Sabine Pass Liquefaction S-4 7 Jan 21 Registration of securities issued in business combination transactions Financial data

Cover Page

Cover Page	9 Months Ended
	Sep. 30, 2020
Cover [Abstract]
Entity Registrant Name	Sabine Pass Liquefaction, LLC
Entity Central Index Key	0001499200
Entity Filer Category	Non-accelerated Filer
Document Type	S-4
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false

Balance Sheets

Balance Sheets - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 0	$ 0	$ 0
Restricted cash	157	181	756
Accounts and other receivables, net	197	292	346
Accounts receivable—affiliate	83	104	113
Advances to affiliate	98	133	210
Inventory	100	103	87
Derivative assets	14	17	6
Prepaid expenses	38	29
Tax receivables	39	1
Other current assets	19	6
Other current assets		36	18
Other current assets—affiliate	21	22	21
Total current assets	766	888	1,557
Property, plant and equipment, net	14,183	13,861	13,209
Debt issuance costs, net	10	6	12
Non-current derivative assets	30	32	31
Other non-current assets, net	159	165	158
Total assets	15,148	14,952	14,967
Current liabilities
Accounts payable	13	38	11
Accrued liabilities	430	629	768
Accrued liabilities—related party	2	0
Due to affiliates	46	49	48
Deferred revenue	157	132	91
Derivative liabilities	31	9	66
Total current liabilities	679	857	984
Long-term debt, net	13,514	13,524	13,500
Non-current derivative liabilities	25	16	14
Other non-current liabilities	8	5	3
Other non-current liabilities—affiliate	15	16	0
Commitments and contingencies (see Note 14)
Member's equity	907	534	466
Total liabilities and member's equity	$ 15,148	$ 14,952	$ 14,967

Statements of Income and Operat

Statements of Income and Operations - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues
Revenues	$ 3,940	$ 4,695	$ 6,523	$ 6,126	$ 4,024
Operating costs and expenses
Cost of sales (excluding items shown separately below)	1,551	2,501	3,373	3,403	2,317
Cost of sales—affiliate	60	35	47	32	23
Operating and maintenance expense	405	398	547	342	243
Operating and maintenance expense—affiliate	352	335	450	423	329
Development expense			0	2	2
General and administrative expense	8	4	6	5	7
General and administrative expense—affiliate	54	64	79	50	58
Depreciation and amortization expense	348	331	447	349	264
Impairment expense and loss on disposal of assets	0	6	6	0	0
Total operating costs and expenses	2,778	3,674	4,955	4,606	3,243
Income from operations	1,162	1,021	1,568	1,520	781
Other income (expense)
Interest expense, net of capitalized interest	(523)	(524)	(705)	(589)	(494)
Loss on modification or extinguishment of debt	(43)	0	0	0	(42)
Derivative loss, net			0	0	(2)
Other income, net	1	9	10	13	7
Total other expense	(565)	(515)	(695)	(576)	(531)
Net income (loss)	597	506	873	944	250
LNG revenues [Member]
Revenues
Revenues	3,588	3,678	5,211	4,827	2,635
LNG—affiliate [Member]
Revenues
Revenues	$ 352	$ 1,017	$ 1,312	$ 1,299	$ 1,389

Statements of Member's Equity

Statements of Member's Equity - USD ($) $ in Millions	Total	Sabine Pass LNG-LP, LLC [Member]
Members' equity, beginning of period at Dec. 31, 2016	$ 486	$ 486
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	7	7
Distributions	(781)	(781)
Net income (loss)	250	250
Member's equity, end of period at Dec. 31, 2017	(38)	(38)
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	129	129
Distributions	(569)	(569)
Net income (loss)	944	944
Member's equity, end of period at Dec. 31, 2018	466	466
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	164	164
Distributions	(231)	(231)
Net income (loss)	308	308
Member's equity, end of period at Mar. 31, 2019	707	707
Members' equity, beginning of period at Dec. 31, 2018	466	466
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	506
Member's equity, end of period at Sep. 30, 2019	521	521
Members' equity, beginning of period at Dec. 31, 2018	466	466
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	1,046	1,046
Distributions	(1,851)	(1,851)
Net income (loss)	873	873
Member's equity, end of period at Dec. 31, 2019	534	534
Members' equity, beginning of period at Mar. 31, 2019	707	707
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	642	642
Distributions	(965)	(965)
Net income (loss)	150	150
Member's equity, end of period at Jun. 30, 2019	534	534
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	143	143
Distributions	(204)	(204)
Net income (loss)	48	48
Member's equity, end of period at Sep. 30, 2019	521	521
Members' equity, beginning of period at Dec. 31, 2019	534	534
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	226	226
Distributions	(376)	(376)
Net income (loss)	360	360
Member's equity, end of period at Mar. 31, 2020	744	744
Members' equity, beginning of period at Dec. 31, 2019	534	534
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	597
Member's equity, end of period at Sep. 30, 2020	907	907
Members' equity, beginning of period at Mar. 31, 2020	744	744
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	261	261
Distributions	(200)	(200)
Net income (loss)	353	353
Member's equity, end of period at Jun. 30, 2020	1,158	1,158
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions	(135)	(135)
Net income (loss)	(116)	(116)
Member's equity, end of period at Sep. 30, 2020	$ 907	$ 907

Statements of Cash Flows

Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities
Net income	$ 597	$ 506	$ 873	$ 944	$ 250
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	348	331	447	349	264
Amortization of debt issuance costs, premium and discount	19	20	27	22	19
Loss on modification or extinguishment of debt	43	0	0	0	42
Total losses (gains) on derivatives, net	38	(30)	(72)	101	26
Net cash provided by (used for) settlement of derivative instruments	(2)	11	5	(3)	(14)
Impairment expense and loss on disposal of assets	0	6	6	0	0
Changes in operating assets and liabilities:
Accounts and other receivables, net	95	37	19	(122)	(99)
Accounts receivable—affiliate	22	47	9	49	(63)
Advances to affiliate	28	(43)	(34)	(76)	(13)
Inventory	2	(2)	(16)	(3)	11
Accounts payable and accrued liabilities	(166)	(261)	(138)	165	190
Accrued liabilities—related party	2
Due to affiliates	(3)	4	8	(6)	22
Deferred revenue	26	56	40	7	38
Other, net	(29)	(26)	(13)	(4)	(4)
Other, net—affiliate			0	0	(12)
Net cash provided by operating activities	1,020	656	1,161	1,423	657
Cash flows from investing activities
Property, plant and equipment, net	(747)	(1,123)	(1,282)	(771)	(1,279)
Other	0	(1)	(1)	0	0
Net cash used in investing activities	(747)	(1,124)	(1,283)	(771)	(1,279)
Cash flows from financing activities
Proceeds from issuances of debt	1,995	0	0	0	2,314
Repayments of Debt	(2,000)	0	0	0	(703)
Debt issuance and other financing costs	(34)	0	0	0	(29)
Debt extinguishment costs	(39)	0
Capital contributions	487	949	1,046	129	7
Distributions	(706)	(1,052)	(1,499)	(569)	(781)
Net cash used in financing activities	(297)	(103)	(453)	(440)	808
Net decrease in cash, cash equivalents and restricted cash	(24)	(571)	(575)	212	186
Cash, cash equivalents and restricted cash—beginning of period	181	756	756	544	358
Cash, cash equivalents and restricted cash—end of period	$ 157	$ 185	$ 181	$ 756	$ 544

Statements of Cash Flows - Bala

Statements of Cash Flows - Balances per Balance Sheets - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Balances per Balance Sheets:
Cash and cash equivalents	$ 0	$ 0		$ 0
Restricted cash	157	181		756
Total cash, cash equivalents and restricted cash	$ 157	$ 181	$ 185	$ 756	$ 544	$ 358

Organization and Nature of Oper

Organization and Nature of Operations	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION We are currently operating five natural gas liquefaction Trains and are constructing one additional Train for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast, adjacent to the existing regasification facilities owned and operated by SPLNG. Basis of Presentation The accompanying unaudited Financial Statements of SPL have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 S-X. 10-K We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income reported on our Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. Results of operations for the nine months ended September 30, 2020 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2020. Recent Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting	NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS We are a Delaware limited liability company formed by Cheniere Partners. We are a Houston-based company with one LNG-LP, LNG-related We are currently operating five

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our financial position, results of operations or cash flows. Recent Accounting Standards We adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) right-of-use right-of-use non-current non-current non-current Use of Estimates The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements, revenue recognition, property, plant and equipment, derivative instruments and asset retirement obligations (“AROs”), as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market. In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates. Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial 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. Revenues from the sale of LNG are recognized as LNG revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues. Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. Accounts Receivable Accounts receivable is reported net of any allowances for doubtful accounts. We periodically review the collectability on our accounts receivable and recognize an allowance if there is probability of non-collection, write-off 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 and subsequently charged to expense when issued. Accounting for LNG Activities 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 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. 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. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets. Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. Interest Capitalization We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. construction-in-process 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. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis. Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2019, 2018 and 2017. 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 cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these 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 Debt Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors. Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, they 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 gain (loss) on modification or extinguishment of debt on our Statements of Income. 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 Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Income, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2019, the tax basis of our assets and liabilities was $4.6 billion less than the reported amounts of our assets and liabilities. Pursuant to the indentures governing our debt, we are permitted to make distributions (“Tax Distributions”) for any fiscal year or portion thereof in which we are a limited partnership, disregarded entity or other substantially similar pass-through entity for federal and state income tax purposes. The Tax Distributions are equal to the tax that we would owe if we were a corporation subject to federal and state income tax that filed separate federal and state income tax returns, excluding the amounts covered by the state tax sharing agreement discussed in Note 12—Related Party Transactions. The Tax Distributions are limited to the amount of federal and/or state income taxes paid by Cheniere to the appropriate taxing authorities and are payable by us within 30 days of the date that Cheniere is required to make federal or state income tax payments to the appropriate taxing authorities. Business Segment Our liquefaction operations at the Sabine Pass LNG terminal represent a single

Restricted Cash

Restricted Cash	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Restricted Cash [Abstract]
Restricted Cash	NOTE 2—RESTRICTED CASH Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. As of September 30, 2020 and December 31, 2019, we had $157 million and $181 million of current restricted cash, respectively. Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.	NOTE 3—RESTRICTED CASH Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. December 31, 2019 2018 Current restricted cash Liquefaction Project $ 181 $ 756 Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.

Accounts and Other Receivables

Accounts and Other Receivables	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Receivables [Abstract]
Accounts and Other Receivables	NOTE 3—ACCOUNTS AND OTHER RECEIVABLES As of September 30, 2020 and December 31, 2019, accounts and other receivables, net consisted of the following (in millions): September 30, December 31, Trade receivable $ 175 $ 283 Other accounts receivable 22 9 Total accounts and other receivables, net $ 197 $ 292	NOTE 4—ACCOUNTS AND OTHER RECEIVABLES As of December 31, 2019 and 2018, accounts and other receivables consisted of the following (in millions): December 31, 2019 2018 Trade receivable $ 283 $ 330 Other accounts receivable 9 16 Total accounts and other receivables $ 292 $ 346

Inventory

Inventory	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Inventory Disclosure [Abstract]
Inventory	NOTE 4—INVENTORY As of September 30, 2020 and December 31, 2019, inventory consisted of the following (in millions): September 30, December 31, Natural gas $ 13 $ 9 LNG 18 27 Materials and other 69 67 Total inventory $ 100 $ 103	NOTE 5—INVENTORY As of December 31, 2019 and 2018, inventory consisted of the following (in millions): December 31, 2019 2018 Natural gas $ 9 $ 28 LNG 27 6 Materials and other 67 53 Total inventory $ 103 $ 87

Property, Plant and Equipment

Property, Plant and Equipment	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	NOTE 5—PROPERTY, PLANT AND EQUIPMENT As of September 30, 2020 and December 31, 2019, property, plant and equipment, net consisted of the following (in millions): September 30, December 31, LNG terminal costs LNG terminal $ 13,700 $ 13,736 LNG terminal construction-in-process 1,924 1,222 Accumulated depreciation (1,446 ) (1,104 ) Total LNG terminal costs, net 14,178 13,854 Fixed assets Fixed assets 19 18 Accumulated depreciation (14 ) (11 ) Total fixed assets, net 5 7 Property, plant and equipment, net $ 14,183 $ 13,861 The following table shows depreciation expense and offsets to LNG terminal costs during the nine months ended September 30, 2020 and 2019 (in millions): Nine Months Ended September 30, 2020 2019 Depreciation expense $ 345 $ 327 Offsets to LNG terminal costs (1) — 48 (1) We realize 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 As of December 31, 2019 and 2018, property, plant and equipment, net consisted of the following (in millions): December 31, 2019 2018 LNG terminal costs LNG terminal $ 13,736 $ 10,004 LNG terminal construction-in-process 1,222 3,866 Accumulated depreciation (1,104 ) (667 ) Total LNG terminal costs, net 13,854 13,203 Fixed assets Fixed assets 18 14 Accumulated depreciation (11 ) (8 ) Total fixed assets, net 7 6 Property, plant and equipment, net $ 13,861 $ 13,209 Depreciation expense was $442 million, $339 million and $257 million during the years ended December 31, 2019, 2018 and 2017, respectively. We realized offsets to LNG terminal costs of $48 million, $94 million and $301 million during the years ended December 31, 2019, 2018 and 2017, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project, during the testing phase for its construction. LNG Terminal Costs LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. Components Useful life (yrs) Water pipelines 30 Liquefaction processing equipment 7-50 Other 10-30 Fixed Assets and Other Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

Derivative Instruments

Derivative Instruments	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	NOTE 6—DERIVATIVE INSTRUMENTS We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Statements of Operations to the extent not utilized for the commissioning process. The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019, which are classified as derivative assets, non-current non-current Fair Value Measurements as of September 30, 2020 December 31, 2019 Quoted Significant Significant Total Quoted Significant Significant Total Liquefaction Supply Derivatives asset (liability) $ (7 ) $ (5 ) $ — $ (12 ) $ 3 $ (3 ) $ 24 $ 24 We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data. The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of September 30, 2020 and December 31, 2019, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow. We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration. The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2020: Net Fair Value Asset Valuation Approach Significant Range of Significant Physical Liquefaction Supply $ — Market approach incorporating Henry Hub $(0.527) - $0.055 / $0.001 (1) Unobservable inputs were weighted by the relative fair value of the instruments. Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives. The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the nine months ended September 30, 2020 and 2019 (in millions): Nine Months Ended 2020 2019 Balance, beginning of period $ 24 $ (25 ) Realized and mark-to-market Included in cost of sales (22 ) (22 ) Purchases and settlements: Purchases 4 (4 ) Settlements (6 ) 43 Transfers into Level 3, net (1) — — Balance, end of period $ — $ (8 ) Change in unrealized losses relating to instruments still held at end of period $ (22 ) $ (22 ) (1) Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off set-off Liquefaction Supply Derivatives We have entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 3,207 TBtu and 3,663 TBtu as of September 30, 2020 and December 31, 2019, respectively, of which 91 TBtu and zero TBtu, respectively, were for a natural gas supply contract that we have with a related party. The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions): Fair Value Measurements as of (1) Balance Sheets Location September 30, December 31, Derivative assets $ 14 $ 17 Non-current 30 32 Total derivative assets 44 49 Derivative liabilities (31 ) (9 ) Non-current (25 ) (16 ) Total derivative liabilities (56 ) (25 ) Derivative asset (liability), net $ (12 ) $ 24 (1) Does not include collateral posted with counterparties by us of $12 million and $2 million for such contracts, which are included in other current assets in our Balance Sheets as of September 30, 2020 and December 31, 2019, respectively. Includes a natural gas supply contract that we have with a related party, which had a fair value of zero as of September 30, 2020. The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Statements of Operations during the nine months ended September 30, 2020 and 2019 (in millions): Statements of Operations Nine Months Ended 2020 2019 Liquefaction Supply Derivatives gain LNG revenues $ 3 $ 2 Liquefaction Supply Derivatives gain (loss) Cost of sales (41 ) 28 (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument. Balance Sheets Presentation Our derivative instruments are presented on a net basis on our Balance Sheets as described above. Offsetting Derivative Assets (Liabilities) Gross Amounts Gross Amounts Net Amounts As of September 30, 2020 Liquefaction Supply Derivatives $ 47 $ (3 ) $ 44 Liquefaction Supply Derivatives (59 ) 3 (56 ) As of December 31, 2019 Liquefaction Supply Derivatives $ 51 $ (2 ) $ 49 Liquefaction Supply Derivatives (27 ) 2 (25 )	NOTE 7—DERIVATIVE INSTRUMENTS We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). We had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of our credit facilities (“Interest Rate Derivatives”), and these Interest Rate Derivatives were settled in March 2017. 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. The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2019 and 2018, which are classified as derivative assets, non-current non-current Fair Value Measurements as of December 31, 2019 December 31, 2018 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) $ 3 $ (3 ) $ 24 $ 24 $ 5 $ (23 ) $ (25 ) $ (43 ) We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available and other relevant data. The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of December 31, 2019 and 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow. We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration. The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas prices. Net Fair Value Asset (in millions) Valuation Approach Significant Significant Unobservable Inputs Range Physical Liquefaction Supply $ 24 Market approach incorporating Henry Hub basis spread $(0.350) - $0.058 Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives. The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, 2019 2018 2017 Balance, beginning of period $ (25 ) $ 43 $ 79 Realized and mark-to-market Included in cost of sales 6 (3 ) (37 ) Purchases and settlements: Purchases — (37 ) 14 Settlements 42 (29 ) (12 ) Transfers out of Level 3 (1) 1 1 (1 ) Balance, end of period $ 24 $ (25 ) $ 43 Change in unrealized gains (losses) relating to instruments still held at end of period $ 6 $ (3 ) $ (37 ) (1) Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off Interest Rate Derivatives In March 2017, we settled the Interest Rate Derivatives we previously had to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities we entered into in June 2015. The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Statements of Income during the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, 2019 2018 2017 Interest Rate Derivatives loss $ — $ — $ (2 ) Liquefaction Supply Derivatives We have entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 3,663 TBtu and 2,978 TBtu as of December 31, 2019 and 2018, respectively. 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 Sheet Location December 31, 2019 December 31, 2018 Derivative assets $ 17 $ 6 Non-current 32 31 Total derivative assets 49 37 Derivative liabilities (9 ) (66 ) Non-current (16 ) (14 ) Total derivative liabilities (25 ) (80 ) Derivative asset (liability), net $ 24 $ (43 ) (1) Does not include collateral posted with counterparties by us of $2 The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Statements of Income during the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, Statement of 2019 2018 2017 Liquefaction Supply Derivatives gain (loss) LNG revenues $ 1 $ (1 ) $ — Liquefaction Supply Derivatives gain (loss) Cost of sales 71 (100 ) (24 ) (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument. Balance Sheet Presentation Our derivative instruments are presented on a net basis on our Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions): Offsetting Derivative Assets (Liabilities) Gross Amounts Gross Amounts Offset Net Amounts As of December 31, 2019 Liquefaction Supply Derivatives $ 51 $ (2 ) $ 49 Liquefaction Supply Derivatives (27 ) 2 (25 ) As of December 31, 2018 Liquefaction Supply Derivatives $ 63 $ (26 ) $ 37 Liquefaction Supply Derivatives (92 ) 12 (80 )

Other Non-Current Assets

Other Non-Current Assets	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Other Assets, Noncurrent [Abstract]
Other Non-Current Assets	NOTE 7—OTHER NON-CURRENT As of September 30, 2020 and December 31, 2019, other non-current September 30, December 31, Advances made to municipalities for water system enhancements $ 85 $ 87 Advances and other asset conveyances to third parties to support LNG terminal 34 35 Operating lease assets 23 21 Information technology service prepayments 5 6 Advances made under EPC and non-EPC 4 15 Other 8 1 Total other non-current $ 159 $ 165	NOTE 8—OTHER NON-CURRENT As of December 31, 2019 and 2018, other non-current December 31, 2019 2018 Advances made to municipalities for water system enhancements $ 87 $ 90 Advances and other asset conveyances to third parties to support LNG terminal 35 36 Operating lease assets 21 — Information technology service prepayments 6 16 Advances made under EPC and non-EPC 15 14 Other 1 2 Total other non-current $ 165 $ 158

Accrued Liabilities

Accrued Liabilities	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	NOTE 8—ACCRUED LIABILITIES As of September 30, 2020 and December 31, 2019, accrued liabilities consisted of the following (in millions): September 30, December 31, Interest costs and related debt fees $ 160 $ 186 Accrued natural gas purchases 212 325 Liquefaction Project costs 54 116 Other accrued liabilities 4 2 Total accrued liabilities $ 430 $ 629	NOTE 9—ACCRUED LIABILITIES As of December 31, 2019 and 2018, accrued liabilities consisted of the following (in millions): December 31, 2019 2018 Interest costs and related debt fees $ 186 $ 186 Accrued natural gas purchases 325 518 Liquefaction Project costs 116 64 Other accrued liabilities 2 — Total accrued liabilities $ 629 $ 768

Debt

Debt	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	NOTE 9—DEBT As of September 30, 2020 and December 31, 2019, our debt consisted of the following (in millions): September 30, December 31, Long-term debt: 4.200% $ 13,650 $ 13,650 Unamortized premium, discount and debt issuance costs, net (136 ) (126 ) Total long-term debt, net 13,514 13,524 Current debt: $1.2 billion Working Capital Facility executed in 2015 (“2015 Working Capital Facility”) — — Total debt, net $ 13,514 $ 13,524 Issuances The following table shows the issuances of debt during the nine months ended September 30, 2020: Maturity Date Interest Principal Amount Nine Months Ended June 30, 2020 4.500% Senior Secured Notes due 2030 (the “2030 Senior Notes”) (1) May 15, 2030 4.500 % $ 2,000 Nine Months Ended September 30, 2020 total $ 2,000 (1) Proceeds of the 2030 Senior Notes, along with available cash, were used to redeem all of our outstanding 5.625% Senior Secured Notes due 2021 (the “2021 Senior Notes”), resulting in the recognition of debt extinguishment costs of $43 million for the nine months ended September 30, 2020 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs. 2020 Working Capital Facility Below is a summary of our 2020 Working Capital Facility as of September 30, 2020 (in millions): 2020 Working Capital Facility (1) Original facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 413 Available commitment $ 787 Interest rate on available balance LIBOR plus 1.125% - 1.750% Weighted average interest rate of outstanding balance n/a Maturity date March 19, 2025 (1) The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. We pay a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on our then-current rating), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans. Restrictive Debt Covenants As of September 30, 2020, 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): Nine Months Ended September 30, 2020 2019 Total interest cost $ 589 $ 593 Capitalized interest (66 ) (69 ) Total interest expense, net of capitalized interest $ 523 $ 524 Fair Value Disclosures The following table shows the carrying amount and estimated fair value of our debt (in millions): September 30, 2020 December 31, 2019 Carrying Estimated Carrying Estimated Senior notes—Level 2 (1) $ 12,850 $ 14,441 $ 12,850 $ 14,050 Senior notes—Level 3 (2) 800 946 800 934 Working capital facility (3) — — — — (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. (3) The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.	NOTE 10—DEBT As of December 31, 2019 and 2018, our debt consisted of the following (in millions): December 31, 2019 2018 Long-term debt 5.625% Senior Secured Notes due 2021 (“2021 Senior Notes”) $ 2,000 $ 2,000 6.25% Senior Secured Notes due 2022 (“2022 Senior Notes”) 1,000 1,000 5.625% Senior Secured Notes due 2023 (“2023 Senior Notes”) 1,500 1,500 5.75% Senior Secured Notes due 2024 (“2024 Senior Notes”) 2,000 2,000 5.625% Senior Secured Notes due 2025 (“2025 Senior Notes”) 2,000 2,000 5.875% Senior Secured Notes due 2026 (“2026 Senior Notes”) 1,500 1,500 5.00% Senior Secured Notes due 2027 (“2027 Senior Notes”) 1,500 1,500 4.200% Senior Secured Notes due 2028 (“2028 Senior Notes”) 1,350 1,350 5.00% Senior Secured Notes due 2037 (“2037 Senior Notes”) 800 800 Unamortized discount, premium and debt issuance costs, net (126 ) (150 ) Total long-term debt, net 13,524 13,500 Current debt $1.2 billion Working Capital Facility (“Working Capital Facility”) — — Total debt, net $ 13,524 $ 13,500 Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2019 (in millions): Years Ending December 31, Principal Payments 2020 $ — 2021 2,000 2022 1,000 2023 1,500 2024 2,000 Thereafter 7,150 Total $ 13,650 Senior Notes The terms of the 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 Senior Notes (collectively with the 2037 Senior Notes, the “Senior Notes”) are governed by a common indenture (the “Indenture”) and the terms of the 2037 Senior Notes are governed by a separate indenture (the “2037 Senior Notes Indenture”). Both the Indenture and the 2037 Senior Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of our restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of our assets and enter into certain LNG sales contracts. Subject to permitted liens, the Senior Notes are secured on a pari passu At any time prior to three months before the respective dates of maturity for each series of the Senior Notes (except for the 2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes and 2037 Senior Notes, in which case the time period is six months before the respective dates of maturity), we may redeem all or part of such series of the Senior Notes at a redemption price equal to the “make-whole” price (except for the 2037 Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. We may also, at any time within three months of the respective maturity dates for each series of the Senior Notes (except for the 2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes and 2037 Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the Senior Notes at a redemption price equal to 100% of the principal amount of such series of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption. Working Capital Facility Below is a summary of our Working Capital Facility as of December 31, 2019 (in millions): Working Capital Facility Original facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 414 Available commitment $ 786 Interest rate on available balance LIBOR plus 1.75% or base rate plus 0.75% Weighted average interest rate of outstanding balance n/a Maturity date December 31, 2020 In September 2015, we entered into the Working Capital Facility with aggregate commitments of $1.2 billion, which was amended in May 2019 in connection with commercialization and financing of Train 6 of the Liquefaction Project. The Working Capital Facility is intended to be used for loans (“Working Capital Loans”), the issuance of letters of credit, as well as for swing line loans (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. We may, from time to time, request increases in the commitments under the Working Capital Facility of up to $760 million and incremental increases in commitments of up to an additional $390 million. Loans under the Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR loans under the Working Capital Facility is 1.75% per annum, and the applicable margin for base rate loans under the Working Capital Facility is 0.75% per annum. Interest on Swing Line Loans and loans deemed made in connection with a draw upon a letter of credit (“LC Loans”) is due and payable on the date the loan becomes due. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period, and interest on base rate loans is due and payable at the end of each fiscal quarter. However, if such base rate loan is converted into a LIBOR loan, interest is due and payable on that date. Additionally, if the loans become due prior to such periods, the interest also becomes due on that date. We pay (1) a commitment fee equal to an annual rate of 0.70% on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding Swing Line Loans and (2) a letter of credit fee equal to an annual rate of 1.75% of the undrawn portion of all letters of credit issued under the Working Capital Facility. If draws are made upon a letter of credit issued under the Working Capital Facility and we do not elect for such draw (an “LC Draw”) to be deemed an LC Loan, we are required to pay the full amount of the LC Draw on or prior to the business day following the notice of the LC Draw. An LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of December 31, 2019, no LC Draws had been made upon any letters of credit issued under the Working Capital Facility. The Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three three five The Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as all of the membership interests in us on a pari passu Restrictive Debt Covenants As of December 31, 2019, we were in compliance with all covenants related to our debt agreements. Interest Expense Total interest expense consisted of the following (in millions): Year Ended December 31, 2019 2018 2017 Total interest cost $ 790 $ 791 $ 779 Capitalized interest (85 ) (202 ) (285 ) Total interest expense, net $ 705 $ 589 $ 494 Fair Value Disclosures The following table shows the carrying amount and estimated fair value of our debt (in millions): December 31, 2019 December 31, 2018 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior notes (1) $ 12,850 $ 14,050 $ 12,850 $ 13,235 2037 Senior Notes (2) 800 934 800 817 (1) Includes 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

Revenues from Contracts with Cu

Revenues from Contracts with Customers	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenues from Contracts with Customers	NOTE 10—REVENUES FROM CONTRACTS WITH CUSTOMERS The following table represents a disaggregation of revenue earned from contracts with customers during the nine months ended September 30, 2020 and 2019 (in millions): Nine Months 2020 2019 LNG revenues (1) $ 3,585 $ 3,676 LNG revenues—affiliate 352 1,017 Total revenues from customers 3,937 4,693 Net derivative gains (2) 3 2 Total revenues $ 3,940 $ 4,695 (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. LNG revenues during the nine months ended September 30, 2020 included $513 million in revenues associated with LNG cargoes for which customers have notified us that they will not take delivery, of which $21 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. (2) See Note 6—Derivative Instruments for additional information about our derivatives. Deferred Revenue Reconciliation The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions): Nine Months Ended Deferred revenues, beginning of period $ 132 Cash received but not yet recognized 157 Revenue recognized from prior period deferral (132 ) Deferred revenues, end of period $ 157 Transaction Price Allocated to Future Performance Obligations Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2020 and December 31, 2019: September 30, 2020 December 31, 2019 Unsatisfied Weighted Average Unsatisfied Weighted Average LNG revenues $ 52.9 9 $ 55.0 10 (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 delivery 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 37% and 53% of our LNG revenues from contracts included in the table above during the nine months ended September 30, 2020 and 2019, 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 FROM CONTRACTS WITH CUSTOMERS The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, 2019 2018 2017 LNG revenues $ 5,210 $ 4,828 $ 2,635 LNG revenues—affiliate 1,312 1,299 1,389 Total revenues from customers 6,522 6,127 4,024 Net derivative gains (losses) (1) 1 (1 ) — Total revenues $ 6,523 $ 6,126 $ 4,024 (1) See Note 7—Derivative Instruments for additional information about our derivatives. LNG Revenues We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 12—Related Party Transactions for additional information regarding these agreements. Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price. Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use. Deferred Revenue Reconciliation The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions): Year Ended December 31, 2019 2018 Deferred revenues, beginning of period $ 91 $ 84 Cash received but not yet recognized 132 91 Revenue recognized from prior period deferral (91 ) (84 ) Deferred revenues, end of period $ 132 $ 91 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, 2019 and 2018 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. Transaction Price Allocated to Future Performance Obligations Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2019 and 2018: December 31, 2019 December 31, 2018 Unsatisfied Transaction Price (in billions) Weighted Average Unsatisfied Weighted Average LNG revenues (2) $ 55.0 10 $ 53.6 10 (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. (2) Includes future consideration from agreement contractually assigned to us from Cheniere Marketing. 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) 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 table above excludes substantially all variable consideration under our SPAs. 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 52% and 57% of our LNG revenues during the years ended December 31, 2019 and 2018, respectively, were related to variable consideration received from customers. All of our LNG revenues—affiliate were related We have entered 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	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 11—RELATED PARTY TRANSACTIONS Below is a summary of our related party transactions as reported on our Statements of Operations for the nine months ended September 30, 2020 and 2019 (in millions): Nine Months Ended 2020 2019 LNG revenues—affiliate Cheniere Marketing Agreements $ 328 $ 1,015 Contracts for Sale and Purchase of Natural Gas and LNG 24 2 Total LNG revenues—affiliate 352 1,017 Cost of sales—affiliate Cheniere Marketing Agreements 32 — Cargo loading fees under TUA 23 29 Contracts for Sale and Purchase of Natural Gas and LNG 5 6 Total cost of sales—affiliate 60 35 Operating and maintenance expense—affiliate TUA 200 196 Natural Gas Transportation Agreement 61 60 Services Agreements 90 78 LNG Site Sublease Agreement 1 1 Total operating and maintenance expense—affiliate 352 335 General and administrative expense—affiliate Services Agreements 54 64 As of September 30, 2020 and December 31, 2019, we had $83 million and $104 million of accounts receivable—affiliate, respectively, under the agreements described below. LNG Terminal-Related Agreements Terminal Use Agreements We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. Cheniere Partners has guaranteed our obligations under our TUA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process. Cheniere Marketing Agreements Cheniere Marketing SPA Cheniere Marketing has an SPA (“Base SPA”) with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG. In May 2019, we and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by us to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo. Cheniere Marketing Master SPA We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. We executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project. Cheniere Marketing Letter Agreements In December 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes scheduled for delivery in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu. Facility Swap Agreement In August 2020, we entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board Natural Gas Transportation and Storage Agreements To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. These agreements with CTPL have a primary term that continues until 20 years from May 2016 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to two consecutive terms of 10 years. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise. As of both September 30, 2020 and December 31, 2019, we recorded due to affiliates of $7 million related to this agreement. We are also party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. We recorded accrued liabilities—related party of $2 million as of September 30, 2020 related to these agreements. Services Agreements As of September 30, 2020 and December 31, 2019, we had $98 million and $133 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement Cheniere Investments Information Technology Services Agreement Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement. Liquefaction O&M Agreement We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on our behalf, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train. Liquefaction MSA We have a management services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day Natural Gas Supply Agreement We are a party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain feed gas for the operation of the Liquefaction Project. The term of the agreement is for five years, which can commence no earlier than November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions precedent. LNG Site Sublease Agreement We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple periods of 10 years with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements. Cooperation Agreement We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We conveyed $5 million in assets to SPLNG under this agreement during the nine months ended September 30, 2020. We did not convey any assets to SPLNG under this agreement during the nine months ended September 30, 2019. Contracts for Sale and Purchase of Natural Gas and LNG We have agreements with SPLNG, CTPL and CCL that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. State Tax Sharing Agreement We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after August 2012.	NOTE 12—RELATED PARTY TRANSACTIONS Below is a summary of our related party transactions as reported on our Statements of Income for the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, 2019 2018 2017 LNG revenues—affiliate Cheniere Marketing Agreements $ 1,309 $ 1,299 $ 1,389 Contracts for Sale and Purchase of Natural Gas and LNG 3 — — Total LNG revenues—affiliate 1,312 1,299 1,389 Cost of sales—affiliate Cargo loading fees under TUA 40 32 23 Contracts for Sale and Purchase of Natural Gas and LNG 7 — — Total cost of sales—affiliate 47 32 23 Operating and maintenance expense—affiliate TUA 261 256 190 Natural Gas Transportation Agreement 81 80 73 Services Agreements 107 87 65 LNG Site Sublease Agreement 1 — 1 Total operating and maintenance expense—affiliate 450 423 329 General and administrative expense—affiliate Services Agreements 79 50 58 As of December 31, 2019 and 2018, we had $104 million and $113 million of accounts receivable—affiliate, respectively, under the agreements described below. LNG Terminal-Related Agreements Terminal Use Agreements We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. Cheniere Partners has guaranteed our obligations under our TUA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process. In connection with our TUA, we are required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is based on our share of the commercial LNG storage capacity at the Sabine Pass LNG terminal. We are also required to reimburse SPLNG for our proportionate share of ad valorem taxes and certain other costs, which are considered variable consideration that are distinctly attributable to the specific years in the TUA. Cheniere Marketing Agreements Cheniere Marketing SPA Cheniere Marketing has an SPA (“Base SPA”) with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG. In May 2019, we and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by us to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo. Cheniere Marketing Master SPA We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. We executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project. Cheniere Marketing Letter Agreements In May 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu that were delivered between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu. In December 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes scheduled for delivery in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu. Natural Gas Transportation Agreements To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have a transportation precedent agreement, firm transportation service agreement and a negotiated rate agreement to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. These agreements have a primary term that continues until 20 years from May 2016 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to two consecutive terms of 10 years. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise. Services Agreements As of December 31, 2019 and 2018, we had $133 million and $210 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement Cheniere Investments Information Technology Services Agreement Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement. Liquefaction O&M Agreement We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on our behalf, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train. Liquefaction MSA We have a management services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day LNG Site Sublease Agreement We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple periods of 10 years with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements. Cooperation Agreement We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We conveyed $351 million in assets to SPLNG under this agreement during the year ended December 31, 2019. We did not convey any assets to SPLNG under this agreement during the years ended December 31, 2018 and 2017. Contracts for Sale and Purchase of Natural Gas and LNG We have agreements with SPLNG, CTPL and CCL that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. State Tax Sharing Agreement We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after August 2012.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 13—COMMITMENTS AND CONTINGENCIES We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2019, are not recognized as liabilities but require disclosures in our Financial Statements. LNG Terminal Commitments and Contingencies Obligations under EPC Contract We have a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 6 of the Liquefaction Project. The EPC contract price for Train 6 of the Liquefaction Project is approximately $2.5 billion, reflecting amounts incurred under change orders through December 31, 2019, and including estimated costs for an optional third marine berth. As of December 31, 2019, we have incurred $1.1 billion under this contract. We have the right to terminate the EPC contract for our convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date. Obligations under SPAs We have third-party SPAs which obligate us to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project. Obligations under Natural Gas Supply, Transportation and Storage Service Agreements We have physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. As of December 31, 2019, we have secured up to approximately 3,850 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the certain events or states of affairs are satisfied. Additionally, we have natural gas transportation and storage service agreements for the Liquefaction Project. The initial term of the natural gas transportation agreements ranges up to 20 years, with renewal options for certain contracts, and commences 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, 2019, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions): Years Ending December 31, Payments 2020 $ 2,329 2021 1,416 2022 931 2023 722 2024 401 Thereafter 2,871 Total $ 8,670 (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread . Obligations under LNG TUAs We have a TUA with SPLNG pursuant to which we have reserved approximately 2 Bcf/d of regasification capacity. See Note 12—Related Party Transactions for additional information regarding this TUA. Additionally, we have a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 5, we gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit us to more flexibly manage our LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. Services Agreements We have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements. Other Commitments State Tax Sharing Agreements We have state tax sharing agreements with Cheniere. See Note 12—Related Party Transactions for information regarding such agreements. Other Agreements In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. 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. In the opinion of management, as of December 31, 2019, 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	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Customer Concentration	NOTE 12—CUSTOMER CONCENTRATION The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable, net balances of 10% or greater of total accounts receivable, net from external customers: Percentage of Total Revenues Percentage of Accounts Receivable, Nine Months Ended September 30, December 31, 2020 2019 2020 2019 Customer A 23 % 30 % 17 % 22 % Customer B 16 % 20 % 21 % 13 % Customer C 19 % 21 % 12 % 22 % Customer D 19 % 23 % 34 % 13 % Customer E * * — 13 % Customer F 10 % * 11 % 14 % * Less than 10%	NOTE 14—CUSTOMER CONCENTRATION The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers: Percentage of Total Revenues Percentage of Accounts Receivable Year Ended December 31, December 31, 2019 2018 2017 2019 2018 Customer A 29 % 30 % 43 % 22 % 35 % Customer B 19 % 23 % 30 % 13 % 23 % Customer C 21 % 24 % 25 % 22 % 30 % Customer D 21 % 20 % — % 13 % * Customer E * — % — % 13 % — % Customer F * — % — % 14 % — % * 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, 2019 2018 2017 United States $ 2,039 $ 1,580 $ 1,161 India 1,113 981 — South Korea 1,071 1,168 666 Ireland 988 1,098 787 Other countries — — 21 Total $ 5,211 $ 4,827 $ 2,635

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION The following table provides supplemental disclosure of cash flow information (in millions): Nine Months Ended 2020 2019 Cash paid during the period for interest, net of amounts capitalized $ 527 $ 542 Non-cash 5 348 The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $217 million and $287 million as of September 30, 2020 and 2019, respectively.	NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2019 2018 2017 Cash paid during the period for interest, net of amounts capitalized $ 678 $ 604 $ 438 Non-cash 351 — — The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $276 million, $256 million and $268 million as of December 31, 2019, 2018 and 2017, respectively.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation, Policy	The accompanying unaudited Financial Statements of SPL have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 S-X. 10-K	Basis of Presentation Our Financial Statements have been prepared in accordance with GAAP. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our financial position, results of operations or cash flows.
Recent Accounting Standards	In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting	Recent Accounting Standards We adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) right-of-use right-of-use non-current non-current non-current
Use of Estimates, Policy		Use of Estimates The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements, revenue recognition, property, plant and equipment, derivative instruments and asset retirement obligations (“AROs”), as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements, Policy		Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market. In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates. Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial
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. Revenues from the sale of LNG are recognized as LNG revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.
Cash and Cash Equivalents, Policy		Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash, Policy		Restricted Cash Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets.
Accounts Receivable, Policy		Accounts Receivable Accounts receivable is reported net of any allowances for doubtful accounts. We periodically review the collectability on our accounts receivable and recognize an allowance if there is probability of non-collection, write-off
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 and subsequently charged to expense when issued.
Accounting For LNG Activities, Policy		Accounting for LNG Activities 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
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. 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. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets. Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.
Interest Capitalization, Policy		Interest Capitalization We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. construction-in-process
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. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis. Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did not have any derivative instruments designated as cash
Concentration of Credit Risk, Policy		Concentration of Credit Risk Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these 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
Debt, Policy		Debt Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors. Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, they 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 gain (loss) on modification or extinguishment of debt on our Statements of Income.
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
Income Taxes, Policy	We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income reported on our Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. 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, which may vary substantially from the net income or loss reported on our Statements of Income, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2019, the tax basis of our assets and liabilities was $4.6 billion less than the reported amounts of our assets and liabilities. Pursuant to the indentures governing our debt, we are permitted to make distributions (“Tax Distributions”) for any fiscal year or portion thereof in which we are a limited partnership, disregarded entity or other substantially similar pass-through entity for federal and state income tax purposes. The Tax Distributions are equal to the tax that we would owe if we were a corporation subject to federal and state income tax that filed separate federal and state income tax returns, excluding the amounts covered by the state tax sharing agreement discussed in Note 12—Related Party Transactions. The Tax Distributions are limited to the amount of federal and/or state income taxes paid by Cheniere to the appropriate taxing authorities and are payable by us within 30 days of the date that Cheniere is required to make federal or state income tax payments to the appropriate taxing authorities.
Business Segment, Policy		Business Segment Our liquefaction operations at the Sabine Pass LNG terminal represent a single

Restricted Cash (Tables)

Restricted Cash (Tables)	12 Months Ended
	Dec. 31, 2019
Restricted Cash [Abstract]
Schedule of Restricted Cash	As of December 31, 2019 and 2018, restricted cash consisted of the following (in millions): December 31, 2019 2018 Current restricted cash Liquefaction Project $ 181 $ 756

Accounts and Other Receivables

Accounts and Other Receivables (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Receivables [Abstract]
Schedule of Accounts and Other Receivables	As of September 30, 2020 and December 31, 2019, accounts and other receivables, net consisted of the following (in millions): September 30, December 31, Trade receivable $ 175 $ 283 Other accounts receivable 22 9 Total accounts and other receivables, net $ 197 $ 292	As of December 31, 2019 and 2018, accounts and other receivables consisted of the following (in millions): December 31, 2019 2018 Trade receivable $ 283 $ 330 Other accounts receivable 9 16 Total accounts and other receivables $ 292 $ 346

Inventory (Tables)

Inventory (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Inventory Disclosure [Abstract]
Schedule of Inventory	As of September 30, 2020 and December 31, 2019, inventory consisted of the following (in millions): September 30, December 31, Natural gas $ 13 $ 9 LNG 18 27 Materials and other 69 67 Total inventory $ 100 $ 103	As of December 31, 2019 and 2018, inventory consisted of the following (in millions): December 31, 2019 2018 Natural gas $ 9 $ 28 LNG 27 6 Materials and other 67 53 Total inventory $ 103 $ 87

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	As of September 30, 2020 and December 31, 2019, property, plant and equipment, net consisted of the following (in millions): September 30, December 31, LNG terminal costs LNG terminal $ 13,700 $ 13,736 LNG terminal construction-in-process 1,924 1,222 Accumulated depreciation (1,446 ) (1,104 ) Total LNG terminal costs, net 14,178 13,854 Fixed assets Fixed assets 19 18 Accumulated depreciation (14 ) (11 ) Total fixed assets, net 5 7 Property, plant and equipment, net $ 14,183 $ 13,861	As of December 31, 2019 and 2018, property, plant and equipment, net consisted of the following (in millions): December 31, 2019 2018 LNG terminal costs LNG terminal $ 13,736 $ 10,004 LNG terminal construction-in-process 1,222 3,866 Accumulated depreciation (1,104 ) (667 ) Total LNG terminal costs, net 13,854 13,203 Fixed assets Fixed assets 18 14 Accumulated depreciation (11 ) (8 ) Total fixed assets, net 7 6 Property, plant and equipment, net $ 13,861 $ 13,209
Property Plant and Equipment Estimated Useful Lives Table [Table Text Block]	The following table shows depreciation expense and offsets to LNG terminal costs during the nine months ended September 30, 2020 and 2019 (in millions): Nine Months Ended September 30, 2020 2019 Depreciation expense $ 345 $ 327 Offsets to LNG terminal costs (1) — 48 (1) We realize 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 identifiable components of the Liquefaction Project have depreciable lives between 7 Components Useful life (yrs) Water pipelines 30 Liquefaction processing equipment 7-50 Other 10-30

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair Value of Derivative Assets and Liabilities	The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019, which are classified as derivative assets, non-current non-current Fair Value Measurements as of September 30, 2020 December 31, 2019 Quoted Significant Significant Total Quoted Significant Significant Total Liquefaction Supply Derivatives asset (liability) $ (7 ) $ (5 ) $ — $ (12 ) $ 3 $ (3 ) $ 24 $ 24	The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2019 and 2018, which are classified as derivative assets, non-current non-current Fair Value Measurements as of December 31, 2019 December 31, 2018 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) $ 3 $ (3 ) $ 24 $ 24 $ 5 $ (23 ) $ (25 ) $ (43 )
Fair Value Measurement Inputs and Valuation Techniques	The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2020: Net Fair Value Asset Valuation Approach Significant Range of Significant Physical Liquefaction Supply $ — Market approach incorporating Henry Hub $(0.527) - $0.055 / $0.001 (1) Unobservable inputs were weighted by the relative fair value of the instruments.	The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2019: Net Fair Value Asset (in millions) Valuation Approach Significant Significant Unobservable Inputs Range Physical Liquefaction Supply $ 24 Market approach incorporating Henry Hub basis spread $(0.350) - $0.058
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the nine months ended September 30, 2020 and 2019 (in millions): Nine Months Ended 2020 2019 Balance, beginning of period $ 24 $ (25 ) Realized and mark-to-market Included in cost of sales (22 ) (22 ) Purchases and settlements: Purchases 4 (4 ) Settlements (6 ) 43 Transfers into Level 3, net (1) — — Balance, end of period $ — $ (8 ) Change in unrealized losses relating to instruments still held at end of period $ (22 ) $ (22 ) (1) Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.	The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, 2019 2018 2017 Balance, beginning of period $ (25 ) $ 43 $ 79 Realized and mark-to-market Included in cost of sales 6 (3 ) (37 ) Purchases and settlements: Purchases — (37 ) 14 Settlements 42 (29 ) (12 ) Transfers out of Level 3 (1) 1 1 (1 ) Balance, end of period $ 24 $ (25 ) $ 43 Change in unrealized gains (losses) relating to instruments still held at end of period $ 6 $ (3 ) $ (37 ) (1) Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.
Fair Value of Derivative Instruments by Balance Sheet Location	The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions): Fair Value Measurements as of (1) Balance Sheets Location September 30, December 31, Derivative assets $ 14 $ 17 Non-current 30 32 Total derivative assets 44 49 Derivative liabilities (31 ) (9 ) Non-current (25 ) (16 ) Total derivative liabilities (56 ) (25 ) Derivative asset (liability), net $ (12 ) $ 24 (1) Does not include collateral posted with counterparties by us of $12 million and $2 million for such contracts, which are included in other current assets in our Balance Sheets as of September 30, 2020 and December 31, 2019, respectively. Includes a natural gas supply contract that we have with a related party, which had a fair value of zero as of September 30, 2020.	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 Sheet Location December 31, 2019 December 31, 2018 Derivative assets $ 17 $ 6 Non-current 32 31 Total derivative assets 49 37 Derivative liabilities (9 ) (66 ) Non-current (16 ) (14 ) Total derivative liabilities (25 ) (80 ) Derivative asset (liability), net $ 24 $ (43 ) (1) Does not include collateral posted with counterparties by us of $2
Derivative Instruments, Gain (Loss)	The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Statements of Operations during the nine months ended September 30, 2020 and 2019 (in millions): Statements of Operations Nine Months Ended 2020 2019 Liquefaction Supply Derivatives gain LNG revenues $ 3 $ 2 Liquefaction Supply Derivatives gain (loss) Cost of sales (41 ) 28 (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
Derivative Net Presentation on Balance Sheets	The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions): Offsetting Derivative Assets (Liabilities) Gross Amounts Gross Amounts Net Amounts As of September 30, 2020 Liquefaction Supply Derivatives $ 47 $ (3 ) $ 44 Liquefaction Supply Derivatives (59 ) 3 (56 ) As of December 31, 2019 Liquefaction Supply Derivatives $ 51 $ (2 ) $ 49 Liquefaction Supply Derivatives (27 ) 2 (25 )	The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions): Offsetting Derivative Assets (Liabilities) Gross Amounts Gross Amounts Offset Net Amounts As of December 31, 2019 Liquefaction Supply Derivatives $ 51 $ (2 ) $ 49 Liquefaction Supply Derivatives (27 ) 2 (25 ) As of December 31, 2018 Liquefaction Supply Derivatives $ 63 $ (26 ) $ 37 Liquefaction Supply Derivatives (92 ) 12 (80 )
Interest Rate Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Instruments, Gain (Loss)		The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Statements of Income during the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, 2019 2018 2017 Interest Rate Derivatives loss $ — $ — $ (2 )
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Instruments, Gain (Loss)		The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Statements of Income during the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, Statement of 2019 2018 2017 Liquefaction Supply Derivatives gain (loss) LNG revenues $ 1 $ (1 ) $ — Liquefaction Supply Derivatives gain (loss) Cost of sales 71 (100 ) (24 ) (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

Other Non-Current Assets (Table

Other Non-Current Assets (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Other Assets, Noncurrent [Abstract]
Schedule of Other Non-Current Assets	As of September 30, 2020 and December 31, 2019, other non-current September 30, December 31, Advances made to municipalities for water system enhancements $ 85 $ 87 Advances and other asset conveyances to third parties to support LNG terminal 34 35 Operating lease assets 23 21 Information technology service prepayments 5 6 Advances made under EPC and non-EPC 4 15 Other 8 1 Total other non-current $ 159 $ 165	As of December 31, 2019 and 2018, other non-current December 31, 2019 2018 Advances made to municipalities for water system enhancements $ 87 $ 90 Advances and other asset conveyances to third parties to support LNG terminal 35 36 Operating lease assets 21 — Information technology service prepayments 6 16 Advances made under EPC and non-EPC 15 14 Other 1 2 Total other non-current $ 165 $ 158

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Accrued Liabilities, Current [Abstract]
Schedule of Accrued Liabilities	As of September 30, 2020 and December 31, 2019, accrued liabilities consisted of the following (in millions): September 30, December 31, Interest costs and related debt fees $ 160 $ 186 Accrued natural gas purchases 212 325 Liquefaction Project costs 54 116 Other accrued liabilities 4 2 Total accrued liabilities $ 430 $ 629	As of December 31, 2019 and 2018, accrued liabilities consisted of the following (in millions): December 31, 2019 2018 Interest costs and related debt fees $ 186 $ 186 Accrued natural gas purchases 325 518 Liquefaction Project costs 116 64 Other accrued liabilities 2 — Total accrued liabilities $ 629 $ 768

Debt (Tables)

Debt (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Debt Instruments	As of September 30, 2020 and December 31, 2019, our debt consisted of the following (in millions): September 30, December 31, Long-term debt: 4.200% $ 13,650 $ 13,650 Unamortized premium, discount and debt issuance costs, net (136 ) (126 ) Total long-term debt, net 13,514 13,524 Current debt: $1.2 billion Working Capital Facility executed in 2015 (“2015 Working Capital Facility”) — — Total debt, net $ 13,514 $ 13,524	As of December 31, 2019 and 2018, our debt consisted of the following (in millions): December 31, 2019 2018 Long-term debt 5.625% Senior Secured Notes due 2021 (“2021 Senior Notes”) $ 2,000 $ 2,000 6.25% Senior Secured Notes due 2022 (“2022 Senior Notes”) 1,000 1,000 5.625% Senior Secured Notes due 2023 (“2023 Senior Notes”) 1,500 1,500 5.75% Senior Secured Notes due 2024 (“2024 Senior Notes”) 2,000 2,000 5.625% Senior Secured Notes due 2025 (“2025 Senior Notes”) 2,000 2,000 5.875% Senior Secured Notes due 2026 (“2026 Senior Notes”) 1,500 1,500 5.00% Senior Secured Notes due 2027 (“2027 Senior Notes”) 1,500 1,500 4.200% Senior Secured Notes due 2028 (“2028 Senior Notes”) 1,350 1,350 5.00% Senior Secured Notes due 2037 (“2037 Senior Notes”) 800 800 Unamortized discount, premium and debt issuance costs, net (126 ) (150 ) Total long-term debt, net 13,524 13,500 Current debt $1.2 billion Working Capital Facility (“Working Capital Facility”) — — Total debt, net $ 13,524 $ 13,500
Schedule of Debt Issuances	The following table shows the issuances of debt during the nine months ended September 30, 2020: Maturity Date Interest Principal Amount Nine Months Ended June 30, 2020 4.500% Senior Secured Notes due 2030 (the “2030 Senior Notes”) (1) May 15, 2030 4.500 % $ 2,000 Nine Months Ended September 30, 2020 total $ 2,000 (1) Proceeds of the 2030 Senior Notes, along with available cash, were used to redeem all of our outstanding 5.625% Senior Secured Notes due 2021 (the “2021 Senior Notes”), resulting in the recognition of debt extinguishment costs of $43 million for the nine months ended September 30, 2020 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.
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, 2019 (in millions): Years Ending December 31, Principal Payments 2020 $ — 2021 2,000 2022 1,000 2023 1,500 2024 2,000 Thereafter 7,150 Total $ 13,650
Schedule of Line of Credit Facilities	Below is a summary of our 2020 Working Capital Facility as of September 30, 2020 (in millions): 2020 Working Capital Facility (1) Original facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 413 Available commitment $ 787 Interest rate on available balance LIBOR plus 1.125% - 1.750% Weighted average interest rate of outstanding balance n/a Maturity date March 19, 2025 (1) The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. We pay a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on our then-current rating), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.	Below is a summary of our Working Capital Facility as of December 31, 2019 (in millions): Working Capital Facility Original facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 414 Available commitment $ 786 Interest rate on available balance LIBOR plus 1.75% or base rate plus 0.75% Weighted average interest rate of outstanding balance n/a Maturity date December 31, 2020
Schedule of Interest Expense	Total interest expense, net of capitalized interest consisted of the following (in millions): Nine Months Ended September 30, 2020 2019 Total interest cost $ 589 $ 593 Capitalized interest (66 ) (69 ) Total interest expense, net of capitalized interest $ 523 $ 524	Total interest expense consisted of the following (in millions): Year Ended December 31, 2019 2018 2017 Total interest cost $ 790 $ 791 $ 779 Capitalized interest (85 ) (202 ) (285 ) Total interest expense, net $ 705 $ 589 $ 494
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments	The following table shows the carrying amount and estimated fair value of our debt (in millions): September 30, 2020 December 31, 2019 Carrying Estimated Carrying Estimated Senior notes—Level 2 (1) $ 12,850 $ 14,441 $ 12,850 $ 14,050 Senior notes—Level 3 (2) 800 946 800 934 Working capital facility (3) — — — — (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. (3) The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.	The following table shows the carrying amount and estimated fair value of our debt (in millions): December 31, 2019 December 31, 2018 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior notes (1) $ 12,850 $ 14,050 $ 12,850 $ 13,235 2037 Senior Notes (2) 800 934 800 817 (1) Includes 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

Revenues from Contracts with _2

Revenues from Contracts with Customers (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table represents a disaggregation of revenue earned from contracts with customers during the nine months ended September 30, 2020 and 2019 (in millions): Nine Months 2020 2019 LNG revenues (1) $ 3,585 $ 3,676 LNG revenues—affiliate 352 1,017 Total revenues from customers 3,937 4,693 Net derivative gains (2) 3 2 Total revenues $ 3,940 $ 4,695 (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. LNG revenues during the nine months ended September 30, 2020 included $513 million in revenues associated with LNG cargoes for which customers have notified us that they will not take delivery, of which $21 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. (2) See Note 6—Derivative Instruments for additional information about our derivatives.	The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, 2019 2018 2017 LNG revenues $ 5,210 $ 4,828 $ 2,635 LNG revenues—affiliate 1,312 1,299 1,389 Total revenues from customers 6,522 6,127 4,024 Net derivative gains (losses) (1) 1 (1 ) — Total revenues $ 6,523 $ 6,126 $ 4,024 (1) See Note 7—Derivative Instruments for additional information about our derivatives.
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): Nine Months Ended Deferred revenues, beginning of period $ 132 Cash received but not yet recognized 157 Revenue recognized from prior period deferral (132 ) Deferred revenues, end of period $ 157	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, 2019 2018 Deferred revenues, beginning of period $ 91 $ 84 Cash received but not yet recognized 132 91 Revenue recognized from prior period deferral (91 ) (84 ) Deferred revenues, end of period $ 132 $ 91
Transaction Price Allocated to Future Performance Obligations	The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2020 and December 31, 2019: September 30, 2020 December 31, 2019 Unsatisfied Weighted Average Unsatisfied Weighted Average LNG revenues $ 52.9 9 $ 55.0 10 (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 as of December 31, 2019 and 2018: December 31, 2019 December 31, 2018 Unsatisfied Transaction Price (in billions) Weighted Average Unsatisfied Weighted Average LNG revenues (2) $ 55.0 10 $ 53.6 10 (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. (2) Includes future consideration from agreement contractually assigned to us from Cheniere Marketing.

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Below is a summary of our related party transactions as reported on our Statements of Operations for the nine months ended September 30, 2020 and 2019 (in millions): Nine Months Ended 2020 2019 LNG revenues—affiliate Cheniere Marketing Agreements $ 328 $ 1,015 Contracts for Sale and Purchase of Natural Gas and LNG 24 2 Total LNG revenues—affiliate 352 1,017 Cost of sales—affiliate Cheniere Marketing Agreements 32 — Cargo loading fees under TUA 23 29 Contracts for Sale and Purchase of Natural Gas and LNG 5 6 Total cost of sales—affiliate 60 35 Operating and maintenance expense—affiliate TUA 200 196 Natural Gas Transportation Agreement 61 60 Services Agreements 90 78 LNG Site Sublease Agreement 1 1 Total operating and maintenance expense—affiliate 352 335 General and administrative expense—affiliate Services Agreements 54 64	Below is a summary of our related party transactions as reported on our Statements of Income for the years ended December 31, 2019, 2018 and 2017 (in millions): Year Ended December 31, 2019 2018 2017 LNG revenues—affiliate Cheniere Marketing Agreements $ 1,309 $ 1,299 $ 1,389 Contracts for Sale and Purchase of Natural Gas and LNG 3 — — Total LNG revenues—affiliate 1,312 1,299 1,389 Cost of sales—affiliate Cargo loading fees under TUA 40 32 23 Contracts for Sale and Purchase of Natural Gas and LNG 7 — — Total cost of sales—affiliate 47 32 23 Operating and maintenance expense—affiliate TUA 261 256 190 Natural Gas Transportation Agreement 81 80 73 Services Agreements 107 87 65 LNG Site Sublease Agreement 1 — 1 Total operating and maintenance expense—affiliate 450 423 329 General and administrative expense—affiliate Services Agreements 79 50 58

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Long-term Purchase Commitment [Line Items]
Contractual Obligation, Fiscal Year Maturity [Table Text Block]	As of December 31, 2019, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions): Years Ending December 31, Payments 2020 $ 2,329 2021 1,416 2022 931 2023 722 2024 401 Thereafter 2,871 Total $ 8,670 (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread .

Customer Concentration (Tables)

Customer Concentration (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Schedule of Revenue and Accounts Receivable by Major Customers	The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable, net balances of 10% or greater of total accounts receivable, net from external customers: Percentage of Total Revenues Percentage of Accounts Receivable, Nine Months Ended September 30, December 31, 2020 2019 2020 2019 Customer A 23 % 30 % 17 % 22 % Customer B 16 % 20 % 21 % 13 % Customer C 19 % 21 % 12 % 22 % Customer D 19 % 23 % 34 % 13 % Customer E * * — 13 % Customer F 10 % * 11 % 14 % * Less than 10%	The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers: Percentage of Total Revenues Percentage of Accounts Receivable Year Ended December 31, December 31, 2019 2018 2017 2019 2018 Customer A 29 % 30 % 43 % 22 % 35 % Customer B 19 % 23 % 30 % 13 % 23 % Customer C 21 % 24 % 25 % 22 % 30 % Customer D 21 % 20 % — % 13 % * Customer E * — % — % 13 % — % Customer F * — % — % 14 % — % * 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, 2019 2018 2017 United States $ 2,039 $ 1,580 $ 1,161 India 1,113 981 — South Korea 1,071 1,168 666 Ireland 988 1,098 787 Other countries — — 21 Total $ 5,211 $ 4,827 $ 2,635

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table provides supplemental disclosure of cash flow information (in millions): Nine Months Ended 2020 2019 Cash paid during the period for interest, net of amounts capitalized $ 527 $ 542 Non-cash 5 348	The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2019 2018 2017 Cash paid during the period for interest, net of amounts capitalized $ 678 $ 604 $ 438 Non-cash 351 — —

Organization and Nature of Op_2

Organization and Nature of Operations (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2020milliontonnesPerYtrains	Dec. 31, 2019milliontonnesPerYtrainsMember
Organization And Nature Of Operations [Line Items]
Limited Liability Company (LLC), Number Of Members | Member		1
Sabine Pass LNG Terminal [Member]
Organization And Nature Of Operations [Line Items]
Number of Liquefaction LNG Trains Operating	5	5
Number of Liquefaction LNG Trains Constructing	1	1
Total Production Capability | milliontonnesPerY	30	30
Cheniere [Member] | Cheniere Partners [Member]
Organization And Nature Of Operations [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent		48.60%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2019USD ($)CustomerUnit	Sep. 30, 2020USD ($)	Jan. 01, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Operating lease assets	$ 21,000,000	$ 23,000,000
Accounts Receivable, Allowance for Credit Loss, Current	0			$ 0
Derivative instruments designated as cash flow hedges	$ 0			$ 0	$ 0
Concentration Risk, Number of Significant Customers | Customer	8
Income Tax Expense	$ 0
Taxes, Difference in Bases, Amount	$ 4,600,000,000
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
Maximum [Member] | Sabine Pass LNG Terminal [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Property Lease Term	90 years
Other Noncurrent Assets [Member] | Accounting Standards Update 2016-02 [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Operating lease assets			$ 20,000,000
Other Noncurrent Liabilities [Member] | Accounting Standards Update 2016-02 [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Operating lease liabilities			4,000,000
Other Noncurrent Liabilities Related Party [Member] | Accounting Standards Update 2016-02 [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Operating lease liabilities			$ 16,000,000

Restricted Cash (Details)

Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 157	$ 181	$ 756
Liquefaction Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 157	$ 181	$ 756

Accounts and Other Receivable_2

Accounts and Other Receivables (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Receivables [Abstract]
Trade receivable	$ 175	$ 283	$ 330
Other accounts receivable	22	9	16
Total accounts and other receivables, net	$ 197	$ 292	$ 346

Inventory (Details)

Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Inventory [Line Items]
Inventory	$ 100	$ 103	$ 87
Natural gas [Member]
Inventory [Line Items]
Inventory	13	9	28
LNG [Member]
Inventory [Line Items]
Inventory	18	27	6
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 69	$ 67	$ 53

Property, Plant and Equipment -

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	9 Months Ended				12 Months Ended
	Sep. 30, 2020		Sep. 30, 2019		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 345		$ 327		$ 442	$ 339	$ 257
Offsets to LNG terminal costs	$ 0	[1]	$ 48	[1]	$ 48	$ 94	$ 301
[1]	We realize 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_2

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 14,183	$ 13,861	$ 13,209
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(1,446)	(1,104)	(667)
Property, plant and equipment, net	14,178	13,854	13,203
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	13,700	13,736	10,004
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,924	1,222	3,866
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19	18	14
Accumulated depreciation	(14)	(11)	(8)
Property, plant and equipment, net	$ 5	$ 7	$ 6

Property, Plant and Equipment_3

Property, Plant and Equipment - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions	9 Months Ended				12 Months Ended
	Sep. 30, 2020		Sep. 30, 2019		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Depreciation	$ 345		$ 327		$ 442	$ 339	$ 257
Offsets to LNG terminal costs	$ 0	[1]	$ 48	[1]	$ 48	$ 94	$ 301
[1]	We realize 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_4

Property, Plant and Equipment - Estimated Useful Lives (Details)	12 Months Ended
	Dec. 31, 2019
LNG terminal costs [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	7 years
LNG terminal costs [Member] | 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	7 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	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	3,207	3,663
Natural Gas Supply Agreement [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	91	0
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	10 years	10 years
Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount		3,663	2,978

Derivative Instruments - Fair V

Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (12)	$ 24	$ (43)
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	(7)	3	5
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	(5)	(3)	(23)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 24	$ (25)

Derivative Instruments - Fair_2

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($)	9 Months Ended		12 Months Ended
	Sep. 30, 2020		Dec. 31, 2019
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset	$ 0
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset			$ 24,000,000
Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	527,000	[1]	(0.350)
Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	55,000	[1]	$ 0.058
Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Inputs Range	$ 1,000
[1]	Unobservable inputs were weighted by the relative fair value of the instruments.

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions	9 Months Ended				12 Months Ended
	Sep. 30, 2020		Sep. 30, 2019		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period	$ 24		$ (25)		$ (25)		$ 43		$ 79
Realized and mark-to-market gains (losses):
Included in cost of sales	(22)		(22)		6		(3)		(37)
Purchases and settlements:
Purchases	4		(4)		0		(37)		14
Settlements	(6)		43		42		(29)		(12)
Transfers out of Level 3	0	[1]	0	[1]	1	[2]	1	[2]	(1)	[2]
Balance, end of period	0		(8)		24		(25)		43
Change in unrealized gains (losses) relating to instruments still held at end of period	$ (22)		$ (22)		$ 6		$ (3)		$ (37)
[1]	Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
[2]	Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative Instruments - Fair_3

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative assets		$ 14	$ 17	$ 6
Non-current derivative assets		30	32	31
Total derivative assets	[1]	44	49
Derivative liabilities		(31)	(9)	(66)
Non-current derivative liabilities		(25)	(16)	(14)
Total derivative liabilities	[1]	(56)	(25)
Derivative asset (liability), net	[1]	(12)	24
Derivative assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		14	17
Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets		30	32
Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		(31)	(9)
Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		$ (25)	(16)
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[2]		49	37
Total derivative liabilities	[2]		(25)	(80)
Derivative asset (liability), net	[2]		24	(43)
Derivative, collateral posted by us			2	1
Liquefaction Supply Derivatives [Member] | Derivative assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[2]		17	6
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[2]		32	31
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[2]		(9)	(66)
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[2]		$ (16)	$ (14)
[1]	Does not include collateral posted with counterparties by us of $12 million and $2 million for such contracts, which are included in other current assets in our Balance Sheets as of September 30, 2020 and December 31, 2019, respectively. Includes a natural gas supply contract that we have with a related party, which had a fair value of zero as of September 30, 2020.
[2]	Does not include collateral posted with counterparties by us of $2 million and $1 million for such contracts, which are included in other current assets in our Balance Sheets as of December 31, 2019 and 2018, respectively.

Derivative Instruments - Deriva

Derivative Instruments - Derivative Gain (Loss) (Details) - USD ($) $ in Millions		9 Months Ended		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 3	$ 2
Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ (41)	$ 28
Interest Rate Derivatives [Member] | Gain (Loss) on Derivative Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net				$ 0	$ 0	$ (2)
Liquefaction Supply Derivatives [Member] | LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[2]			1	(1)	0
Liquefaction Supply Derivatives [Member] | Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[2]			$ 71	$ (100)	$ (24)
[1]	Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
[2]	Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

Derivative Instruments - Deri_2

Derivative Instruments - Derivative Net Presentation on Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	$ 47	$ 51	$ 63
Derivative Asset, Gross Amounts Offset in the Balance Sheets	(3)	(2)	(26)
Net Amounts Presented in our Balance Sheets	44	49	37
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(59)	(27)	(92)
Derivative Liability, Gross Amounts Offset in the Balance Sheets	3	2	12
Net Amounts Presented in our Balance Sheets	$ (56)	$ (25)	$ (80)

Other Non-Current Assets (Detai

Other Non-Current Assets (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Assets, Noncurrent [Abstract]
Advances made to municipalities for water system enhancements	$ 85	$ 87	$ 90
Advances and other asset conveyances to third parties to support LNG terminal	34	35	36
Operating lease assets	23	21
Information technology service prepayments	5	6	16
Advances made under EPC and non-EPC contracts	4	15	14
Other	8	1	2
Total Other non-current assets, net	$ 159	$ 165	$ 158

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 160	$ 186	$ 186
Accrued natural gas purchases	212	325	518
Liquefaction Project costs	54	116	64
Other accrued liabilities	4	2
Total accrued liabilities	$ 430	$ 629	$ 768

Debt - Schedule of Debt Instrum

Debt - Schedule of Debt Instruments (Details) - USD ($)	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 13,650,000,000	$ 13,650,000,000
Unamortized discount, premium and debt issuance costs, net		(126,000,000)	$ (150,000,000)
Long-term Debt, Net	13,514,000,000	13,524,000,000	13,500,000,000
Current Debt, Working Capital Facility	0	0
Total Debt, Net	13,514,000,000	13,524,000,000	13,500,000,000
2021 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
2022 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,000,000,000	1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.25%
2023 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
2024 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.75%
2025 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,000,000,000	2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
2026 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.875%
2027 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.00%
2028 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,350,000,000	1,350,000,000
Debt Instrument, Interest Rate, Stated Percentage		4.20%
2037 Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 800,000,000	800,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.00%
Working Capital Facility [Member]
Debt Instrument [Line Items]
Current Debt, Working Capital Facility		$ 0	0
Line of Credit Facility, Maximum Borrowing Capacity	1,200,000,000	1,200,000,000	$ 1,200,000,000
Long-term Debt [Member]
Debt Instrument [Line Items]
Unamortized discount, premium and debt issuance costs, net	$ (136,000,000)	$ (126,000,000)
Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.20%

Debt - Schedule of Debt Issuanc

Debt - Schedule of Debt Issuances (Details) - USD ($) $ in Millions		9 Months Ended		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 2,000
Loss on modification or extinguishment of debt		$ (43)	$ 0	$ 0	$ 0	$ (42)
2030 Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	[1]	May 15, 2030
Debt Instrument, Interest Rate, Stated Percentage	[1]	4.50%
Debt Instrument, Face Amount	[1]	$ 2,000
Loss on modification or extinguishment of debt		$ 43
[1]	Proceeds of the 2030 Senior Notes, along with available cash, were used to redeem all of our outstanding 5.625% Senior Secured Notes due 2021 (the “2021 Senior Notes”), resulting in the recognition of debt extinguishment costs of $43 million for the nine months ended September 30, 2020 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

Debt - Schedule of Maturities (

Debt - Schedule of Maturities (Details) $ in Millions	Dec. 31, 2019USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2020	$ 0
2021	2,000
2022	1,000
2023	1,500
2024	2,000
Thereafter	7,150
Total	$ 13,650

Debt - Senior Notes (Details)

Debt - Senior Notes (Details)	12 Months Ended
	Dec. 31, 2019Rate
Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Fixed Charge, Coverage Ratio	1.25
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes, Excluding 2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes and 2037 Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Period, Minimum Number of Months Prior to Maturity Date, Redemption Price Equals Make Whole Price	3 months
Debt Instrument, Redemption Period, Maximum Number of Months Prior to Maturity Date, Redemption Price Equals Principal Amount	3 months
2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes and 2037 Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Period, Minimum Number of Months Prior to Maturity Date, Redemption Price Equals Make Whole Price	6 months
Debt Instrument, Redemption Period, Maximum Number of Months Prior to Maturity Date, Redemption Price Equals Principal Amount	6 months

Debt - Credit Facilities (Detai

Debt - Credit Facilities (Details) - USD ($)		9 Months Ended	12 Months Ended
		Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Outstanding balance		$ 0	$ 0
Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size			1,200,000,000
Outstanding balance			0	$ 0
Letters of credit issued			414
Available commitment			$ 786,000,000
Debt Instrument, Description of Variable Rate Basis			LIBOR or base rate
Debt Instrument, Maturity Date			Dec. 31, 2020
Line of Credit Facility, Maximum Borrowing Capacity		1,200,000,000	$ 1,200,000,000	$ 1,200,000,000
Line of Credit Facility, Commitment Fee Percentage			0.70%
Working Capital Facility [Member] | Portion issued and not drawn [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage			1.75%
Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.75%
Working Capital Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.75%
Working Capital Facility [Member] | Base Rate Determination Federal Funds Rate [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.50%
Working Capital Facility [Member] | Base Rate Determination LIBOR [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.50%
Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility Permitted Increase			$ 760,000,000
Line of Credit Facility Additional Permitted Increase			$ 390,000,000
Line of Credit Facility, Number of Business Days Notice Required for Repayment of Debt Without Penalty			3 days
Letter of Credit [Member] | Drawn Portion [Member]
Line of Credit Facility [Line Items]
Long-term Line of Credit			$ 0
Letter of Credit [Member] | Base Rate [Member] | Drawn Portion [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			2.00%
LC Loan [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Term			1 year
Swing Line Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Minimum Period For Termination Date, Number of Business Days			3 days
Swing Line Loan [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Term			15 days
Working Capital Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Annual Temporary Requirement, Balance, Outstanding Principal			$ 0
Line of Credit Facility, Annual Temporary Requirement, Period, Number of Consecutive Business Days			5 days
2020 Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	[1]	1,200,000,000
Outstanding balance	[1]	0
Letters of credit issued	[1]	413,000,000
Available commitment	[1]	$ 787,000,000
Debt Instrument, Description of Variable Rate Basis		LIBOR or base rate
Debt Instrument, Maturity Date	[1]	Mar. 19, 2025
2020 Working Capital Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage		0.10%
2020 Working Capital Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]	1.125%
2020 Working Capital Facility [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.125%
2020 Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage		0.30%
2020 Working Capital Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1]	1.75%
2020 Working Capital Facility [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
[1]	The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. We pay a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on our then-current rating), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

Debt - Interest Expense (Detail

Debt - Interest Expense (Details) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Total interest cost	$ 589	$ 593	$ 790	$ 791	$ 779
Capitalized interest	(66)	(69)	(85)	(202)	(285)
Total interest expense, net	$ 523	$ 524	$ 705	$ 589	$ 494

Debt - Schedule of Carrying Val

Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value		$ 13,514	$ 13,524	$ 13,500
Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[1]		12,850	12,850
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[2]	12,850	12,850
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[3]	800	800
Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]		14,050	13,235
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	14,441	14,050
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[3]	946	934
2037 Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[4]		800	800
2037 Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[4]		934	$ 817
Working Capital Facility [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[5]	0	0
Working Capital Facility [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[5]	$ 0	$ 0
[1]	Includes 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 Senior Notes. 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 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
[3]	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.
[4]	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.
[5]	The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

Revenues from Contracts with _3

Revenues from Contracts with Customers - Narrative (Details)	9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	37.00%	53.00%	52.00%	57.00%
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage			100.00%	100.00%

Revenues from Contracts with _4

Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	9 Months Ended				12 Months Ended
	Sep. 30, 2020		Sep. 30, 2019		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 3,937		$ 4,693		$ 6,522		$ 6,127		$ 4,024
Net derivative gains	3	[1]	2	[1]	1	[2]	(1)	[2]	0	[2]
Revenues	3,940		4,695		6,523		6,126		4,024
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,585	[3]	3,676	[3]	5,210		4,828		2,635
Revenues	3,588		3,678		5,211		4,827		2,635
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	352		1,017		1,312		1,299		1,389
Revenues	352		$ 1,017		$ 1,312		$ 1,299		$ 1,389
Suspension Fees And LNG Cover Damages Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	513
Suspension Fees And LNG Cover Damages Revenue [Member] | Subsequent Period [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 21
[1]	See Note 6—Derivative Instruments for additional information about our derivatives.
[2]	See Note 7—Derivative Instruments for additional information about our derivatives.
[3]	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. LNG revenues during the nine months ended September 30, 2020 included $513 million in revenues associated with LNG cargoes for which customers have notified us that they will not take delivery, of which $21 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

Revenues from Contracts with _5

Revenues from Contracts with Customers - Schedule of Deferred Revenue Reconciliation (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019	Dec. 31, 2018
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	$ 132	$ 91	$ 84
Cash received but not yet recognized	157	132	91
Revenue recognized from prior period deferral	(132)	(91)	(84)
Deferred revenues, end of period	$ 157	$ 132	$ 91

Revenues from Contracts with _6

Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - LNG [Member] - USD ($) $ in Billions		Sep. 30, 2020	Dec. 31, 2019		Dec. 31, 2018	[1]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 55		$ 53.6
Weighted Average Recognition Timing	[2]		10 years		10 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 52.9	$ 55	[1]
Weighted Average Recognition Timing	[2]	9 years	10 years	[1]
[1]	Includes future consideration from agreement contractually assigned to us from Cheniere Marketing.
[2]	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	9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 352	$ 1,017	$ 1,312	$ 1,299	$ 1,389
Cost of sales—affiliate	60	35	47	32	23
Operating and maintenance expense—affiliate	352	335	450	423	329
General and administrative expense—affiliate	54	64	79	50	58
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	328	1,015	1,309	1,299	1,389
Cost of sales—affiliate	32	0
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	24	2	3	0	0
Cost of sales—affiliate	5	6	7	0	0
Terminal Use Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—affiliate	23	29	40	32	23
Operating and maintenance expense—affiliate	200	196	261	256	190
Natural Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	61	60	81	80	73
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	90	78	107	87	65
General and administrative expense—affiliate	54	64	79	50	58
LNG Site Sublease Agreement [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	$ 1	$ 1	$ 1	$ 0	$ 1

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) MMBTU in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2020USD ($)bcfPerDcargoitem	Sep. 30, 2019USD ($)	Dec. 31, 2019USD ($)bcfPerDBcfMMBTUitemcargo	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate	$ 83,000,000		$ 104,000,000	$ 113,000,000
Regasification Capacity | Bcf			2
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
Advances to affiliate	98,000,000		$ 133,000,000	210,000,000
Due to affiliates	46,000,000		49,000,000	48,000,000
Accrued Liabilities Related Party	$ 2,000,000		$ 0
Terminal Use Agreement [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Regasification Capacity | bcfPerD	2		2
Related Party Transaction, Committed Annual Fee	$ 250,000,000		$ 250
LNG Sale and Purchase Agreement [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
LNG Volume, Purchase Price			$ 3
2019 Letter Agreement [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
Contract Volumes | MMBTU			70
LNG Volume, Purchase Price Percentage of Henry Hub			115.00%
LNG Volume, Purchase Price			$ 2
2019 Letter Agreement [Member] | Cheniere Marketing [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | cargo			20
2020 Letter Agreement [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%		115.00%
LNG Volume, Purchase Price	$ 1.67		$ 1.67
2020 Letter Agreement [Member] | Cheniere Marketing [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | cargo	43		43
Cheniere Marketing SPA [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price	$ 3
Facility Swap Agreement [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
Natural Gas Transportation Agreement [Member] | CTPL [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term	20 years		20 years
Related Party Agreement, Termination Notice Period	1 year		1 year
Related Party Agreement, Number Of Available Extensions | item	2		2
Related Party Agreement, Term Of Available Extension	10 years		10 years
Due to affiliates	$ 7,000,000		$ 7,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to affiliate	$ 98,000,000		$ 133,000,000	210,000,000
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	0.60%		0.60%
Related Party Transaction, Committed Monthly Fee	$ 83,333		$ 83,333
Management Services Agreement [Member] | Cheniere Terminals [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	2.40%		2.40%
Related Party Transaction, Committed Monthly Fee	$ 541,667		$ 541,667
LNG Site Sublease Agreement [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Annual Sublease Payment	$ 1,000,000		$ 1,000,000
Term of available extension	10 years		10 years
Review Period for Inflation Adjustment	5 years		5 years
Cooperation Agreement [Member] | SPLNG [Member]
Related Party Transaction [Line Items]
Assets conveyed under the agreement	$ 5,000,000	$ 0	$ 351,000,000	$ 0	$ 0
Tax Sharing Agreement [Member] | Cheniere [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0		$ 0
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term	10 years
Accrued Liabilities Related Party	$ 2,000,000
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term	5 years

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)tbtuBcfitem
Commitments and Contingencies [Line Items]
Energy Units Secured Through Natural Gas Supply Contracts | tbtu	3,850
Regasification Capacity | Bcf	2
Loss Contingency, Pending Claims, Number | item	0
Bechtel EPC Contract, Train 6 [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Amount	$ 2,500
Long-term Purchase Commitment, Amount Incurred To Date	1,100
Bechtel EPC Contract, Train 6 [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Contract termination convenience penalty	$ 30
Natural Gas Supply Agreement [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	10 years
Transportation Agreement [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	20 years
Storage Service Agreement [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	10 years

Commitments and Contingencies_2

Commitments and Contingencies - Purchase Obligations Table (Details) - Natural Gas Supply, Transportation And Storage Service Agreements [Member] $ in Millions	Dec. 31, 2019USD ($)	[1]
Long-term Purchase Commitment [Line Items]
2020	$ 2,329
2021	1,416
2022	931
2023	722
2024	401
Thereafter	2,871
Total	$ 8,670
[1]	Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2019. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

Customer Concentration (Details

Customer Concentration (Details)	9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	23.00%	30.00%	29.00%	30.00%	43.00%
Customer A [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%		22.00%	35.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%	20.00%	19.00%	23.00%	30.00%
Customer B [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	21.00%		13.00%	23.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%	21.00%	21.00%	24.00%	25.00%
Customer C [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%		22.00%	30.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%	23.00%	21.00%	20.00%	0.00%
Customer D [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	34.00%		13.00%
Customer E [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage				0.00%	0.00%
Customer E [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%		13.00%	0.00%
Customer F [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%			0.00%	0.00%
Customer F [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%		14.00%	0.00%

Customer Concentration - Schedu

Customer Concentration - Schedule of Revenues from External Customers by Country (Details) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Revenues from External Customers	$ 3,940	$ 4,695	$ 6,523	$ 6,126	$ 4,024
Geographic Concentration Risk [Member]
Concentration Risk [Line Items]
Revenues from External Customers			5,211	4,827	2,635
Geographic Concentration Risk [Member] | United States
Concentration Risk [Line Items]
Revenues from External Customers			2,039	1,580	1,161
Geographic Concentration Risk [Member] | India
Concentration Risk [Line Items]
Revenues from External Customers			1,113	981	0
Geographic Concentration Risk [Member] | South Korea
Concentration Risk [Line Items]
Revenues from External Customers			1,071	1,168	666
Geographic Concentration Risk [Member] | Ireland
Concentration Risk [Line Items]
Revenues from External Customers			988	1,098	787
Geographic Concentration Risk [Member] | Other countries
Concentration Risk [Line Items]
Revenues from External Customers			$ 0	$ 0	$ 21

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 527	$ 542	$ 678	$ 604	$ 438
Non-cash distributions to affiliates for conveyance of assets	5	348	351	0	0
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 217	$ 287	$ 276	$ 256	$ 268