Sabine Pass Liquefaction S-4 13 Jul 23 Registration of securities issued in business combination transactions Financial data

Cover Page

Cover Page	3 Months Ended
	Mar. 31, 2023
Document Information [Line Items]
Document Type	S-4
Entity Registrant Name	SABINE PASS LIQUEFACTION, LLC
Entity Incorporation, State or Country Code	DE
Entity Primary SIC Number	4924
Entity Tax Identification Number	27-3235920
Entity Address, Address Line One	700 Milam Street
Entity Address, Address Line Two	Suite 1900
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	375-5000
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0001499200
Amendment Flag	false
Business Contact [Member]
Document Information [Line Items]
Contact Personnel Name	Zach Davis
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

Statements of Income

Statements of Income - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Revenues
Revenues	$ 2,867	$ 3,245	$ 16,075		$ 9,112		$ 5,857
Revenues from contracts with customers	2,867	3,245	16,074		9,113		5,857
Operating costs and expenses
Cost of sales (excluding items shown separately below)	313	2,561	11,885		5,289		2,504
Cost of sales—affiliate	33	18	262		128		110
Cost of sales—related party			0		17		0
Operating and maintenance expense	176	148	652		548		547
Operating and maintenance expense—affiliate	124	117	482		457		466
Operating and maintenance expense—related party	16	12	72		46		13
General and administrative expense	1	1	0		4		9
General and administrative expense—affiliate	16	17	66		61		71
Depreciation and amortization expense	138	130	539		468		465
Other			0		6		1
Total operating costs and expenses	817	3,004	13,958		7,024		4,186
Income from operations	2,050	241	2,117		2,088		1,671
Other income (expense)
Interest expense, net of capitalized interest	(161)	(156)	(667)		(622)		(685)
Loss on modification or extinguishment of debt			(2)		(5)		(43)
Other income, net	4	0	7		0		0
Total other expense	(157)	(156)	(662)		(627)		(728)
Net income	1,893	85	1,455		1,461		943
LNG [Member]
Revenues
Revenues	2,106	2,488	11,507		7,639		5,195
Revenues from contracts with customers	2,106	2,488	11,506	[1]	7,640	[1]	5,195	[1]
LNG—affiliate
Revenues
Revenues from contracts with customers	$ 761	$ 757	4,568		1,472		662
LNG—related party [Member]
Revenues
Revenues from contracts with customers			$ 0		$ 1		$ 0
[1]LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2022 and 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

Balance Sheets

Balance Sheets - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current assets
Restricted cash and cash equivalents	$ 160	$ 92	$ 98
Trade and other receivables, net of current expected credit losses	265	622	571
Trade receivables—affiliate	263	553	232
Accounts receivable—related party		0	1
Advances to affiliate	131	151	127
Inventory	132	143	159
Current derivative assets	55	24	21
Margin deposits	0	35	7
Other current assets	31	33	53
Other current assets—affiliate	22	21	21
Total current assets	1,059	1,674	1,290
Property, plant and equipment, net of accumulated depreciation	13,689	13,805	14,433
Debt issuance costs, net of accumulated amortization	5	5	7
Derivative assets	32	28	33
Other non-current assets, net	167	160	171
Total assets	14,952	15,672	15,934
Current liabilities
Accounts payable	66	28	18
Accrued liabilities	610	1,314	1,012
Accrued liabilities—related party	5	6	4
Current debt, net of discount and debt issuance costs	60	0
Due to affiliates	38	80	73
Deferred revenue	72	132	132
Current derivative liabilities	400	769	16
Other current liabilities	9	0
Total current liabilities	1,260	2,329	1,255
Long-term debt, net of premium, discount and debt issuance costs	11,985	12,040	13,023
Derivative liabilities	2,157	3,024	11
Other non-current liabilities	7	7	7
Other non-current liabilities—affiliate	20	20	17
Member's deficit	(477)	(1,748)	1,621
Total liabilities and member's equity (deficit)	$ 14,952	$ 15,672	$ 15,934

Statements of Member's Equity (

Statements of Member's Equity (Deficit) - USD ($) $ in Millions	Total	Sabine Pass LNG-LP, LLC [Member]
Members' equity, beginning of period at Dec. 31, 2019	$ 534	$ 534
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	488	488
Distributions	(1,007)	(1,007)
Net income	943	943
Member's equity, end of period at Dec. 31, 2020	958	958
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	821	821
Distributions	(1,619)	(1,619)
Net income	1,461	1,461
Member's equity, end of period at Dec. 31, 2021	1,621	1,621
Increase (Decrease) in Partners' Capital [Roll Forward]
Novated IPM agreement	(2,712)	(2,712)
Distributions	(563)	(563)
Net income	85	85
Member's equity, end of period at Mar. 31, 2022	(1,569)	(1,569)
Members' equity, beginning of period at Dec. 31, 2021	1,621	1,621
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	225	225
Novated IPM agreement	(2,712)	(2,712)
Non-cash distributions to affiliates for conveyance of assets	(576)	(576)
Distributions	(1,761)	(1,761)
Net income	1,455	1,455
Member's equity, end of period at Dec. 31, 2022	(1,748)	(1,748)
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions	(622)	(622)
Net income	1,893	1,893
Member's equity, end of period at Mar. 31, 2023	$ (477)	$ (477)

Statements of Cash Flows

Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities
Net income	$ 1,893	$ 85	$ 1,455	$ 1,461	$ 943
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	138	130	539	468	465
Amortization of debt issuance costs, premium and discount	6	5	24	22	24
Loss on modification of debt			2	5	43
Total losses (gains) on derivative instruments, net	(1,260)	525	1,158	(29)	49
Total gains on derivatives instruments, net—related party			0	(2)	0
Other			7	6	1
Net cash used for settlement of derivative instruments	(11)	(9)	(102)	(17)	(4)
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	357	83	(116)	(203)	(17)
Trade receivables—affiliate	290	(73)	(337)	(32)	(80)
Accounts receivable—related party			0	(1)	0
Advances to affiliate	18	(5)	(24)	(5)	5
Inventory	11	26	15	(66)	9
Margin deposits	35	25	(28)	(3)	(2)
Accounts payable and accrued liabilities	(615)	(5)	348	326	2
Accrued liabilities—related party	(2)	1	3	(1)	4
Due to affiliates	(40)	(21)	22	(1)	9
Deferred revenue	(60)	(38)	0	18	(18)
Deferred revenue—affiliate			0	0	(10)
Other, net	18	(44)	2	(11)	1
Other, net—affiliate	(1)	1	5	2	0
Net cash provided by operating activities	777	686	2,973	1,937	1,424
Cash flows from investing activities
Property, plant and equipment	(82)	(85)	(434)	(612)	(916)
Other	(5)	0
Net cash used in investing activities	(87)	(85)	(434)	(612)	(916)
Cash flows from financing activities
Proceeds from issuances of debt			560	482	1,995
Redemptions and repayments of debt			(1,560)	(1,000)	(2,000)
Debt issuance and other financing costs			(7)	(5)	(35)
Debt extinguishment costs			(2)	(3)	(39)
Capital contributions			225	821	488
Distributions	(622)	(563)	(1,761)	(1,619)	(1,001)
Net cash used in financing activities	(622)	(563)	(2,545)	(1,324)	(592)
Net increase in restricted cash and cash equivalents	68	38	(6)	1	(84)
Restricted cash and cash equivalents—beginning of period	92	98	98	97	181
Restricted cash and cash equivalents—end of period	$ 160	$ 136	$ 92	$ 98	$ 97

Nature of Operations and Basis

Nature of Operations and Basis of Presentation	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations and Basis of Presentation	NOTE 1-NATURE We are a Delaware limited liability company formed by CQP and based in Houston with one member, Sabine Pass LNG-LP, LNG-related The natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) has six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities owned by SPLNG. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. In February 2023, we and another subsidiary of CQP initiated the pre-filing Basis of Presentation The accompanying unaudited Financial Statements of SPL have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 S-X 10-K Results of operations for the three months ended March 31, 2023 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2023. We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss is included in the federal income tax return of CQP. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP’s taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. Recent Accounting Standards ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard. We have not yet applied the optional expedients available under the standard because we have not yet modified any of our existing contracts indexed to LIBOR, mainly our credit facility as further described in Note 8-Debt,	NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS We are a Delaware limited liability company formed by CQP and based in Houston with one member, Sabine Pass LNG-LP, LNG-related The natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) has six operational Trains, with Train 6 having achieved substantial completion on February 4, 2022, for a total operational production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities owned by SPLNG. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Our Financial Statements have been prepared in accordance with GAAP. Use of Estimates The preparation of our Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment and asset retirement obligations (“AROs”) as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market. In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates. Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, margin deposits, accounts payable and accrued liabilities reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Revenue Recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 11—Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Current Expected Credit Losses Trade and other receivables are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Statements of Income. As of December 31, 2022 and 2021, we had current expected credit losses of zero and $5 million, respectively, on our trade and other receivables and as of both December 31, 2022 and 2021, we had current expected credit losses of zero on our non-current 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 for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method. Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end 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 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 on disposal are recorded in other operating costs and expenses. 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 did not record any material impairments related to property, plant and equipment during the years ended December 31, 2022, 2021 and 2020. Interest Capitalization We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. construction-in-process in-service Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis. For those derivative instruments measured at fair value, changes in the fair value of the 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, 2022, 2021 and 2020. See Note 7—Derivative Instruments for additional details about our derivative instruments. Concentration of Credit Risk Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter We have entered into fixed price long-term SPAs generally with terms of 20 years with 11 third parties and have entered into agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 14—Customer Concentration for additional details about our customer concentration. Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter pre-established non-exchange Debt Our debt consists of current and long-term secured and unsecured debt securities and a credit facility with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors. Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in loss on modification or extinguishment of debt on our Statements of Income. We classify debt on our Balance Sheets based on contractual maturity, with the following exceptions: • We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement. • We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date. Asset Retirement Obligations We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. We have not recorded an ARO associated with the Sabine Pass LNG Terminal. Based on the real property lease agreements at the Sabine Pass LNG Terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG Terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial. Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss included in the federal income tax return of CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2022, the tax basis of our assets and liabilities was $5.8 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our tax sharing agreement. Business Segment Our liquefaction operations at the Sabine Pass LNG Terminal represent a single Recent Accounting Standards ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, subsequent amendment to the standard. We have not yet applied the optional expedients available under the standard because we have not yet modified any of our existing contracts indexed to LIBOR, mainly our credit facility as further described in Note 10—Debt, for reference rate reform. However, we do not expect the impact of applying the optional expedients to any future contract modifications to be material, and we do not expect the transition to a replacement rate index to have a material impact on our future cash flows.

Restricted Cash and Cash Equiva

Restricted Cash and Cash Equivalents	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Restricted Cash and Cash Equivalents [Abstract]
Restricted Cash and Cash Equivalents	NOTE 2-RESTRICTED 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. As of March 31, 2023 and December 31, 2022, we had $160 million and $92 million of restricted cash and cash equivalents, respectively, as required under the above agreement.	NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS 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. As of December 31, 2022 and 2021, we had $92 million and $98 million of restricted cash and cash equivalents, respectively, as required by the above agreement.

Trade and Other Receivables, Ne

Trade and Other Receivables, Net of Current Expected Credit Losses	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Receivables [Abstract]
Trade and Other Receivables, Net of Current Expected Credit Losses	NOTE 3-TRADE Trade and other receivables, net of current expected credit losses consisted of the following (in millions): March 31, December 31, Trade receivables $ 259 $ 603 Other receivables 6 19 Total trade and other receivables, net of current expected credit losses $ 265 $ 622	NOTE 4—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES Trade and other receivables, net of current expected credit losses consisted of the following (in millions): December 31, 2022 2021 Trade receivables $ 603 $ 546 Other receivables 19 25 Total trade and other receivables, net of current expected credit losses $ 622 $ 571

Inventory

Inventory	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Inventory Disclosure [Abstract]
Inventory	NOTE 4-INVENTORY Inventory consisted of the following (in millions): March 31, December 31, Materials $ 90 $ 87 LNG 19 26 Natural gas 22 28 Other 1 2 Total inventory $ 132 $ 143	NOTE 5—INVENTORY Inventory consisted of the following (in millions): December 31, 2022 2021 Materials $ 87 $ 71 LNG 26 44 Natural gas 28 43 Other 2 1 Total inventory $ 143 $ 159

Property, Plant and Equipment,

Property, Plant and Equipment, Net of Accumulated Depreciation	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net of Accumulated Depreciation	NOTE 5-PROPERTY, Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions): March 31, December 31, LNG terminal Terminal $ 16,262 $ 16,240 Construction-in-process 113 114 Accumulated depreciation (2,690 ) (2,553 ) Total LNG terminal, net of accumulated depreciation 13,685 13,801 Fixed assets Fixed assets 19 19 Accumulated depreciation (15 ) (15 ) Total fixed assets, net of accumulated depreciation 4 4 Property, plant and equipment, net of accumulated depreciation $ 13,689 $ 13,805 The following table shows depreciation expense and offsets to LNG terminal costs (in millions): Three Months Ended March 31, 2023 2022 Depreciation expense $ 137 $ 129 Offsets to LNG terminal costs (1) — 148 (1) We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.	NOTE 6—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions): December 31, 2022 2021 LNG terminal Terminal $ 16,240 $ 13,751 Construction-in-process 114 2,699 Accumulated depreciation (2,553 ) (2,021 ) Total LNG terminal, net of accumulated depreciation 13,801 14,429 Fixed assets Fixed assets 19 19 Accumulated depreciation (15 ) (15 ) Total fixed assets, net of accumulated depreciation 4 4 Property, plant and equipment, net of accumulated depreciation $ 13,805 $ 14,433 (1) In October 2022, we completed construction of the third marine berth at the Sabine Pass LNG Terminal for a total cost of $576 million and upon completion, we conveyed the property, plant and equipment associated with the third berth to SPLNG. The following table shows depreciation expense and offsets to LNG terminal costs (in millions): Year Ended December 31, 2022 2021 2020 Depreciation expense $ 534 $ 463 $ 460 Offsets to LNG terminal costs (1) 148 105 — (1) We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction. LNG Terminal Costs LNG terminal costs related to the Liquefaction Project are Components Useful life (years) Water pipelines 30 Liquefaction processing equipment 6-50 Other 10-30 Fixed Assets Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

Derivative Instruments

Derivative Instruments	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	NOTE 6-DERIVATIVE We have commodity derivatives consisting of natural gas supply contracts, including those under our IPM agreement, for the operation of the Liquefaction Project and associated economic hedges (collectively, “Liquefaction Supply Derivatives”). We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Statements of Income to the extent not utilized for the commissioning process, in which case such changes are capitalized. The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis (in millions): Fair Value Measurements as of March 31, 2023 December 31, 2022 Quoted (Level 1) Significant (Level 2) Significant (Level 3) Total Quoted (Level 1) Significant (Level 2) Significant (Level 3) Total Liquefaction Supply Derivatives asset (liability) $ 28 $ 4 $ (2,502 ) $ (2,470 ) $ (12 ) $ (10 ) $ (3,719 ) $ (3,741 ) We value our Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data. The fair value of our 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 significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and volatility. The Level 3 fair value measurements of our natural gas positions within our 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 Liquefaction Supply Derivatives as of March 31, 2023: Net Fair Value (in millions) Valuation Approach Significant Unobservable Range of Significant Liquefaction Supply Derivatives $ (2,502 ) Market approach incorporating present value techniques Henry Hub basis spread $(1.173) - $0.361 / Option pricing model International LNG 93% - 574% / 208% (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 Liquefaction Supply Derivatives. The following table shows the changes in the fair value of our Level 3 Liquefaction Supply Derivatives (in millions): Three Months Ended March 31, 2023 2022 Balance, beginning of period $ (3,719 ) $ 38 Realized and change in fair value gains (losses) included in net income (1): Included in cost of sales, existing deals (2) 1,049 (53 ) Included in cost of sales, new deals (3) 3 — Purchases and settlements: Purchases (4) — (3,141 ) Settlements (5) 165 (6 ) Balance, end of period $ (2,502 ) $ (3,162 ) Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period $ 1,052 $ (53 ) (1) Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table. (2) Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period. (3) Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period. (4) Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. (5) Roll-off All counterparty derivative contracts provide for the unconditional right of set-off set-off set-off Liquefaction Supply Derivatives We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The terms of the Liquefaction Supply Derivatives range up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs. The forward notional amount for our Liquefaction Supply Derivatives was approximately 6,027 TBtu and 5,972 TBtu as of March 31, 2023 and December 31, 2022, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of March 31, 2023. The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Income (in millions): Gain (Loss) Recognized in Statements of Income Statements of Income Location (1) Three Months Ended March 31, 2023 2022 Cost of sales $ 1,260 $ (525 ) (1) Does not include the 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. Fair Value and Location of Derivative Assets and Liabilities on the Balance Sheets The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions): Fair Value Measurements as of (1) Balance Sheets Location March 31, 2023 December 31, 2022 Current derivative assets $ 55 $ 24 Derivative assets 32 28 Total derivative assets 87 52 Current derivative liabilities (400 ) (769 ) Derivative liabilities (2,157 ) (3,024 ) Total derivative liabilities (2,557 ) (3,793 ) Derivative liability, net $ (2,470 ) $ (3,741 ) (1) Does not include collateral posted by counterparties to us of $8 million as of March 31, 2023, which is included in other current liabilities on our Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits in our Balance Sheets. Balance Sheets Presentation The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Balance Sheets: Liquefaction Supply Derivatives March 31, 2023 December 31, 2022 Gross assets $ 89 $ 57 Offsetting amounts (2 ) (5 ) Net assets $ 87 $ 52 Gross liabilities $ (2,577 ) $ (3,814 ) Offsetting amounts 20 21 Net liabilities $ (2,557 ) $ (3,793 )	NOTE 7-DERIVATIVE We have entered into commodity derivatives consisting of natural gas supply contracts, including those under our IPM agreement, for the operation of the Liquefaction Project and associated economic hedges (collectively, “Liquefaction Supply Derivatives”). We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Statements of Income to the extent not utilized for the commissioning process, in which case such changes are capitalized. The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis (in millions): Fair Value Measurements as of December 31, 2022 December 31, 2021 Quoted Prices (Level 1) Significant Other (Level 2) Significant (Level 3) Total Quoted Prices (Level 1) Significant Other (Level 2) Significant (Level 3) Total Liquefaction Supply Derivatives asset (liability) $ (12 ) $ (10 ) $ (3,719 ) $ (3,741 ) $ 2 $ (13 ) $ 38 $ 27 We value our Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data. The fair value of our 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 significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and volatility. The Level 3 fair value measurements of natural gas positions within our 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 Liquefaction Supply Derivatives as of December 31, 2022: Net Fair Value (in millions) Valuation Approach Significant Range of Significant Liquefaction Supply Derivatives $ (3,719 ) Market approach incorporating present value techniques Henry Hub basis spread $(1.775) - $0.660 / $(0.063) Option pricing model International LNG 77% - 515% / 193% (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 Liquefaction Supply Derivatives. The following table shows the changes in the fair value of our Level 3 Liquefaction Supply Derivatives (in millions): Year Ended December 31, 2022 2021 2020 Balance, beginning of period $ 38 $ (21 ) $ 24 Realized and change in fair value gains (losses) included in net income (1): Included in cost of sales, existing deals (2) (228 ) 74 (43 ) Included in cost of sales, new deals (3) (804 ) — — Purchases and settlements: Purchases (4) (2,712 ) (10 ) 5 Settlements (5) (13 ) (5 ) (7 ) Balance, end of period $ (3,719 ) $ 38 $ (21 ) Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period $ (1,032 ) $ 74 $ (43 ) (1) Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table. (2) Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period. (3) Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period. (4) Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. For further discussion of IPM agreements that were novated to us during the period, see Note 15-Supplemental (5) Roll-off All counterparty derivative contracts provide for the unconditional right of set-off set-off set-off Liquefaction Supply Derivatives We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The terms of the Liquefaction Supply Derivatives range up to 15 years, some of which commence upon the satisfaction of certain events or states of affairs. The forward notional amount for our Liquefaction Supply Derivatives was approximately 5,972 TBtu and 5,194 TBtu as of December 31, 2022 and 2021, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of December 31, 2022. The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Income (in millions): Gain (Loss) Recognized in Statements of Income Statements of Income Location (1) Year Ended December 31, 2022 2021 2020 LNG revenues $ 1 $ (1 ) $ — Cost of sales (1,159 ) 30 (49 ) Cost of sales-related party — 2 — (1) Does not include the 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. Fair Value and Location of Derivative Assets and Liabilities on the Balance Sheets The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions): Fair Value Measurements as of (1) Balance Sheets Location December 31, 2022 December 31, 2021 Current derivative assets $ 24 $ 21 Derivative assets 28 33 Total derivative assets 52 54 Current derivative liabilities (769 ) (16 ) Derivative liabilities (3,024 ) (11 ) Total derivative liabilities (3,793 ) (27 ) Derivative asset (liability), net $ (3,741 ) $ 27 (1) Does not include collateral posted with counterparties by us of $35 million and $7 million, as of December 31, 2022 and 2021, respectively, which are included in margin deposits in our Balance Sheets. Balance Sheets Presentation The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Balance Sheets: Liquefaction Supply Derivatives As of December 31, 2022 Gross assets $ 57 Offsetting amounts (5 ) Net assets $ 52 Gross liabilities $ (3,814 ) Offsetting amounts 21 Net liabilities $ (3,793 ) As of December 31, 2021 Gross assets $ 79 Offsetting amounts (25 ) Net assets $ 54 Gross liabilities $ (33 ) Offsetting amounts 6 Net liabilities $ (27 )

Other Non-Current Assets, Net

Other Non-Current Assets, Net	12 Months Ended
	Dec. 31, 2022
Other Assets, Noncurrent [Abstract]
Other Non-Current Assets, Net	NOTE 8-OTHER NON-CURRENT Other non-current December 31, 2022 2021 Advances made to municipalities for water system enhancements $ 78 $ 81 Advances and other asset conveyances to third parties to support LNG terminal 31 37 Operating lease assets 23 23 Advances made under EPC and non-EPC — 5 Information technology service prepayments 4 4 Other 24 21 Total other non-current $ 160 $ 171

Accrued Liabilities

Accrued Liabilities	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	NOTE 7-ACCRUED Accrued liabilities consisted of the following (in millions): March 31, 2023 December 31, 2022 Natural gas purchases $ 406 $ 1,017 Interest costs and related debt fees 118 165 Liquefaction Project costs 80 125 Other accrued liabilities 6 7 Total accrued liabilities $ 610 $ 1,314	NOTE 9-ACCRUED Accrued liabilities consisted of the following (in millions): December 31, 2022 2021 Natural gas purchases $ 1,017 $ 786 Interest costs and related debt fees 165 133 Liquefaction Project costs 125 89 Other accrued liabilities 7 4 Total accrued liabilities $ 1,314 $ 1,012

Debt

Debt	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Debt	NOTE 8-DEBT Debt consisted of the following (in millions): March 31, 2023 December 31, 2022 Senior Secured Notes: 5.75% due 2024 $ 2,000 $ 2,000 5.625% due 2025 2,000 2,000 5.875% due 2026 1,500 1,500 5.00% due 2027 1,500 1,500 4.200% due 2028 1,350 1,350 4.500% due 2030 2,000 2,000 4.746% weighted average rate due 2037 1,782 1,782 Total Senior Secured Notes 12,132 12,132 Working capital revolving credit and letter of credit reimbursement agreement (the “Working Capital Facility”) — — Total debt 12,132 12,132 Current portion of long-term debt (1) (60 ) — Long-term portion of unamortized premium, discount and debt issuance costs, net (87 ) (92 ) Total long-term debt, net of premium, discount and debt issuance costs $ 11,985 $ 12,040 (1) As of March 31, 2023, $60 million of debt with contractual maturities of greater than one year was classified as current portion of long-term debt based on our intent and ability to repay the debt with cash that was on hand at March 31, 2023, including repurchases of debt subsequent to the balance sheet date and through April 26, 2023. Working Capital Facility Below is a summary of our Working Capital Facility as of March 31, 2023 (in millions): Working Capital Facility Total facility size $1,200 Less: Outstanding balance — Letters of credit issued 329 Available commitment $ 871 Priority ranking Senior secured Interest rate on available balance (1) LIBOR 0.125% - 0.750% Commitment fees on undrawn balance (1) 0.10% - 0.30% Maturity date March 19, 2025 (1) The margin on the interest rate and the commitment fees is subject to change based on our credit rating. Restrictive Debt Covenants The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit our ability to make certain investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied. As of March 31, 2023, we were in compliance with all covenants related to our debt agreements. Interest Expense Total interest expense, net of capitalized interest, consisted of the following (in millions): Three Months Ended March 31, 2023 2022 Total interest cost $ 163 $ 177 Capitalized interest (2 ) (21 ) Total interest expense, net of capitalized interest $ 161 $ 156 Fair Value Disclosures The following table shows the carrying amount and estimated fair value of our debt (in millions): March 31, 2023 December 31, 2022 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior notes - Level 2 (1) $ 10,780 $ 10,718 $ 10,780 $ 10,569 Senior notes - Level 3 (2) 1,352 1,241 1,352 1,224 (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. The estimated fair value of our Working Capital Facility approximates the principal amount outstanding because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.	NOTE 10-DEBT Debt consisted of the following (in millions): December 31, 2022 2021 Senior Secured Notes: 5.625% due 2023 $ — $ 1,500 5.75% due 2024 2,000 2,000 5.625% due 2025 2,000 2,000 5.875% due 2026 1,500 1,500 5.00% due 2027 1,500 1,500 4.200% due 2028 1,350 1,350 4.500% due 2030 2,000 2,000 4.746% weighted average rate due 2037 1,782 1,282 Total Senior Secured Notes 12,132 13,132 Working capital revolving credit and letter of credit reimbursement agreement (the “Working Capital Facility”) — — Total debt 12,132 13,132 Unamortized premium, discount and debt issuance costs, net (92 ) (109 ) Total long-term debt, net of premium, discount and debt issuance costs $ 12,040 $ 13,023 Senior Secured Notes The Senior Secured Notes are our senior secured obligations, ranking equally in right of payment with our other existing and future senior debt and secured by the same collateral and senior in right of payment to any of its future subordinated debt. Subject to permitted liens, the Senior Secured Notes are secured on a pari passu Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2022 (in millions): Years Ending December 31, Principal Payments 2023 $ — 2024 2,000 2025 2,051 2026 1,608 2027 1,612 Thereafter 4,861 Total $ 12,132 Working Capital Facility Below is a summary of our Working Capital Facility as of December 31, 2022 (in millions): Working Capital Facility (1) Total facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 328 Available commitment $ 872 Priority ranking Senior secured Interest rate on available balance (2) LIBOR Commitment fees on undrawn balance (2) 0.10% - 0.30% Maturity date March 19, 2025 (1) Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu (2) The margin on the interest rate and the commitment fees are subject to change based on our credit rating. Restrictive Debt Covenants The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit our ability to make certain investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied. As of December 31, 2022, we were in compliance with all covenants related to our debt agreements. Interest Expense Total interest expense, net of capitalized interest consisted of the following (in millions): Year Ended December 31, 2022 2021 2020 Total interest cost $ 706 $ 754 $ 779 Capitalized interest (39 ) (132 ) (94 ) Total interest expense, net of capitalized interest $ 667 $ 622 $ 685 Fair Value Disclosures The following table shows the carrying amount and estimated fair value of our debt (in millions): December 31, 2022 December 31, 2021 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior notes - Level 2 (1) $ 10,780 $ 10,569 $ 11,850 $ 13,128 Senior notes - Level 3 (2) 1,352 1,224 1,282 1,466 (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. The estimated fair value of our Working Capital Facility approximates the principal amount outstanding because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without pen alty.

Revenues

Revenues	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Revenues	NOTE 9-REVENUES The following table represents a disaggregation of revenue earned (in millions): Three Months Ended March 31, 2023 2022 Revenues from contracts with customers LNG revenues $ 2,106 $ 2,488 LNG revenues-affiliate 761 757 Total revenues from contracts with customers $ 2,867 $ 3,245 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 March 31, December 31, Contract assets, net of current expected credit losses $ 1 $ 1 The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions): Three Months Ended March 31, 2023 Deferred revenue, beginning of period $ 132 Cash received but not yet recognized in revenue 72 Revenue recognized from prior period deferral (132 ) Deferred revenue, end of period $ 72 The following table reflects the changes in our contract liabilities to affiliate, which we classify as other non-current Three Months Ended March 31, 2023 Deferred revenue-affiliate, beginning of period $ 5 Cash received but not yet recognized in revenue 5 Revenue recognized from prior period deferral (5 ) Deferred revenue-affiliate, end of period $ 5 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: March 31, 2023 December 31, 2022 Unsatisfied Transaction Weighted Average Unsatisfied Transaction Weighted Average LNG revenues $ 49.9 8 $ 50.8 8 LNG revenues-affiliate 1.8 2 2.0 2 Total revenues $ 51.7 $ 52.8 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price. We have elected the following exemptions which omit certain potential future sources of revenue from the table above: (1) We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less. (2) The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 61% and 67% of our LNG revenues from contracts included in the table above during the three months ended March 31, 2023 and 2022, respectively, were related to variable consideration received from customers. Approximately 73% and 100% of our LNG revenues-affiliate from contracts included in the table above during the three months ended March 31, 2023 and 2022, respectively, were related to variable consideration received from customers. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.	NOTE 11-REVENUES The following table represents a disaggregation of revenue earned (in millions): Year Ended December 31, 2022 2021 2020 Revenues from contracts with customers LNG revenues (1) $ 11,506 $ 7,640 $ 5,195 LNG revenues-affiliate 4,568 1,472 662 LNG revenues-related party — 1 — Total revenues from contracts with customers 16,074 9,113 5,857 Net derivative gain (loss) (2) 1 (1 ) — Total revenues $ 16,075 $ 9,112 $ 5,857 (1) LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2022 and 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. (2) See Note 7-Derivative LNG Revenues We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Sabine Pass LNG Terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues-affiliate. See Note 12-Related Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG Terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price. Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use. Sales of natural gas where, in the delivery of the natural gas to the end customer, we have concluded that we acted as a principal are presented within revenues in our Statements of Income, and where we have concluded that we acted as an agent are netted within cost of sales in our Statements of Income. 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 December 31, 2022 2021 Contract assets, net of current expected credit losses $ 1 $ 1 Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions): Year Ended December 31, 2022 Deferred revenue, beginning of period $ 132 Cash received but not yet recognized in revenue 132 Revenue recognized from prior period deferral (132 ) Deferred revenue, end of period $ 132 The following table reflects the changes in our contract liabilities to affiliate, which we classify as other non-current Year Ended December 31, 2022 Deferred revenue-affiliate, beginning of period $ 2 Cash received but not yet recognized in revenue 5 Revenue recognized from prior period deferral (2 ) Deferred revenue-affiliate, end of period $ 5 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, 2022 and 2021 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG und er 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: December 31, 2022 December 31, 2021 Unsatisfied Transaction Weighted Average Recognition Unsatisfied Transaction Weighted Average Recognition LNG revenues $ 50.8 8 $ 49.3 9 LNG revenues-affiliate 2.0 2 2.1 3 Total revenues $ 52.8 $ 51.4 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price. We have elected the following exemptions which omit certain potential future sources of revenue from the table above: (1) We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less. (2) The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 74% and 61% of our LNG revenues from contracts included in the table above during the years ended December 31, 2022 and 2021, respectively, were related to variable consideration received from customers. Approximately 75% and 96% of our LNG revenues-affiliate from contracts included in the table above during the years ended December 31, 2022 and 2021, respectively, were related to variable consideration received from customers. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

Related Party Transactions

Related Party Transactions	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 10-RELATED Below is a summary of our related party transactions as reported on our Statements of Income (in millions): Three Months Ended March 31, 2023 2022 LNG revenues-affiliate Cheniere Marketing Agreements (1) $ 761 $ 745 Contracts for Sale and Purchase of Natural Gas and LNG (2) — 12 Total LNG revenues-affiliate 761 757 Cost of sales-affiliate Cargo loading fees under TUA (3) 14 13 Contracts for Sale and Purchase of Natural Gas and LNG (2) 19 5 Total cost of sales-affiliate 33 18 Operating and maintenance expense-affiliate TUA (3) 68 66 Natural Gas Transportation Agreement (4) 21 20 Services Agreements (5) 35 31 Total operating and maintenance expense-affiliate 124 117 Operating and maintenance expense-related party Natural Gas Transportation and Storage Agreements (6) 16 12 General and administrative expense-affiliate Services Agreements (5) 16 17 (1) We primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices. We also have a master SPA agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. As of March 31, 2023 and December 31, 2022, we had $263 million and $551 million of trade receivables-affiliate, respectively, under these agreements with Cheniere Marketing. In addition, we have 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 the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price. (2) We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales-affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. (3) We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (a portion of which is indexed for inflation), continuing until at least May 2036. Additionally, we are required to reimburse SPLNG for our proportionate share of ad valorem taxes incurred based on our contracted share of SPLNG’s regasification capacity. CQP has guaranteed our obligations under our TUA. (4) To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG Terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of CQP, and third party pipeline companies. (5) We do not have employees and thus we have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements were primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of March 31, 2023 and December 31, 2022, we had $131 million and $151 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement (6) We are party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. This related party is partially owned by the investment management company that indirectly acquired a portion of CQP’s limited partner interests in September 2020. We recorded accrued liabilities-related party of $5 million and $6 million as of March 31, 2023 and December 31, 2022, respectively, with this related party. We had $38 million and $80 million due to affiliates as of March 31, 2023 and December 31, 2022, respectively, under agreements with affiliates as described above. Disclosure of future consideration under revenue contracts with affiliates is included in Note 9-Revenues. Other Agreements LNG Site Sublease Agreement We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG Terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million, with renewal options and adjustment for inflation every five years. As of both March 31, 2023 and December 31, 2022, we recorded other non-current Cooperation Agreement We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We did not convey any assets to SPLNG under this agreement during the three months ended March 31, 2023 and 2022. State Tax Sharing Agreement We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreement. The agreement is effective for tax returns due on or after August 2012.	NOTE 12-RELATED Below is a summary of our related party transactions as reported on our Statements of Income (in millions): Year Ended December 31, 2022 2021 2020 LNG revenues-affiliate Cheniere Marketing Agreements (1) $ 4,565 $ 1,453 $ 632 Contracts for Sale and Purchase of Natural Gas and LNG (2) 3 19 30 Total LNG revenues-affiliate 4,568 1,472 662 LNG revenues-related party Natural Gas Transportation and Storage Agreements (3) — 1 — Cost of sales-affiliate Cheniere Marketing Agreements (1) — 34 61 Cargo loading fees under TUA (4) 51 43 33 Contracts for Sale and Purchase of Natural Gas and LNG (2) 211 51 16 Total cost of sales-affiliate 262 128 110 Cost of sales-related party Natural Gas Transportation and Storage Agreements (3) — 1 — Natural Gas Supply Agreements (5) — 16 — Total cost of sales-related party — 17 — Operating and maintenance expense-affiliate TUA (4) 269 266 265 Natural Gas Transportation Agreement (6) 81 81 82 Services Agreements (7) 131 109 118 LNG Site Sublease Agreement (8) 1 1 1 Total operating and maintenance expense-affiliate 482 457 466 Operating and maintenance expense-related party Natural Gas Transportation and Storage Agreements (3) 72 46 13 General and administrative expense-affiliate Services Agreements (7) 66 61 71 (1) We primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices, which will commence in January 2023. We also have a master SPA agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. As of December 31, 2022 and 2021, we had $551 million and $232 million of accounts receivable-affiliate, respectively, under these agreements with Cheniere Marketing. In addition, we have an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the even (2) We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales-affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. (3) We are party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. This related party is partially owned by the investment management company that indirectly acquired a portion of CQP’s limited partner interests in September 2020. We recorded accrued liabilities-related party of $6 million and $4 million as of December 31, 2022 and 2021, respectively, with this related party. (4) We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (a portion of which is indexed for inflation), continuing until at least May 2036. Additionally, we are required to reimburse SPLNG for our proportionate share of ad valorem taxes incurred based on our contracted share of SPLNG’s regasification capacity. CQP has guaranteed our obligations under our TUA. (5) We were a party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party was partially owned by Blackstone, who also partially owns CQP’s limited partner interests. However, this entity was acquired by a non-related (6) To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG Terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of CQP, and third party pipeline companies. (7) We do not have employees and thus we have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements were primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2022 and 2021, we had $151 million and $127 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement (8) We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG Terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million, with renewal options and adjustment for inflation every five years. As of both December 31, 2022 and 2021, we recorded other non-current We had $80 million and $73 million due to affiliates as of December 31, 2022 and 2021, respectively, under agreements with affiliates as described above. Disclosure of future consideration under revenue contracts with affiliates is included in Note 11-Revenues. 13-Commitments Other Agreements Cooperation Agreement We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. In October 2022, we completed construction of the third marine berth at the Sabine Pass LNG Terminal for a total cost of $576 million and upon completion, we conveyed the property, plant and equipment associated with the third berth to SPLNG. We did not convey any assets to SPLNG under this agreement during the year ended December 31, 2021. We conveyed $6 million in assets to SPLNG under this agreement during the year ended December 31, 2020. State Tax Sharing Agreement We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreement. The agreement is effective for tax returns due on or after August 2012.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 13-COMMITMENTS Commitments We have various future commitments under executed contracts that include unconditional purchase obligations and other commitments which do not meet the definition of a liability as of December 31, 2022 and thus are not recognized as liabilities in our Financial Statements. Natural Gas Supply, Transportation and Storage Service Agreements We have physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 15 years. Additionally, we have natural gas transportation and storage service agreements for the Liquefaction Project. The initial term of the natural gas transportation agreements range up to 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The initial terms of our natural gas storage service agreements range up to 10 years. As of December 31, 2022, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met or are currently expected to be met were as follows (in billions): Years Ending December 31, Payments Due to Payments Due to Payments Due to 2023 $ 6.6 $ 0.1 $ 0.1 2024 4.5 0.1 0.1 2025 3.6 0.1 0.1 2026 2.9 0.1 — 2027 2.5 0.1 — Thereafter 9.7 0.6 — Total $ 29.8 $ 1.1 $ 0.3 (1) Pricing of natural gas supply contracts is variable based on market commodity basis prices adjusted for basis spread, and pricing of our IPM agreement is variable based on global gas market prices less fixed liquefaction fees and certain costs incurred by us . (2) Includes $0.4 billion under natural gas supply agreements with unsatisfied conditions precedent. Services Agreements We have certain fixed commitments under services and other agreements of $1.0 billion with third parties and $4.7 billion with affiliates. Substantially all of our commitments to affiliates consist of a TUA with SPLNG pursuant to which we have reserved approximately 2 Bcf/d of regasification capacity. See Note 12-Related Additionally, we have a partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), another TUA customer, whereby upon substantial completion of Train 5, we gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG Terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity. 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, 2022, 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	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Risks and Uncertainties [Abstract]
Customer Concentration	NOTE 11-CUSTOMER The concentration of our customer credit risk in excess of 10% or greater of total revenues and/or trade and other receivables was as follows: Percentage of Total Revenues from External Percentage of Trade and Other Receivables, Net and Three Months Ended March 31, March 31, 2023 December 31, 2022 2023 2022 Customer A 28 % 29 % 30 % 28 % Customer B 15 % 14 % 23 % 18 % Customer C 17 % 18 % 15 % * Customer D 15 % 15 % 15 % 18 % Customer E * 10 % * * Customer F * * - % 13 % * Less than 10%	NOTE 14-CUSTOMER The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively: Percentage of Total Revenues from Percentage of Trade and Other Receivables, Net and Year Ended December 31, December 31, 2022 2021 2020 2022 2021 Customer A 24 % 25 % 25 % 28 % 29 % Customer B 17 % 18 % 19 % 18 % 17 % Customer C 17 % 17 % 18 % * * Customer D 16 % 16 % 16 % 18 % 14 % Customer E * 10 % * * 13 % Customer F * * * 13 % 12 % * Less than 10% The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States. Revenues from External Customers Year Ended December 31, 2022 2021 2020 United States $ 4,147 $ 2,550 $ 1,975 India 1,951 1,342 970 South Korea 1,932 1,336 924 Ireland 1,858 1,237 842 United Kingdom 1,026 966 456 Switzerland 593 208 21 Other countries — — 7 Total $ 11,507 $ 7,639 $ 5,195

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	NOTE 12-SUPPLEMENTAL The following table provides supplemental disclosure of cash flow information (in millions): Three Months Ended March 31, 2023 2022 Cash paid during the period for interest on debt, net of amounts capitalized $ 202 $ 130 Non-cash Unpaid purchases of property, plant and equipment 39 205 Novation of IPM Agreement from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”) In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, we and CCL Stage III, formerly a wholly owned direct subsidiary of Cheniere that merged with and into CCL, entered into an agreement to assign to us an IPM agreement to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023. The transaction has been accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $2.7 billion in distributions within our Statements of Member’s Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $142 million and $2.6 billion, respectively, which represented a non-cash	NOTE 15-SUPPLEMENTAL The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2022 2021 2020 Cash paid during the period for interest on debt, net of amounts capitalized $ 613 $ 615 $ 692 Non-cash 576 — 6 Right-of-use — — 3 The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $271 million, $322 million and $207 million as of December 31, 2022, 2021 and 2020, respectively. Novation of IPM Agreement from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”) In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, we and CCL Stage III, formerly a wholly owned direct subsidiary of Cheniere that merged with and into CCL, entered into an agreement to assign to us an IPM agreement to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023. The transaction has been accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $2.7 billion in distributions within our Statements of Member’s Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $142 million and $2.6 billion, respectively, which represented a non-cash

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Basis of Presentation, Policy	Basis of Presentation The accompanying unaudited Financial Statements of SPL have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 S-X 10-K Results of operations for the three months ended March 31, 2023 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2023.	Basis of Presentation Our Financial Statements have been prepared in accordance with GAAP.
Use of Estimates, Policy		Use of Estimates The preparation of our Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment and asset retirement obligations (“AROs”) as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements, Policy		Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market. In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates. Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, margin deposits, accounts payable and accrued liabilities reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs.
Revenue Recognition, 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 for further discussion of our revenue streams and accounting policies related to revenue recognition.
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 Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Current Expected Credit Losses		Current Expected Credit Losses Trade and other receivables are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Statements of Income. As of December 31, 2022 and 2021, we had current expected credit losses of zero and $5 million, respectively, on our trade and other receivables and as of both December 31, 2022 and 2021, we had current expected credit losses of zero on our non-current
Inventory, Policy		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 for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.
Property, Plant and Equipment, Policy		Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end 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 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 on disposal are recorded in other operating costs and expenses. 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 did not record any material impairments related to property, plant and equipment during the years ended December 31, 2022, 2021 and 2020.
Interest Capitalization, Policy		Interest Capitalization We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. construction-in-process in-service
Derivative Instruments, Policy		Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis. For those derivative instruments measured at fair value, changes in the fair value of the 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, 2022, 2021 and 2020. See Note 7—Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk, Policy		Concentration of Credit Risk Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter We have entered into fixed price long-term SPAs generally with terms of 20 years with 11 third parties and have entered into agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 14—Customer Concentration for additional details about our customer concentration. Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter pre-established non-exchange
Debt, Policy		Debt Our debt consists of current and long-term secured and unsecured debt securities and a credit facility with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors. Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in loss on modification or extinguishment of debt on our Statements of Income. We classify debt on our Balance Sheets based on contractual maturity, with the following exceptions: • We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement. • We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.
Asset Retirement Obligations, 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 Sabine Pass LNG Terminal. Based on the real property lease agreements at the Sabine Pass LNG Terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG Terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.
Income Taxes, Policy	We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss is included in the federal income tax return of CQP. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP’s taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.	Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss included in the federal income tax return of CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2022, the tax basis of our assets and liabilities was $5.8 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our tax sharing agreement.
Business Segment, Policy		Business Segment Our liquefaction operations at the Sabine Pass LNG Terminal represent a single
Recent Accounting Standards	Recent Accounting Standards ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard. We have not yet applied the optional expedients available under the standard because we have not yet modified any of our existing contracts indexed to LIBOR, mainly our credit facility as further described in Note 8-Debt,	Recent Accounting Standards ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, subsequent amendment to the standard. We have not yet applied the optional expedients available under the standard because we have not yet modified any of our existing contracts indexed to LIBOR, mainly our credit facility as further described in Note 10—Debt, for reference rate reform. However, we do not expect the impact of applying the optional expedients to any future contract modifications to be material, and we do not expect the transition to a replacement rate index to have a material impact on our future cash flows.

Trade and Other Receivables, _2

Trade and Other Receivables, Net of Current Expected Credit Losses (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Receivables [Abstract]
Schedule of Accounts and Other Receivables, Net of Current Expected Credit Losses	Trade and other receivables, net of current expected credit losses consisted of the following (in millions): March 31, December 31, Trade receivables $ 259 $ 603 Other receivables 6 19 Total trade and other receivables, net of current expected credit losses $ 265 $ 622	Trade and other receivables, net of current expected credit losses consisted of the following (in millions): December 31, 2022 2021 Trade receivables $ 603 $ 546 Other receivables 19 25 Total trade and other receivables, net of current expected credit losses $ 622 $ 571

Inventory (Tables)

Inventory (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Inventory Disclosure [Abstract]
Schedule of Inventory	Inventory consisted of the following (in millions): March 31, December 31, Materials $ 90 $ 87 LNG 19 26 Natural gas 22 28 Other 1 2 Total inventory $ 132 $ 143	Inventory consisted of the following (in millions): December 31, 2022 2021 Materials $ 87 $ 71 LNG 26 44 Natural gas 28 43 Other 2 1 Total inventory $ 143 $ 159

Property, Plant and Equipment_2

Property, Plant and Equipment, Net of Accumulated Depreciation (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net of Accumulated Depreciation	Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions): March 31, December 31, LNG terminal Terminal $ 16,262 $ 16,240 Construction-in-process 113 114 Accumulated depreciation (2,690 ) (2,553 ) Total LNG terminal, net of accumulated depreciation 13,685 13,801 Fixed assets Fixed assets 19 19 Accumulated depreciation (15 ) (15 ) Total fixed assets, net of accumulated depreciation 4 4 Property, plant and equipment, net of accumulated depreciation $ 13,689 $ 13,805	Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions): December 31, 2022 2021 LNG terminal Terminal $ 16,240 $ 13,751 Construction-in-process 114 2,699 Accumulated depreciation (2,553 ) (2,021 ) Total LNG terminal, net of accumulated depreciation 13,801 14,429 Fixed assets Fixed assets 19 19 Accumulated depreciation (15 ) (15 ) Total fixed assets, net of accumulated depreciation 4 4 Property, plant and equipment, net of accumulated depreciation $ 13,805 $ 14,433 (1) In October 2022, we completed construction of the third marine berth at the Sabine Pass LNG Terminal for a total cost of $576 million and upon completion, we conveyed the property, plant and equipment associated with the third berth to SPLNG.
Schedule of Depreciation and Offsets to LNG Terminal Costs	The following table shows depreciation expense and offsets to LNG terminal costs (in millions): Three Months Ended March 31, 2023 2022 Depreciation expense $ 137 $ 129 Offsets to LNG terminal costs (1) — 148 (1) We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.	The following table shows depreciation expense and offsets to LNG terminal costs (in millions): Year Ended December 31, 2022 2021 2020 Depreciation expense $ 534 $ 463 $ 460 Offsets to LNG terminal costs (1) 148 105 — (1) We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.
Property Plant and Equipment Estimated Useful Lives		LNG terminal costs related to the Liquefaction Project are Components Useful life (years) Water pipelines 30 Liquefaction processing equipment 6-50 Other 10-30

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair Value of Derivative Assets and Liabilities	The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis (in millions): Fair Value Measurements as of March 31, 2023 December 31, 2022 Quoted (Level 1) Significant (Level 2) Significant (Level 3) Total Quoted (Level 1) Significant (Level 2) Significant (Level 3) Total Liquefaction Supply Derivatives asset (liability) $ 28 $ 4 $ (2,502 ) $ (2,470 ) $ (12 ) $ (10 ) $ (3,719 ) $ (3,741 )	The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis (in millions): Fair Value Measurements as of December 31, 2022 December 31, 2021 Quoted Prices (Level 1) Significant Other (Level 2) Significant (Level 3) Total Quoted Prices (Level 1) Significant Other (Level 2) Significant (Level 3) Total Liquefaction Supply Derivatives asset (liability) $ (12 ) $ (10 ) $ (3,719 ) $ (3,741 ) $ 2 $ (13 ) $ 38 $ 27
Fair Value Measurement Inputs and Valuation Techniques	The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of March 31, 2023: Net Fair Value (in millions) Valuation Approach Significant Unobservable Range of Significant Liquefaction Supply Derivatives $ (2,502 ) Market approach incorporating present value techniques Henry Hub basis spread $(1.173) - $0.361 / Option pricing model International LNG 93% - 574% / 208% (1) Unobservable inputs were weighted by the relative fair value of the instruments. (2) Spread contemplates U.S. dollar-denominated pricing.	The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of December 31, 2022: Net Fair Value (in millions) Valuation Approach Significant Range of Significant Liquefaction Supply Derivatives $ (3,719 ) Market approach incorporating present value techniques Henry Hub basis spread $(1.775) - $0.660 / $(0.063) Option pricing model International LNG 77% - 515% / 193% (1) Unobservable inputs were weighted by the relative fair value of the instruments. (2) Spread contemplates U.S. dollar-denominated pricing.
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation	The following table shows the changes in the fair value of our Level 3 Liquefaction Supply Derivatives (in millions): Three Months Ended March 31, 2023 2022 Balance, beginning of period $ (3,719 ) $ 38 Realized and change in fair value gains (losses) included in net income (1): Included in cost of sales, existing deals (2) 1,049 (53 ) Included in cost of sales, new deals (3) 3 — Purchases and settlements: Purchases (4) — (3,141 ) Settlements (5) 165 (6 ) Balance, end of period $ (2,502 ) $ (3,162 ) Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period $ 1,052 $ (53 ) (1) Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table. (2) Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period. (3) Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period. (4) Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. (5) Roll-off	The following table shows the changes in the fair value of our Level 3 Liquefaction Supply Derivatives (in millions): Year Ended December 31, 2022 2021 2020 Balance, beginning of period $ 38 $ (21 ) $ 24 Realized and change in fair value gains (losses) included in net income (1): Included in cost of sales, existing deals (2) (228 ) 74 (43 ) Included in cost of sales, new deals (3) (804 ) — — Purchases and settlements: Purchases (4) (2,712 ) (10 ) 5 Settlements (5) (13 ) (5 ) (7 ) Balance, end of period $ (3,719 ) $ 38 $ (21 ) Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period $ (1,032 ) $ 74 $ (43 ) (1) Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table. (2) Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period. (3) Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period. (4) Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. For further discussion of IPM agreements that were novated to us during the period, see Note 15-Supplemental (5) Roll-off
Derivative Instruments, Gain (Loss)	The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Income (in millions): Gain (Loss) Recognized in Statements of Income Statements of Income Location (1) Three Months Ended March 31, 2023 2022 Cost of sales $ 1,260 $ (525 ) (1) Does not include the 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.	The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Income (in millions): Gain (Loss) Recognized in Statements of Income Statements of Income Location (1) Year Ended December 31, 2022 2021 2020 LNG revenues $ 1 $ (1 ) $ — Cost of sales (1,159 ) 30 (49 ) Cost of sales-related party — 2 — (1) Does not include the 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.
Fair Value of Derivative Instruments by Balance Sheet Location	The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions): Fair Value Measurements as of (1) Balance Sheets Location March 31, 2023 December 31, 2022 Current derivative assets $ 55 $ 24 Derivative assets 32 28 Total derivative assets 87 52 Current derivative liabilities (400 ) (769 ) Derivative liabilities (2,157 ) (3,024 ) Total derivative liabilities (2,557 ) (3,793 ) Derivative liability, net $ (2,470 ) $ (3,741 ) (1) Does not include collateral posted by counterparties to us of $8 million as of March 31, 2023, which is included in other current liabilities on our Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits in our Balance Sheets.	The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions): Fair Value Measurements as of (1) Balance Sheets Location December 31, 2022 December 31, 2021 Current derivative assets $ 24 $ 21 Derivative assets 28 33 Total derivative assets 52 54 Current derivative liabilities (769 ) (16 ) Derivative liabilities (3,024 ) (11 ) Total derivative liabilities (3,793 ) (27 ) Derivative asset (liability), net $ (3,741 ) $ 27 (1) Does not include collateral posted with counterparties by us of $35 million and $7 million, as of December 31, 2022 and 2021, respectively, which are included in margin deposits in our Balance Sheets.
Derivative Net Presentation on Balance Sheets	The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Balance Sheets: Liquefaction Supply Derivatives March 31, 2023 December 31, 2022 Gross assets $ 89 $ 57 Offsetting amounts (2 ) (5 ) Net assets $ 87 $ 52 Gross liabilities $ (2,577 ) $ (3,814 ) Offsetting amounts 20 21 Net liabilities $ (2,557 ) $ (3,793 )	The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Balance Sheets: Liquefaction Supply Derivatives As of December 31, 2022 Gross assets $ 57 Offsetting amounts (5 ) Net assets $ 52 Gross liabilities $ (3,814 ) Offsetting amounts 21 Net liabilities $ (3,793 ) As of December 31, 2021 Gross assets $ 79 Offsetting amounts (25 ) Net assets $ 54 Gross liabilities $ (33 ) Offsetting amounts 6 Net liabilities $ (27 )

Other Non-Current Assets, Net (

Other Non-Current Assets, Net (Tables)	12 Months Ended
	Dec. 31, 2022
Other Assets, Noncurrent [Abstract]
Schedule of Other Non-Current Assets	Other non-current December 31, 2022 2021 Advances made to municipalities for water system enhancements $ 78 $ 81 Advances and other asset conveyances to third parties to support LNG terminal 31 37 Operating lease assets 23 23 Advances made under EPC and non-EPC — 5 Information technology service prepayments 4 4 Other 24 21 Total other non-current $ 160 $ 171

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Accrued Liabilities, Current [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consisted of the following (in millions): March 31, 2023 December 31, 2022 Natural gas purchases $ 406 $ 1,017 Interest costs and related debt fees 118 165 Liquefaction Project costs 80 125 Other accrued liabilities 6 7 Total accrued liabilities $ 610 $ 1,314	Accrued liabilities consisted of the following (in millions): December 31, 2022 2021 Natural gas purchases $ 1,017 $ 786 Interest costs and related debt fees 165 133 Liquefaction Project costs 125 89 Other accrued liabilities 7 4 Total accrued liabilities $ 1,314 $ 1,012

Debt (Tables)

Debt (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Debt Instruments	Debt consisted of the following (in millions): March 31, 2023 December 31, 2022 Senior Secured Notes: 5.75% due 2024 $ 2,000 $ 2,000 5.625% due 2025 2,000 2,000 5.875% due 2026 1,500 1,500 5.00% due 2027 1,500 1,500 4.200% due 2028 1,350 1,350 4.500% due 2030 2,000 2,000 4.746% weighted average rate due 2037 1,782 1,782 Total Senior Secured Notes 12,132 12,132 Working capital revolving credit and letter of credit reimbursement agreement (the “Working Capital Facility”) — — Total debt 12,132 12,132 Current portion of long-term debt (1) (60 ) — Long-term portion of unamortized premium, discount and debt issuance costs, net (87 ) (92 ) Total long-term debt, net of premium, discount and debt issuance costs $ 11,985 $ 12,040 (1) As of March 31, 2023, $60 million of debt with contractual maturities of greater than one year was classified as current portion of long-term debt based on our intent and ability to repay the debt with cash that was on hand at March 31, 2023, including repurchases of debt subsequent to the balance sheet date and through April 26, 2023.	Debt consisted of the following (in millions): December 31, 2022 2021 Senior Secured Notes: 5.625% due 2023 $ — $ 1,500 5.75% due 2024 2,000 2,000 5.625% due 2025 2,000 2,000 5.875% due 2026 1,500 1,500 5.00% due 2027 1,500 1,500 4.200% due 2028 1,350 1,350 4.500% due 2030 2,000 2,000 4.746% weighted average rate due 2037 1,782 1,282 Total Senior Secured Notes 12,132 13,132 Working capital revolving credit and letter of credit reimbursement agreement (the “Working Capital Facility”) — — Total debt 12,132 13,132 Unamortized premium, discount and debt issuance costs, net (92 ) (109 ) Total long-term debt, net of premium, discount and debt issuance costs $ 12,040 $ 13,023
Schedule of Maturities of Long-term Debt		Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2022 (in millions): Years Ending December 31, Principal Payments 2023 $ — 2024 2,000 2025 2,051 2026 1,608 2027 1,612 Thereafter 4,861 Total $ 12,132
Schedule of Line of Credit Facilities	Below is a summary of our Working Capital Facility as of March 31, 2023 (in millions): Working Capital Facility Total facility size $1,200 Less: Outstanding balance — Letters of credit issued 329 Available commitment $ 871 Priority ranking Senior secured Interest rate on available balance (1) LIBOR 0.125% - 0.750% Commitment fees on undrawn balance (1) 0.10% - 0.30% Maturity date March 19, 2025 (1) The margin on the interest rate and the commitment fees is subject to change based on our credit rating.	Below is a summary of our Working Capital Facility as of December 31, 2022 (in millions): Working Capital Facility (1) Total facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 328 Available commitment $ 872 Priority ranking Senior secured Interest rate on available balance (2) LIBOR Commitment fees on undrawn balance (2) 0.10% - 0.30% Maturity date March 19, 2025 (1) Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu (2) The margin on the interest rate and the commitment fees are subject to change based on our credit rating.
Schedule of Interest Expense	Total interest expense, net of capitalized interest, consisted of the following (in millions): Three Months Ended March 31, 2023 2022 Total interest cost $ 163 $ 177 Capitalized interest (2 ) (21 ) Total interest expense, net of capitalized interest $ 161 $ 156	Total interest expense, net of capitalized interest consisted of the following (in millions): Year Ended December 31, 2022 2021 2020 Total interest cost $ 706 $ 754 $ 779 Capitalized interest (39 ) (132 ) (94 ) Total interest expense, net of capitalized interest $ 667 $ 622 $ 685
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments	The following table shows the carrying amount and estimated fair value of our debt (in millions): March 31, 2023 December 31, 2022 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior notes - Level 2 (1) $ 10,780 $ 10,718 $ 10,780 $ 10,569 Senior notes - Level 3 (2) 1,352 1,241 1,352 1,224 (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.	The following table shows the carrying amount and estimated fair value of our debt (in millions): December 31, 2022 December 31, 2021 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior notes - Level 2 (1) $ 10,780 $ 10,569 $ 11,850 $ 13,128 Senior notes - Level 3 (2) 1,352 1,224 1,282 1,466 (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

Revenues (Tables)

Revenues (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table represents a disaggregation of revenue earned (in millions): Three Months Ended March 31, 2023 2022 Revenues from contracts with customers LNG revenues $ 2,106 $ 2,488 LNG revenues-affiliate 761 757 Total revenues from contracts with customers $ 2,867 $ 3,245	The following table represents a disaggregation of revenue earned (in millions): Year Ended December 31, 2022 2021 2020 Revenues from contracts with customers LNG revenues (1) $ 11,506 $ 7,640 $ 5,195 LNG revenues-affiliate 4,568 1,472 662 LNG revenues-related party — 1 — Total revenues from contracts with customers 16,074 9,113 5,857 Net derivative gain (loss) (2) 1 (1 ) — Total revenues $ 16,075 $ 9,112 $ 5,857 (1) LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2022 and 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. (2) See Note 7-Derivative
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 March 31, December 31, Contract assets, net of current expected credit losses $ 1 $ 1	The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current December 31, 2022 2021 Contract assets, net of current expected credit losses $ 1 $ 1
Contract Balances Reconciliation	The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions): Three Months Ended March 31, 2023 Deferred revenue, beginning of period $ 132 Cash received but not yet recognized in revenue 72 Revenue recognized from prior period deferral (132 ) Deferred revenue, end of period $ 72 The following table reflects the changes in our contract liabilities to affiliate, which we classify as other non-current Three Months Ended March 31, 2023 Deferred revenue-affiliate, beginning of period $ 5 Cash received but not yet recognized in revenue 5 Revenue recognized from prior period deferral (5 ) Deferred revenue-affiliate, end of period $ 5	The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions): Year Ended December 31, 2022 Deferred revenue, beginning of period $ 132 Cash received but not yet recognized in revenue 132 Revenue recognized from prior period deferral (132 ) Deferred revenue, end of period $ 132 The following table reflects the changes in our contract liabilities to affiliate, which we classify as other non-current Year Ended December 31, 2022 Deferred revenue-affiliate, beginning of period $ 2 Cash received but not yet recognized in revenue 5 Revenue recognized from prior period deferral (2 ) Deferred revenue-affiliate, end of period $ 5
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: March 31, 2023 December 31, 2022 Unsatisfied Transaction Weighted Average Unsatisfied Transaction Weighted Average LNG revenues $ 49.9 8 $ 50.8 8 LNG revenues-affiliate 1.8 2 2.0 2 Total revenues $ 51.7 $ 52.8 (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.	The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied: December 31, 2022 December 31, 2021 Unsatisfied Transaction Weighted Average Recognition Unsatisfied Transaction Weighted Average Recognition LNG revenues $ 50.8 8 $ 49.3 9 LNG revenues-affiliate 2.0 2 2.1 3 Total revenues $ 52.8 $ 51.4 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Below is a summary of our related party transactions as reported on our Statements of Income (in millions): Three Months Ended March 31, 2023 2022 LNG revenues-affiliate Cheniere Marketing Agreements (1) $ 761 $ 745 Contracts for Sale and Purchase of Natural Gas and LNG (2) — 12 Total LNG revenues-affiliate 761 757 Cost of sales-affiliate Cargo loading fees under TUA (3) 14 13 Contracts for Sale and Purchase of Natural Gas and LNG (2) 19 5 Total cost of sales-affiliate 33 18 Operating and maintenance expense-affiliate TUA (3) 68 66 Natural Gas Transportation Agreement (4) 21 20 Services Agreements (5) 35 31 Total operating and maintenance expense-affiliate 124 117 Operating and maintenance expense-related party Natural Gas Transportation and Storage Agreements (6) 16 12 General and administrative expense-affiliate Services Agreements (5) 16 17 (1) We primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices. We also have a master SPA agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. As of March 31, 2023 and December 31, 2022, we had $263 million and $551 million of trade receivables-affiliate, respectively, under these agreements with Cheniere Marketing. In addition, we have 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 the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price. (2) We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales-affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. (3) We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (a portion of which is indexed for inflation), continuing until at least May 2036. Additionally, we are required to reimburse SPLNG for our proportionate share of ad valorem taxes incurred based on our contracted share of SPLNG’s regasification capacity. CQP has guaranteed our obligations under our TUA. (4) To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG Terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of CQP, and third party pipeline companies. (5) We do not have employees and thus we have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements were primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of March 31, 2023 and December 31, 2022, we had $131 million and $151 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement (6) We are party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. This related party is partially owned by the investment management company that indirectly acquired a portion of CQP’s limited partner interests in September 2020. We recorded accrued liabilities-related party of $5 million and $6 million as of March 31, 2023 and December 31, 2022, respectively, with this related party.	Below is a summary of our related party transactions as reported on our Statements of Income (in millions): Year Ended December 31, 2022 2021 2020 LNG revenues-affiliate Cheniere Marketing Agreements (1) $ 4,565 $ 1,453 $ 632 Contracts for Sale and Purchase of Natural Gas and LNG (2) 3 19 30 Total LNG revenues-affiliate 4,568 1,472 662 LNG revenues-related party Natural Gas Transportation and Storage Agreements (3) — 1 — Cost of sales-affiliate Cheniere Marketing Agreements (1) — 34 61 Cargo loading fees under TUA (4) 51 43 33 Contracts for Sale and Purchase of Natural Gas and LNG (2) 211 51 16 Total cost of sales-affiliate 262 128 110 Cost of sales-related party Natural Gas Transportation and Storage Agreements (3) — 1 — Natural Gas Supply Agreements (5) — 16 — Total cost of sales-related party — 17 — Operating and maintenance expense-affiliate TUA (4) 269 266 265 Natural Gas Transportation Agreement (6) 81 81 82 Services Agreements (7) 131 109 118 LNG Site Sublease Agreement (8) 1 1 1 Total operating and maintenance expense-affiliate 482 457 466 Operating and maintenance expense-related party Natural Gas Transportation and Storage Agreements (3) 72 46 13 General and administrative expense-affiliate Services Agreements (7) 66 61 71 (1) We primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices, which will commence in January 2023. We also have a master SPA agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. As of December 31, 2022 and 2021, we had $551 million and $232 million of accounts receivable-affiliate, respectively, under these agreements with Cheniere Marketing. In addition, we have an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the even (2) We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales-affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. (3) We are party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. This related party is partially owned by the investment management company that indirectly acquired a portion of CQP’s limited partner interests in September 2020. We recorded accrued liabilities-related party of $6 million and $4 million as of December 31, 2022 and 2021, respectively, with this related party. (4) We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (a portion of which is indexed for inflation), continuing until at least May 2036. Additionally, we are required to reimburse SPLNG for our proportionate share of ad valorem taxes incurred based on our contracted share of SPLNG’s regasification capacity. CQP has guaranteed our obligations under our TUA. (5) We were a party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party was partially owned by Blackstone, who also partially owns CQP’s limited partner interests. However, this entity was acquired by a non-related (6) To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG Terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of CQP, and third party pipeline companies. (7) We do not have employees and thus we have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements were primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2022 and 2021, we had $151 million and $127 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement (8) We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG Terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million, with renewal options and adjustment for inflation every five years. As of both December 31, 2022 and 2021, we recorded other non-current

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met or are currently expected to be met were as follows (in billions): Years Ending December 31, Payments Due to Payments Due to Payments Due to 2023 $ 6.6 $ 0.1 $ 0.1 2024 4.5 0.1 0.1 2025 3.6 0.1 0.1 2026 2.9 0.1 — 2027 2.5 0.1 — Thereafter 9.7 0.6 — Total $ 29.8 $ 1.1 $ 0.3 (1) Pricing of natural gas supply contracts is variable based on market commodity basis prices adjusted for basis spread, and pricing of our IPM agreement is variable based on global gas market prices less fixed liquefaction fees and certain costs incurred by us . (2) Includes $0.4 billion under natural gas supply agreements with unsatisfied conditions precedent.

Customer Concentration (Tables)

Customer Concentration (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Risks and Uncertainties [Abstract]
Schedule of Revenue and Accounts Receivable by Major Customers	The concentration of our customer credit risk in excess of 10% or greater of total revenues and/or trade and other receivables was as follows: Percentage of Total Revenues from External Percentage of Trade and Other Receivables, Net and Three Months Ended March 31, March 31, 2023 December 31, 2022 2023 2022 Customer A 28 % 29 % 30 % 28 % Customer B 15 % 14 % 23 % 18 % Customer C 17 % 18 % 15 % * Customer D 15 % 15 % 15 % 18 % Customer E * 10 % * * Customer F * * - % 13 % * Less than 10%	The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively: Percentage of Total Revenues from Percentage of Trade and Other Receivables, Net and Year Ended December 31, December 31, 2022 2021 2020 2022 2021 Customer A 24 % 25 % 25 % 28 % 29 % Customer B 17 % 18 % 19 % 18 % 17 % Customer C 17 % 17 % 18 % * * Customer D 16 % 16 % 16 % 18 % 14 % Customer E * 10 % * * 13 % Customer F * * * 13 % 12 % * Less than 10%
Schedule of Revenue from External Customers by Country		The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States. Revenues from External Customers Year Ended December 31, 2022 2021 2020 United States $ 4,147 $ 2,550 $ 1,975 India 1,951 1,342 970 South Korea 1,932 1,336 924 Ireland 1,858 1,237 842 United Kingdom 1,026 966 456 Switzerland 593 208 21 Other countries — — 7 Total $ 11,507 $ 7,639 $ 5,195

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table provides supplemental disclosure of cash flow information (in millions): Three Months Ended March 31, 2023 2022 Cash paid during the period for interest on debt, net of amounts capitalized $ 202 $ 130 Non-cash Unpaid purchases of property, plant and equipment 39 205	The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2022 2021 2020 Cash paid during the period for interest on debt, net of amounts capitalized $ 613 $ 615 $ 692 Non-cash 576 — 6 Right-of-use — — 3

Nature of Operations and Basi_2

Nature of Operations and Basis of Presentation (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2023 MT trains members	Dec. 31, 2022 MT trains members
Organization and Nature of Operations [Line Items]
Limited Liability Company (LLC) Number Of Members | members	1	1
Sabine Pass LNG Terminal [Member]
Organization and Nature of Operations [Line Items]
Number of Liquefaction LNG Trains Operating | trains	6	6
Total Production Capability | MT	30	30
Sabine Pass LNG Terminal Expansion
Organization and Nature of Operations [Line Items]
Total Production Capability | MT	20
Number of Liquefaction LNG Trains | trains	3
Cheniere Energy Partners, LP | Cheniere [Member]
Organization and Nature of Operations [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	48.60%	48.60%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	100%	100%

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) unit members	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Accounts Receivable, Allowance for Credit Loss, Current	$ 0	$ 5
Contract with Customer, Asset, Allowance for Credit Loss, Noncurrent	0	0
Impairment of Long-Lived Assets Held-for-use	0	0	$ 0
Derivative instruments designated as cash flow hedges	0	0	0
Income Tax Expense (Benefit)	0	$ 0	$ 0
Taxes, Difference in Bases, Amount	$ 5,800
Number of Reportable Segments | unit	1
Sabine Pass LNG Terminal [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Asset Retirement Obligation	$ 0
Customer Concentration Risk [Member] | SPA Customers [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
SPA, Term of Agreement	20 years
Concentration Risk, Number of Significant Customers | members	11
Maximum [Member] | Sabine Pass LNG Terminal [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Property Lease Term	90 years

Restricted Cash and Cash Equi_2

Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 160	$ 92	$ 98
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 160	$ 92	$ 98

Trade and Other Receivables, _3

Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Receivables [Abstract]
Trade receivables	$ 259	$ 603	$ 546
Other receivables	6	19	25
Total trade and other receivables, net of current expected credit losses	$ 265	$ 622	$ 571

Inventory (Details)

Inventory (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Inventory [Line Items]
Inventory	$ 132	$ 143	$ 159
Materials [Member]
Inventory [Line Items]
Inventory	90	87	71
LNG [Member]
Inventory [Line Items]
Inventory	19	26	44
Natural gas [Member]
Inventory [Line Items]
Inventory	22	28	43
Other [Member]
Inventory [Line Items]
Inventory	$ 1	$ 2	$ 1

Property, Plant and Equipment_3

Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020	Mar. 31, 2023
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 13,805		$ 14,433			$ 13,689
Non-cash distributions to affiliates for conveyance of assets	576		0		$ 6
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(2,553)		(2,021)			(2,690)
Property, plant and equipment, net of accumulated depreciation	13,801		14,429			13,685
Terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	16,240		13,751			16,262
Construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	114	[1]	2,699	[1]		113
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19		19			19
Accumulated depreciation	(15)		(15)			(15)
Property, plant and equipment, net of accumulated depreciation	$ 4		$ 4			$ 4
[1]In October 2022, we completed construction of the third marine berth at the Sabine Pass LNG Terminal for a total cost of $576 million and upon completion, we conveyed the property, plant and equipment associated with the third berth to SPLNG.

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		3 Months Ended		12 Months Ended
		Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 137	$ 129	$ 534	$ 463	$ 460
Offsets to LNG terminal costs	[1]	$ 0	$ 148	$ 148	$ 105	$ 0
[1]We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

Property, Plant and Equipment_5

Property, Plant and Equipment, Net of Accumulated Depreciation - Estimated Useful Lives (Details)	12 Months Ended
	Dec. 31, 2022
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	6 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Water pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years
Liquefaction processing equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	6 years
Liquefaction processing equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details) - tbtu	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	6,027	5,972	5,194
Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	15 years	15 years

Derivative Instruments - Fair V

Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (2,470)	$ (3,741)	$ 27
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	28	(12)	2
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	4	(10)	(13)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (2,502)	$ (3,719)	$ 38

Derivative Instruments - Fair_2

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - USD ($)		3 Months Ended	12 Months Ended
		Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liabilities		$ (2,470,000,000)	$ (3,741,000,000)	$ 27,000,000
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liabilities		(2,502,000,000)	(3,719,000,000)	$ 38,000,000
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liabilities		(2,502,000,000)	(3,719,000,000)
Liquefaction Supply Derivatives [Member] | Valuation, Market Approach | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	[1]	(1.173)	(1.775)
Liquefaction Supply Derivatives [Member] | Valuation, Market Approach | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	[1]	0.361	0.66
Liquefaction Supply Derivatives [Member] | Valuation, Market Approach | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	[1]	$ (0.021)	$ (0.063)
Liquefaction Supply Derivatives [Member] | Valuation Technique, Option Pricing Model | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	93%	77%
Liquefaction Supply Derivatives [Member] | Valuation Technique, Option Pricing Model | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	574%	515%
Liquefaction Supply Derivatives [Member] | Valuation Technique, Option Pricing Model | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	208%	193%
[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) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended				12 Months Ended
		Mar. 31, 2023		Mar. 31, 2022		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (3,719)		$ 38		$ 38		$ (21)		$ 24
Realized and change in fair value gains (losses) included in net income:
Included in cost of sales, existing deals	[1],[2]	1,049		(53)		(228)		74		(43)
Included in cost of sales, new deals	[1],[3]	3		0		(804)		0		0
Purchases and settlements:
Purchases		0	[4]	(3,141)	[4]	(2,712)	[5]	(10)	[5]	5	[5]
Settlements	[6]	165		(6)		(13)		(5)		(7)
Balance, end of period		(2,502)		(3,162)		(3,719)		38		(21)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period		$ 1,052		$ (53)		$ (1,032)		$ 74		$ (43)
[1]Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.[2]Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.[3]Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.[4]Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.[5]Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. For further discussion of IPM agreements that were novated to us during the period, see Note 15-Supplemental Cash Flow Information.[6]Roll-off in the current period of amounts recognized in our Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.

Derivative Instruments - Deriva

Derivative Instruments - Derivative Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]			$ 1	$ (1)	$ 0
Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 1,260	$ (525)	(1,159)	30	(49)
Cost of Sales, Related Party
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]			$ 0	$ 2	$ 0
[1]Does not include the value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

Derivative Instruments - Fair_3

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions	Mar. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Current derivative assets	$ 55		$ 24		$ 21
Derivative assets	32		28		33
Total derivative assets	87	[1]	52	[1],[2]	54	[2]
Current derivative liabilities	(400)		(769)		(16)
Derivative liabilities	(2,157)		(3,024)		(11)
Total derivative liabilities	(2,557)	[1]	(3,793)	[1],[2]	(27)	[2]
Derivative asset (liability), net	(2,470)	[1]	(3,741)	[1],[2]	27	[2]
Derivative, collateral posted by counterparties	8
Derivative, collateral posted by us			35		7
Current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	55	[1]	24	[1],[2]	21	[2]
Derivative assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	32	[1]	28	[1],[2]	33	[2]
Current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities	(400)	[1]	(769)	[1],[2]	(16)	[2]
Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ (2,157)	[1]	$ (3,024)	[1],[2]	$ (11)	[2]
[1]Does not include collateral posted by counterparties to us of $8 million as of March 31, 2023, which is included in other current liabilities on our Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits in our Balance Sheets.[2]Does not include collateral posted with counterparties by us of $35 million and $7 million, as of December 31, 2022 and 2021, respectively, which are included in margin deposits in our Balance Sheets.

Derivative Instruments - Deri_2

Derivative Instruments - Derivative Net Presentation on Balance Sheets (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Net Amounts Presented in our Balance Sheets	$ (2,470)	$ (3,741)	$ 27
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	89	57	79
Derivative Asset, Gross Amounts Offset in the Balance Sheets	(2)	(5)	(25)
Net Amounts Presented in our Balance Sheets	87	52	54
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(2,577)	(3,814)	(33)
Derivative Liability, Gross Amounts Offset in the Balance Sheets	20	21	6
Net Amounts Presented in our Balance Sheets	$ (2,557)	$ (3,793)	$ (27)

Other Non-Current Assets, Net_2

Other Non-Current Assets, Net (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Assets, Noncurrent [Abstract]
Advances made to municipalities for water system enhancements		$ 78	$ 81
Advances and other asset conveyances to third parties to support LNG terminal		31	37
Operating lease assets		23	23
Advances made under EPC and non-EPC contracts		0	5
Information technology service prepayments		4	4
Other		24	21
Other non-current assets, net	$ 167	$ 160	$ 171

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accrued Liabilities, Current [Abstract]
Natural gas purchases	$ 406	$ 1,017	$ 786
Interest costs and related debt fees	118	165	133
Liquefaction Project costs	80	125	89
Other accrued liabilities	6	7	4
Total accrued liabilities	$ 610	$ 1,314	$ 1,012

Debt - Schedule of Debt Instrum

Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 12,132	$ 12,132		$ 13,132
Long-Term Debt, Current Maturities	[1]	(60)	0
Long-term portion of unamortized premium, discount and debt issuance costs, net		(87)	(92)		(109)
Long-Term Debt, Total		11,985	12,040		13,023
Long Term Debt Current Gross		60
Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		12,132	12,132		13,132
2023 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 0		1,500
Debt Instrument, Interest Rate, Stated Percentage			5.625%
2024 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,000	$ 2,000		2,000
Debt Instrument, Interest Rate, Stated Percentage		5.75%	5.75%
2025 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,000	$ 2,000		2,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%	5.625%
2026 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,500	$ 1,500		1,500
Debt Instrument, Interest Rate, Stated Percentage		5.875%	5.875%
2027 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,500	$ 1,500		1,500
Debt Instrument, Interest Rate, Stated Percentage		5%	5%
2028 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,350	$ 1,350		1,350
Debt Instrument, Interest Rate, Stated Percentage		4.20%	4.20%
2030 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,000	$ 2,000		2,000
Debt Instrument, Interest Rate, Stated Percentage		4.50%	4.50%
2037 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,782	$ 1,782		1,282
2037 Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.746%	4.746%
Working Capital Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 0	$ 0	[2]	$ 0
[1]As of March 31, 2023, $60 million of debt with contractual maturities of greater than one year was classified as current portion of long-term debt based on our intent and ability to repay the debt with cash that was on hand at March 31, 2023, including repurchases of debt subsequent to the balance sheet date and through April 26, 2023.[2]Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu basis by a first priority lien with the Working Capital Facility. The Working Capital Facility contains customary conditions precedent for extensions.

Debt - Schedule of Maturities (

Debt - Schedule of Maturities (Details) $ in Millions	Dec. 31, 2022 USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2023	$ 0
2024	2,000
2025	2,051
2026	1,608
2027	1,612
Thereafter	4,861
Total	$ 12,132

Debt - Credit Facilities (Detai

Debt - Credit Facilities (Details) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2023 USD ($) unit		Dec. 31, 2022 USD ($) unit		Dec. 31, 2021 USD ($)
Line of Credit Facility [Line Items]
Outstanding balance	$ 12,132		$ 12,132		$ 13,132
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio | unit	1.25		1.25
Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,200		$ 1,200	[1]
Outstanding balance	0		0	[1]	$ 0
Letters of credit issued	329		328	[1]
Available commitment	$ 871		$ 872	[1]
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate		LIBOR or base rate
Debt Instrument, Maturity Date	Mar. 19, 2025		Mar. 19, 2025	[1]
Working Capital Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%	[2]	0.10%	[1],[3]
Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[2]	0.30%	[1],[3]
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	1.125%	[2]	1.125%	[1],[3]
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	1.75%	[2]	1.75%	[1],[3]
Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.125%	[2]	0.125%	[1],[3]
Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%	[2]	0.75%	[1],[3]
[1]Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu basis by a first priority lien with the Working Capital Facility. The Working Capital Facility contains customary conditions precedent for extensions.[2]The margin on the interest rate and the commitment fees is subject to change based on our credit rating.[3]The margin on the interest rate and the commitment fees are subject to change based on our credit rating.

Debt - Interest Expense (Detail

Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
Total interest cost	$ 163	$ 177	$ 706	$ 754	$ 779
Capitalized interest	(2)	(21)	(39)	(132)	(94)
Total interest expense, net of capitalized interest	$ 161	$ 156	$ 667	$ 622	$ 685

Debt - Schedule of Carrying Val

Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - Senior Notes [Member] - USD ($) $ in Millions		Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[1]	$ 10,780	$ 10,780	$ 11,850
Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[2]	1,352	1,352	1,282
Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	10,718	10,569	13,128
Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	$ 1,241	$ 1,224	$ 1,466
[1]The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.[2]The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

Revenues - Narrative (Details)

Revenues - Narrative (Details)	12 Months Ended
	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115%

Revenues - Schedule of Disaggre

Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 2,867	$ 3,245	$ 16,074		$ 9,113		$ 5,857
Net derivative gain	[1]			1		(1)		0
Revenues		2,867	3,245	16,075		9,112		5,857
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		2,106	2,488	11,506	[2]	7,640	[2]	5,195	[2]
Revenues		2,106	2,488	11,507		7,639		5,195
Suspension Fees and LNG Cover Damages Revenue
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				0		0		553
LNG-affiliate
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 761	$ 757	4,568		1,472		662
LNG-related party [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				$ 0		$ 1		$ 0
[1]See Note 7-Derivative

Revenues - Contract Assets and

Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 1	$ 1	$ 1
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	132	132
Cash received but not yet recognized in revenue	72	132
Revenue recognized from prior period deferral	(132)	(132)
Deferred revenue, end of period	72	132
Deferred revenue-affiliate, beginning of period	5	2
Cash received but not yet recognized in revenue	5	5
Revenue recognized from prior period deferral	(5)	(2)
Deferred revenue-affiliate, end of period	$ 5	$ 5

Revenues - Schedule of Transact

Revenues - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		3 Months Ended		12 Months Ended
		Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price					$ 51.4
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price				$ 52.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 51.7
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		61%	67%	74%	61%
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price					$ 49.3
Weighted Average Recognition Timing	[1]				9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price				$ 50.8
Weighted Average Recognition Timing	[1]			8 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 49.9
Weighted Average Recognition Timing	[1]	8 years
LNG-affiliate
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		73%	100%	75%	96%
LNG-affiliate | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price					$ 2.1
Weighted Average Recognition Timing	[1]				3 years
LNG-affiliate | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price				$ 2
Weighted Average Recognition Timing	[1]			2 years
LNG-affiliate | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 1.8
Weighted Average Recognition Timing	[1]	2 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		3 Months Ended				12 Months Ended
		Mar. 31, 2023		Mar. 31, 2022		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Related Party Transaction [Line Items]
Revenues from contracts with customers		$ 2,867		$ 3,245		$ 16,074		$ 9,113		$ 5,857
Cost of sales-affiliate		33		18		262		128		110
Operating and maintenance expense-affiliate		124		117		482		457		466
Operating and maintenance expense-related party		16		12		72		46		13
General and administrative expense-affiliate		16		17		66		61		71
Cost of sales-related party						0		17		0
LNG-affiliate
Related Party Transaction [Line Items]
Revenues from contracts with customers		761		757		4,568		1,472		662
LNG-related party [Member]
Related Party Transaction [Line Items]
Revenues from contracts with customers						0		1		0
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
Cost of sales-affiliate	[1]					0		34		61
Cheniere Marketing Agreements [Member] | LNG-affiliate
Related Party Transaction [Line Items]
Revenues from contracts with customers		761	[2]	745	[2]	4,565	[1]	1,453	[1]	632	[1]
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
Cost of sales-affiliate	[3]	19		5		211		51		16
Contracts for Sale and Purchase of Natural Gas And LNG [Member] | LNG-affiliate
Related Party Transaction [Line Items]
Revenues from contracts with customers	[3]	0		12		3		19		30
Terminal Use Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales-affiliate	[4]	14		13		51		43		33
Operating and maintenance expense-affiliate	[4]	68		66		269		266		265
Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense-affiliate	[5]	21		20		81		81		82
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense-affiliate		35	[6]	31	[6]	131	[7]	109	[7]	118	[7]
General and administrative expense-affiliate		16	[6]	17	[6]	66	[7]	61	[7]	71	[7]
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense-related party		$ 16	[8]	$ 12	[8]	72	[9]	46	[9]	13	[9]
Cost of sales-related party	[9]					0		1		0
Natural Gas Transportation and Storage Agreements [Member] | LNG-related party [Member]
Related Party Transaction [Line Items]
Revenues from contracts with customers	[9]					0		1		0
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales-related party	[10]					0		16		0
LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense-affiliate	[11]					$ 1		$ 1		$ 1
SPLNG [Member] | LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Review Period for Inflation Adjustment		5 years				5 years
[1]We primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices, which will commence in January 2023. We also have a master SPA agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. As of December 31, 2022 and 2021, we had $551 million and $232 million of accounts receivable-affiliate, respectively, under these agreements with Cheniere Marketing. In addition, we have an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the even construction-in-process. non-reimbursement non-reimbursement non-related non-current

Related Party Transactions - Ta

Related Party Transactions - Table Footnotes (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2023 USD ($) Bcf	Dec. 31, 2022 USD ($) Bcf	Dec. 31, 2021 USD ($)
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub		115%
Trade receivables-affiliate	$ 263	$ 553	$ 232
Regasification Capacity | Bcf		2
Advances to affiliate	131	$ 151	127
Accrued liabilities-related party	5	6	4
Due to affiliates	38	80	73
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to affiliate	131	151	127
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Accrued liabilities-related party	5	6	4
LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Operating Lease Liability Noncurrent-Affiliate	$ 15	$ 15	15
Affiliated Entity [Member] | Facility Swap Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115%	115%
Cheniere Marketing International, LLP | Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115%	115%
Trade receivables-affiliate	$ 263	$ 551	$ 232
SPLNG [Member] | Terminal Use Agreement [Member]
Related Party Transaction [Line Items]
Regasification Capacity | Bcf	2	2
Related Party Transaction, Committed Annual Fee	$ 250	$ 250
SPLNG [Member] | LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Annual Sublease Payment	$ 1	$ 1

Related Party Transactions - Ot

Related Party Transactions - Other Agreements (Details) - USD ($)		3 Months Ended		12 Months Ended
	Oct. 31, 2022	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Non-cash distributions to affiliates for conveyance of assets				$ 576,000,000	$ 0	$ 6,000,000
LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Operating Lease Liability Noncurrent—Affiliate		$ 15,000,000		15,000,000	15,000,000
SPLNG [Member] | LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Annual Sublease Payment		$ 1,000,000		$ 1,000,000
Review Period for Inflation Adjustment		5 years		5 years
SPLNG [Member] | Cooperation Agreement [Member]
Related Party Transaction [Line Items]
Non-cash distributions to affiliates for conveyance of assets	$ 576,000,000	$ 0	$ 0		$ 0	$ 6,000,000
Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net		$ 0		$ 0

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Billions	12 Months Ended
	Dec. 31, 2022 USD ($) Bcf item
Commitments and Contingencies [Line Items]
Regasification Capacity | Bcf	2
Loss Contingency, Pending Claims, Number | item	0
Natural Gas Supply Agreement [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	15 years
Natural Gas Transportation Agreements [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	20 years
Natural Gas Storage Service Agreements [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	10 years
Service and Other Agreements [Member] | Third Party
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Amount	$ 1
Service and Other Agreements [Member] | Affiliated Entity [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Amount	$ 4.7

Commitments and Contingencies_2

Commitments and Contingencies - Purchase Obligations Table (Details) - Natural Gas Supply, Transportation And Storage Service Agreements [Member] $ in Billions	Dec. 31, 2022 USD ($)
Third Party
Long-term Purchase Commitment [Line Items]
2023	$ 6.6	[1],[2]
2024	4.5	[1],[2]
2025	3.6	[1],[2]
2026	2.9	[1],[2]
2027	2.5	[1],[2]
Thereafter	9.7	[1],[2]
Total	29.8	[1],[2]
Purchase Obligation, Conditions Precedent Not Met	0.4
Affiliated Entity [Member]
Long-term Purchase Commitment [Line Items]
2023	0.1	[2]
2024	0.1	[2]
2025	0.1	[2]
2026	0.1	[2]
2027	0.1	[2]
Thereafter	0.6	[2]
Total	1.1	[2]
Related Party
Long-term Purchase Commitment [Line Items]
2023	0.1	[2]
2024	0.1	[2]
2025	0.1	[2]
2026	0	[2]
2027	0	[2]
Thereafter	0	[2]
Total	$ 0.3	[2]
[1]Includes $0.4 billion under natural gas supply agreements with unsatisfied conditions precedent.[2]Pricing of natural gas supply contracts is variable based on market commodity basis prices adjusted for basis spread, and pricing of our IPM agreement is variable based on global gas market prices less fixed liquefaction fees and certain costs incurred by us .

Customer Concentration - Schedu

Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	28%	29%	24%	25%	25%
Customer A [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	30%		28%	29%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15%	14%	17%	18%	19%
Customer B [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	23%		18%	17%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17%	18%	17%	17%	18%
Customer C [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15%	15%	16%	16%	16%
Customer D [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15%		18%	14%
Customer E [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10%		10%
Customer E [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage				13%
Customer F [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0%		13%	12%

Customer Concentration - Sche_2

Customer Concentration - Schedule of Revenues from External Customers by Country (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Concentration Risk [Line Items]
Revenues from External Customers	$ 2,867	$ 3,245	$ 16,075	$ 9,112	$ 5,857
LNG [Member]
Concentration Risk [Line Items]
Revenues from External Customers	$ 2,106	$ 2,488	11,507	7,639	5,195
Geographic Concentration Risk [Member] | United States
Concentration Risk [Line Items]
Revenues from External Customers			4,147	2,550	1,975
Geographic Concentration Risk [Member] | India
Concentration Risk [Line Items]
Revenues from External Customers			1,951	1,342	970
Geographic Concentration Risk [Member] | South Korea
Concentration Risk [Line Items]
Revenues from External Customers			1,932	1,336	924
Geographic Concentration Risk [Member] | Ireland
Concentration Risk [Line Items]
Revenues from External Customers			1,858	1,237	842
Geographic Concentration Risk [Member] | United Kingdom
Concentration Risk [Line Items]
Revenues from External Customers			1,026	966	456
Geographic Concentration Risk [Member] | Switzerland
Concentration Risk [Line Items]
Revenues from External Customers			593	208	21
Geographic Concentration Risk [Member] | Other Countries
Concentration Risk [Line Items]
Revenues from External Customers			$ 0	$ 0	$ 7

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) $ in Millions		1 Months Ended	3 Months Ended		12 Months Ended
	Mar. 15, 2022 USD ($)	Mar. 31, 2022 MMBTU	Mar. 31, 2023 USD ($)	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($) MMBTU	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Nonmonetary Transaction [Line Items]
Cash paid during the period for interest on debt, net of amounts capitalized			$ 202	$ 130	$ 613	$ 615	$ 692
Non-cash distributions to affiliates for conveyance of assets					576	0	6
Right-of-use assets obtained in exchange for new operating lease liabilities					0	0	3
Unpaid purchases of property, plant and equipment			39	205	271	322	$ 207
Distributions for Novated IPM Agreement				$ 2,712	2,712
Current derivative liabilities			400		769	16
Derivative liabilities			$ 2,157		$ 3,024	$ 11
Novation of IPM Agreement
Nonmonetary Transaction [Line Items]
Distributions for Novated IPM Agreement	$ 2,700
Current derivative liabilities	142
Derivative liabilities	$ 2,600
Novation of IPM Agreement | Cheniere Corpus Christi Liquefaction Stage III
Nonmonetary Transaction [Line Items]
Contract Volume | MMBTU		140,000			140,000
IPM Agreement, Term of Agreement		15 years			15 years