivatives [Member] | Current derivative liabilities
Derivatives, Fair Value [Line Items]
Current derivative liabilities		(40)	(100)
CCH Interest Rate Derivatives [Member] | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities		0	(40)
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[1]	54	128
Total derivative liabilities	[1]	(1,266)	(117)
Derivative asset (liability), net	[1]	(1,212)	11
Derivative, collateral posted by us		13	5
Liquefaction Supply Derivatives [Member] | Current derivative assets
Derivatives, Fair Value [Line Items]
Current derivative assets	[1]	17	10
Liquefaction Supply Derivatives [Member] | Current derivative assets—related party
Derivatives, Fair Value [Line Items]
Current derivative assets—related party	[1]		3
Liquefaction Supply Derivatives [Member] | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	37	114
Liquefaction Supply Derivatives [Member] | Non-current derivative assets—related party
Derivatives, Fair Value [Line Items]
Derivative assets—related party	[1]		1
Liquefaction Supply Derivatives [Member] | Current derivative liabilities
Derivatives, Fair Value [Line Items]
Current derivative liabilities	[1]	(628)	(43)
Liquefaction Supply Derivatives [Member] | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	$ (638)	$ (74)
[1]	Does not include collateral posted with counterparties by us of $13 million and $5 million, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract 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 12—Related Party Transactions

Derivative Instruments - Deri_2

Derivative Instruments - Derivative Net Presentation on Consolidated Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
CCH Interest Rate Derivative Asset
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 0	$ 0
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	0	0
Derivative Assets (Liabilities), at Fair Value, Net	0	0
CCH Interest Rate Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(40)	(140)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	0	0
Derivative Assets (Liabilities), at Fair Value, Net	(40)	(140)
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	76	132
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(22)	(4)
Derivative Assets (Liabilities), at Fair Value, Net	54	128
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(1,295)	(136)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	29	19
Derivative Assets (Liabilities), at Fair Value, Net	$ (1,266)	$ (117)

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]
Contract assets, net of current expected credit losses	$ 103	$ 48
Advances and other asset conveyances to third parties to support LNG terminal	24	22
Operating lease assets	4	5
Information technology service prepayments	3	3
Tax-related payments and receivables	2	3
Other	9	6
Total other non-current assets, net	$ 145	$ 87

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Accrued Liabilities, Current [Abstract]
Accrued natural gas purchases	$ 531	$ 186
Interest costs and related debt fees	7	7
Liquefaction Project costs	43	76
Other	50	49
Total accrued liabilities	$ 631	$ 318

Debt - Schedule of Debt Instrum

Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 10,449,000	$ 10,488,000
Current portion of long-term debt		(117,000)	(129,000)
Short-term debt		(250,000)	(140,000)
Unamortized discount and debt issuance costs, net		(96,000)	(118,000)
Total long-term debt, net of discount and debt issuance costs		9,986,000	10,101,000
CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 8,471,000	7,721,000
CCH Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.83%
2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,250,000	1,250,000
Debt Instrument, Interest Rate, Stated Percentage		7.00%
2025 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500,000	1,500,000
Debt Instrument, Interest Rate, Stated Percentage		5.875%
2027 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500,000	1,500,000
Debt Instrument, Interest Rate, Stated Percentage		5.125%
2029 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500,000	1,500,000
Debt Instrument, Interest Rate, Stated Percentage		3.70%
2039 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 2,721,000	1,971,000
2039 CCH Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.72%
CCH Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[1]	$ 1,728,000	2,627,000
CCH Working Capital Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[2]	250,000	$ 140,000
Short-term debt	[3]	(250,000)
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,200,000
[1]	A portion of the outstanding balance that is due within one year is classified as current portion of long-term debt.
[2]	The CCH Working Capital Facility is classified as short-term debt.
[3]	Our obligations under the CCH Working Capital Facility are secured by substantially all of our and the CCH Guarantors assets as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility.

Debt - Schedule of Maturities (

Debt - Schedule of Maturities (Details) $ in Thousands	Dec. 31, 2021USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2022	$ 367,000
2023	67,000
2024	2,794,000
2025	1,500,000
2026	0
Thereafter	5,721,000
Total	$ 10,449,000

Debt - Credit Facilities Table

Debt - Credit Facilities Table (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Outstanding balance - current		$ 250,000	$ 140,000
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	[1]	8,404,000
Incremental commitments	[1]	1,566,000
Outstanding balance	[1]	1,729,000
Commitments terminated	[1]	8,241,000
Letters of credit issued	[1]	0
Available commitment	[1]	$ 0
Debt Instrument, Description of Variable Rate Basis		LIBOR or the base rate
Weighted average interest rate of outstanding balance		1.85%
Maturity Date		Jun. 30, 2024
CCH Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	1.75%
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	0.75%
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	[3]	$ 350,000
Incremental commitments	[3]	850,000
Outstanding balance - current	[3]	250,000
Commitments terminated	[3]	0
Letters of credit issued	[3]	361,000
Available commitment	[3]	$ 589,000
Debt Instrument, Description of Variable Rate Basis		LIBOR or the base rate
Weighted average interest rate of outstanding balance		3.50%
Line of Credit Facility, Commitment Fee Percentage		0.50%
Maturity Date		Jun. 29, 2023
CCH Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	1.25%
CCH Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	1.75%
CCH Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	0.25%
CCH Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[2]	0.75%
[1]	Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our and our subsidiaries assets and by a pledge by Cheniere CCH Holdco I, LLC of its limited liability company interests in us.
[2]	These facilities were amended in 2021 to establish a SOFR-indexed replacement rate for LIBOR.
[3]	Our obligations under the CCH Working Capital Facility are secured by substantially all of our and the CCH Guarantors assets as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility.

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	$ 473	$ 484	$ 539
Capitalized interest, including amounts capitalized as an Allowance for Funds Used During Construction	(26)	(119)	(261)
Total interest expense, net of capitalized interest	$ 447	$ 365	$ 278

Debt - Schedule of Carrying Val

Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value		$ 10,449,000	$ 10,488,000
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]	6,500,000	5,750,000
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]	1,971,000	1,971,000
Senior notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	[1]	7,095,000	6,669,000
Senior notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	[2]	2,227,000	2,387,000
Credit facilities [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[3]	1,978,000	2,767,000
Credit facilities [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[3]	$ 1,978,000	$ 2,767,000
[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, 2021Rate	Dec. 31, 2020Rate
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	58.00%	33.00%
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	0.00%	0.00%

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		$ 5,790	$ 2,530	$ 1,405
Net derivative gain (loss)	[1]	4	(1)	0
Revenues		5,794	2,529	1,405
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	[2]	3,903	2,047	679
Revenues		3,907	2,046	679
Suspension Fees and LNG Cover Damages Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		0	435	0
Suspension Fees and LNG Cover Damages Revenue [Member] | Subsequent Period
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			38
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 1,887	$ 483	$ 726
[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 $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized during the year ended December 31, 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the 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	$ 104	$ 48
Change in Contract with Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	0
Cash received but not yet recognized in revenue	35
Revenue recognized from prior period deferral	0
Deferred revenue, end of period	$ 35

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			$ 33.3
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		$ 32.8
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 32.3
Weighted Average Recognition Timing	[1]		10 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		$ 31.7
Weighted Average Recognition Timing	[1]	9 years
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 1
Weighted Average Recognition Timing	[1]		12 years
LNG—affiliate [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		$ 1.1
Weighted Average Recognition Timing	[1]	10 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		$ 1,887	$ 483	$ 726
Cost of sales—affiliate		50	30	3
Cost of sales—related party		146	114	86
Operating and maintenance expense—affiliate		106	90	59
Operating and maintenance expense—related party		9	6	0
General and administrative expense—affiliate		28	20	11
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate		1,837	468	719
Cost of sales—affiliate		31	0	0
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate		50	15	7
Cost of sales—affiliate		19	30	3
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—related party	[1]	146	114	86
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate		105	89	58
General and administrative expense—affiliate		28	20	11
Land Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate		1	1	1
Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—related party		$ 9	$ 6	$ 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 - LN

Related Party Transactions - LNG Sale and Purchase Agreements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)tbtu	Dec. 31, 2020USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate | $	$ 315	$ 42
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
CCL [Member] | Affiliated Entity [Member] | Facility Swap Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
CCL [Member] | Cheniere Marketing [Member] | Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
Accounts receivable—affiliate | $	$ 314	$ 39
CCL [Member] | Cheniere Marketing [Member] | Cheniere Marketing Base SPA [Member]
Related Party Transaction [Line Items]
SPA, Term of Agreement	20 years
CCL [Member] | Cheniere Marketing [Member] | Cheniere Marketing Base SPA [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Volumes	150
CCL [Member] | Cheniere Marketing [Member] | Cheniere Marketing SPA [Member]
Related Party Transaction [Line Items]
Contract Volumes	15
CCL [Member] | Cheniere Marketing [Member] | Cheniere Marketing EOG SPA [Member]
Related Party Transaction [Line Items]
Contract Volumes	44

Related Party Transactions - Se

Related Party Transactions - Service Agreements (Details) - CCL [Member]	12 Months Ended
	Dec. 31, 2021USD ($)
Shared Services [Member] | Gas and Power Supply Services Agreement [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 125,000
Shared Services [Member] | Management Services Agreement [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 375,000
Monthly fee as a percentage of capital expenditures incurred in the previous month	3.00%
O&M Services [Member] | Operation and Maintenance Agreement [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 125,000

Related Party Transactions - Na

Related Party Transactions - Natural Gas Supply Agreement (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Accrued liabilities—related party	$ 1	$ 16
Current derivative assets—related party	0	3
Derivative assets—related party	$ 0	1
CCL [Member] | Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Accrued liabilities—related party		13
Current derivative assets—related party		3
Derivative assets—related party		$ 1

Related Party Transactions - Ot

Related Party Transactions - Other Agreements (Details)	12 Months Ended
	Dec. 31, 2021USD ($)yd3unit	Dec. 31, 2020USD ($)
Related Party Transaction [Line Items]
Due to affiliates	$ 35,000,000	$ 32,000,000
Accrued liabilities—related party	$ 1,000,000	16,000,000
CCL [Member] | Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Agreement Term	10 years
Accrued liabilities—related party	$ 1,000,000	$ 1,000,000
CCL [Member] | Cheniere Land Holdings [Member] | Lease Agreements [Member]
Related Party Transaction [Line Items]
Annual lease payment	$ 600,000
CCL [Member] | Cheniere Land Holdings [Member] | Lease Agreements [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Lease Term	3 years
CCL [Member] | Cheniere Land Holdings [Member] | Lease Agreements [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Lease Term	10 years
CCL [Member] | Cheniere Land Holdings [Member] | Easement Agreements [Member]
Related Party Transaction [Line Items]
Annual lease payment	$ 100,000
CCL [Member] | Cheniere Land Holdings [Member] | Easement Agreements [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Agreement Term	3 years
CCL [Member] | Cheniere Land Holdings [Member] | Easement Agreements [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Agreement Term	5 years
CCL [Member] | Cheniere Land Holdings [Member] | Dredge Material Disposal Agreement [Member]
Related Party Transaction [Line Items]
Dredge Material Deposits, Price Per Cubic Yard Of Deposit	$ 0.50
Dredge Material Deposits, Deposit Threshold | yd3	5,000,000
Dredge Material Deposits, Price Per Cubic Yard Of Deposit After Exceeding Threshold	$ 4.62
CCL [Member] | Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0
CCP [Member] | Cheniere Corpus Christi Liquefaction Stage III, LLC [Member] | Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Agreement Term	20 years
Related Party Agreement, Number Of Available Extensions | unit	2
Related Party Agreement, Term Of Available Extension	5 years
CCP [Member] | Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0

Related Party Transactions - Eq

Related Party Transactions - Equity Contribution Agreements (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Capital contributions		$ 0	$ 145,000,000	$ 711,000,000
Cheniere Revolving Credit Facility [Member]
Related Party Transaction [Line Items]
Letters of credit issued		0
CCH Credit Facility [Member]
Related Party Transaction [Line Items]
Letters of credit issued	[1]	0
Cheniere [Member] | Equity Contributions Agreement [Member]
Related Party Transaction [Line Items]
Capital contributions		703,000,000
Cheniere [Member] | Equity Contributions Agreement [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Capital contributions		1,100,000,000
Cheniere [Member] | Previous Equity Contributions Agreement [Member]
Related Party Transaction [Line Items]
Capital contributions		2,000,000,000
Cheniere [Member] | CCH Credit Facility [Member] | Equity Contributions Agreement [Member]
Related Party Transaction [Line Items]
Related Party Agreement, Additional Contribution Requirement, Debt Instrument, Commitments Reduction Threshold		$ 0
[1]	Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our and our subsidiaries assets and by a pledge by Cheniere CCH Holdco I, LLC of its limited liability company interests in us.

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details)	12 Months Ended
	Dec. 31, 2021item
Commitments and Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	0
Natural Gas Supply Agreements [Member] | CCL [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	10 years
Natural Gas Transportation Agreements [Member] | CCL [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	20 years
Storage Service Agreements [Member] | CCL [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	5 years

Commitments and Contingencies_2

Commitments and Contingencies - Purchase Obligation Table (Details) - CCL [Member] - Natural Gas Supply, Transportation And Storage Service Agreements [Member] $ in Billions	Dec. 31, 2021USD ($)	[1]
Long-term Purchase Commitment [Line Items]
2022	$ 3.5
2023	2.1
2024	1.6
2025	1.2
2026	1
Thereafter	3.6
Total	$ 13
[1]	Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread, and pricing of IPM agreements are variable based on global gas market prices less fixed liquefaction fees and certain costs by us .. 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	21.00%	31.00%	57.00%
Customer A [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		15.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%	16.00%	23.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%	14.00%	0.00%
Customer C [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
Customer D [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		16.00%
Customer E [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			0.00%
Customer E [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	31.00%	27.00%
Customer F [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			0.00%
Customer F [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		11.00%
Customer G [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		0.00%	0.00%
Customer G [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%	0.00%

Customer Concentration - Sche_2

Customer Concentration - Schedule of Revenue 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	$ 5,794	$ 2,529	$ 1,405
Geographic Concentration Risk [Member]
Concentration Risk [Line Items]
Revenues from External Customers	3,907	2,046	679
Geographic Concentration Risk [Member] | Spain
Concentration Risk [Line Items]
Revenues from External Customers	1,432	1,001	451
Geographic Concentration Risk [Member] | Singapore
Concentration Risk [Line Items]
Revenues from External Customers	694	134	0
Geographic Concentration Risk [Member] | Indonesia
Concentration Risk [Line Items]
Revenues from External Customers	618	336	155
Geographic Concentration Risk [Member] | Ireland
Concentration Risk [Line Items]
Revenues from External Customers	599	285	0
Geographic Concentration Risk [Member] | France
Concentration Risk [Line Items]
Revenues from External Customers	423	136	0
Geographic Concentration Risk [Member] | United States
Concentration Risk [Line Items]
Revenues from External Customers	$ 141	$ 154	$ 73

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	$ 423	$ 345	$ 258
Non-cash distributions to affiliates for conveyance of assets	0	2	0
Balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)	$ 20	$ 86	$ 187