Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2018USD ($)shares | |
Document and Entity Information [Abstract] | |
Entity Registrant Name | Sabine Pass Liquefaction, LLC |
Entity Central Index Key | 1,499,200 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Non-accelerated Filer |
Document Type | 10-K |
Document Period End Date | Dec. 31, 2018 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Entity Small Business | false |
Entity Emerging Growth Company | false |
Entity Common Stock, Shares Outstanding | shares | 0 |
Entity Well-known Seasoned Issuer | No |
Entity Voluntary Filers | Yes |
Entity Current Reporting Status | No |
Entity Shell Company | false |
Entity Public Float | $ | $ 0 |
Balance Sheets
Balance Sheets - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents | $ 0 | $ 0 |
Restricted cash | 756 | 544 |
Accounts and other receivables | 346 | 189 |
Accounts receivable—affiliate | 113 | 163 |
Advances to affiliate | 210 | 26 |
Inventory | 87 | 85 |
Other current assets | 24 | 54 |
Other current assets—affiliate | 21 | 21 |
Total current assets | 1,557 | 1,082 |
Property, plant and equipment, net | 13,209 | 12,920 |
Debt issuance costs, net | 12 | 18 |
Non-current derivative assets | 31 | 17 |
Other non-current assets, net | 158 | 169 |
Total assets | 14,967 | 14,206 |
Current liabilities | ||
Accounts payable | 11 | 8 |
Accrued liabilities | 768 | 606 |
Due to affiliates | 48 | 66 |
Deferred revenue | 91 | 84 |
Derivative liabilities | 66 | 0 |
Total current liabilities | 984 | 764 |
Long-term debt, net | 13,500 | 13,477 |
Non-current derivative liabilities | 14 | 3 |
Other non-current liabilities | 3 | 0 |
Commitments and contingencies (see Note 14) | ||
Member’s equity (deficit) | 466 | (38) |
Total liabilities and member’s equity (deficit) | $ 14,967 | $ 14,206 |
Statements of Operations
Statements of Operations - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues | |||
Revenue earned from contracts with customers | $ 5,986 | $ 4,004 | $ 829 |
Revenues | 6,126 | 4,024 | 833 |
Operating costs and expenses | |||
Cost of sales (excluding depreciation and amortization expense shown separately below) | 3,403 | 2,317 | 416 |
Cost of sales—affiliate | 32 | 23 | 7 |
Operating and maintenance expense | 342 | 243 | 72 |
Operating and maintenance expense—affiliate | 423 | 329 | 129 |
Development expense | 2 | 2 | 0 |
Development expense—affiliate | 0 | 0 | 1 |
General and administrative expense | 5 | 7 | 7 |
General and administrative expense—affiliate | 50 | 58 | 68 |
Depreciation and amortization expense | 349 | 264 | 83 |
Total operating costs and expenses | 4,606 | 3,243 | 783 |
Income from operations | 1,520 | 781 | 50 |
Other income (expense) | |||
Interest expense, net of capitalized interest | (589) | (494) | (186) |
Loss on modification or extinguishment of debt | 0 | (42) | (52) |
Derivative loss, net | 0 | (2) | (6) |
Other income | 13 | 7 | 1 |
Total other expense | (576) | (531) | (243) |
Net income (loss) | 944 | 250 | (193) |
LNG [Member] | |||
Revenues | |||
Revenue earned from contracts with customers | 4,687 | 2,615 | 535 |
Revenues | 4,827 | 2,635 | 539 |
LNG—affiliate [Member] | |||
Revenues | |||
Revenue earned from contracts with customers | $ 1,299 | $ 1,389 | $ 294 |
Statements of Member's Equity (
Statements of Member's Equity (Deficit) - USD ($) $ in Millions | Total | Sabine Pass LNG-LP, LLC [Member] |
Members' equity, beginning of period at Dec. 31, 2015 | $ 931 | $ 931 |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||
Capital contributions | 1 | 1 |
Distributions | (253) | (253) |
Net income (loss) | (193) | (193) |
Member's equity, end 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 |
Statements of Cash Flows
Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities | |||
Net income (loss) | $ 944 | $ 250 | $ (193) |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||
Depreciation and amortization expense | 349 | 264 | 83 |
Amortization of debt issuance costs, deferred commitment fees, premium and discount | 22 | 19 | 12 |
Loss on modification or extinguishment of debt | 0 | 42 | 52 |
Total losses (gains) on derivatives, net | 101 | 26 | (36) |
Net cash used for settlement of derivative instruments | (3) | (14) | (7) |
Changes in operating assets and liabilities: | |||
Accounts and other receivables | (122) | (99) | (90) |
Accounts receivable—affiliate | 49 | (63) | (99) |
Advances to affiliate | (76) | (13) | 1 |
Inventory | (3) | 11 | (60) |
Accounts payable and accrued liabilities | 165 | 190 | 179 |
Due to affiliates | (6) | 22 | 1 |
Deferred revenue | 7 | 38 | 46 |
Other, net | (4) | (4) | (10) |
Other, net—affiliate | 0 | (12) | (9) |
Net cash provided by (used in) operating activities | 1,423 | 657 | (130) |
Cash flows from investing activities | |||
Property, plant and equipment, net | (771) | (1,279) | (2,306) |
Other | 0 | 0 | (32) |
Net cash used in investing activities | (771) | (1,279) | (2,338) |
Cash flows from financing activities | |||
Proceeds from issuances of debt | 0 | 2,314 | 5,443 |
Repayments of debt | 0 | (703) | (2,765) |
Debt issuance and deferred financing costs | 0 | (29) | (42) |
Capital contributions | 129 | 7 | 1 |
Distributions | (569) | (781) | 0 |
Net cash provided by (used in) financing activities | (440) | 808 | 2,637 |
Net increase in cash, cash equivalents and restricted cash | 212 | 186 | 169 |
Cash, cash equivalents and restricted cash—beginning of period | 544 | 358 | 189 |
Cash, cash equivalents and restricted cash—end of period | $ 756 | $ 544 | $ 358 |
Statements of Cash Flows - Bala
Statements of Cash Flows - Balances per Balance Sheets - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Balances per Balance Sheets: | ||||
Cash and cash equivalents | $ 0 | $ 0 | ||
Restricted cash | 756 | 544 | ||
Total cash, cash equivalents and restricted cash | $ 756 | $ 544 | $ 358 | $ 189 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | ORGANIZATION AND NATURE OF OPERATIONS We are a Delaware limited liability company formed by Cheniere Partners to develop, construct and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities owned and operated by SPLNG. We are a Houston-based company with one member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of Cheniere Partners. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of Cheniere Partners, a publicly traded limited partnership (NYSE MKT: CQP). Cheniere Partners is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses. Our Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal, which is located on the Sabine-Neches Waterway less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is undergoing commissioning and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG per Train, and run rate adjusted nominal production capacity of approximately 4.5 to 4.9 mtpa of LNG per Train. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Our Financial Statements have been prepared in accordance with GAAP . 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. On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying Financial Statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported Financial Statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. 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 the recoverability of property, plant and equipment, derivative instruments, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Fair Value 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 other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. 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 assets and liabilities initially measured at fair value include intangible assets and AROs. 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 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 allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses. The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral. We did no t recognize any impairment expense related to accounts receivable during the years ended December 31, 2018, 2017 and 2016 . 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 front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train. Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed. 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. We did no t recognize any impairment expense related to property, plant and equipment during the years ended December 31, 2018, 2017 and 2016 , respectively. Interest Capitalization We capitalize interest and other related debt costs during the construction period of our LNG terminals and related pipelines as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset. Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. 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, including completing contemporaneous hedge documentation. We did no t have any derivative instruments designated as cash flow hedges during the years ended December 31, 2018, 2017 and 2016 . 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 and restricted cash. 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 contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments. We have entered into fixed price SPAs with terms of at least 20 years with seven unaffiliated third parties. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration. Debt Our debt consists of current and long-term secured 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. 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 of debt are recorded in gain (loss) on modification or extinguishment of debt on our Statements of Operations. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Balance Sheets. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on modification or extinguishment of debt. 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 no t recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial. Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss 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. At December 31, 2018 , the tax basis of our assets and liabilities was $2.6 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 reportable segment. Our chief operating decision maker reviews the financial results of SPL in total when evaluating financial performance and for purposes of allocating resources. |
Restricted Cash
Restricted Cash | 12 Months Ended |
Dec. 31, 2018 | |
Restricted Cash [Abstract] | |
Restricted Cash | RESTRICTED CASH Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. As of December 31, 2018 and 2017 , restricted cash consisted of the following (in millions): December 31, 2018 2017 Current restricted cash Liquefaction Project $ 756 $ 544 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 | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Accounts and Other Receivables | ACCOUNTS AND OTHER RECEIVABLES As of December 31, 2018 and 2017 , accounts and other receivables consisted of the following (in millions): December 31, 2018 2017 Trade receivable $ 330 $ 185 Other accounts receivable 16 4 Total accounts and other receivables $ 346 $ 189 |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2018 | |
Inventory Disclosure [Abstract] | |
Inventory | INVENTORY As of December 31, 2018 and 2017 , inventory consisted of the following (in millions): December 31, 2018 2017 Natural gas $ 28 $ 17 LNG 6 26 Materials and other 53 42 Total inventory $ 87 $ 85 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT As of December 31, 2018 and 2017 , property, plant and equipment, net consisted of the following (in millions): December 31, 2018 2017 LNG terminal costs LNG terminal $ 10,004 $ 9,963 LNG terminal construction-in-process 3,866 3,283 Accumulated depreciation (667 ) (330 ) Total LNG terminal costs, net 13,203 12,916 Fixed assets Fixed assets 14 10 Accumulated depreciation (8 ) (6 ) Total fixed assets, net 6 4 Property, plant and equipment, net $ 13,209 $ 12,920 Depreciation expense was $339 million , $257 million and $77 million during the years ended December 31, 2018, 2017 and 2016 , respectively. We realized offsets to LNG terminal costs of $94 million , $301 million and $201 million in the years ended December 31, 2018, 2017 and 2016 , 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 Train of the Liquefaction Project , during the testing phase for its construction. LNG Terminal Costs LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows: Components Useful life (yrs) Water pipelines 30 Liquefaction processing equipment 6-50 Other 15-30 Fixed Assets and Other Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | DERIVATIVE INSTRUMENTS We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”) . We 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 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 December 31, 2018 and 2017 , which are classified as other current assets , non-current derivative assets , derivative liabilities or non-current derivative liabilities in our Balance Sheets (in millions). Fair Value Measurements as of December 31, 2018 December 31, 2017 Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Liquefaction Supply Derivatives asset (liability) $ 5 $ (23 ) $ (25 ) $ (43 ) $ 2 $ 10 $ 43 $ 55 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 market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts. 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 may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2018 : Net Fair Value Liability (in millions) Valuation Approach Significant Unobservable Input Significant Unobservable Inputs Range Physical Liquefaction Supply Derivatives $(25) Market approach incorporating present value techniques Basis Spread $(0.892) - $0.085 The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, 2018 2017 2016 Balance, beginning of period $ 43 $ 79 $ 32 Realized and mark-to-market gains (losses): Included in cost of sales (1) (3 ) (37 ) 48 Purchases and settlements: Purchases (37 ) 14 1 Settlements (1) (29 ) (12 ) (2 ) Transfers out of Level 3 (2) 1 (1 ) — Balance, end of period $ (25 ) $ 43 $ 79 Change in unrealized gains (losses) relating to instruments still held at end of period $ (3 ) $ (37 ) $ 49 (1) Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016. (2) 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 net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default. Interest Rate Derivatives We had entered into Interest Rate Derivatives 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 “Credit Facilities”) , based on a portion of the expected outstanding borrowings over the term of the Credit Facilities. In March 2017, we settled the Interest Rate Derivatives and paid $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the Credit Facilities . 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 Operations during the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, 2018 2017 2016 Interest Rate Derivatives loss $ — $ (2 ) $ (6 ) 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 terms of the physical natural gas supply contracts range up to six years, some of which commence upon the satisfaction of certain conditions precedent. Our Financial Liquefaction Supply Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our Financial Liquefaction Supply Derivatives activities. We had secured up to approximately 3,464 TBtu and 2,214 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2018 and 2017 , respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 2,978 TBtu and 1,520 TBtu as of December 31, 2018 and 2017 , 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, 2018 December 31, 2017 Other current assets $ 6 $ 41 Non-current derivative assets 31 17 Total derivative assets 37 58 Derivative liabilities (66 ) — Non-current derivative liabilities (14 ) (3 ) Total derivative liabilities (80 ) (3 ) Derivative asset (liability), net $ (43 ) $ 55 (1) Does not include collateral calls of $1 million for such contracts, which are included in other current assets in our Balance Sheets as of both December 31, 2018 and 2017 . The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives on our Statements of Operations during the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, Statement of Operations Location (1) 2018 2017 2016 Liquefaction Supply Derivatives loss LNG revenues $ (1 ) $ — $ — Liquefaction Supply Derivatives gain (loss) Cost of sales (100 ) (24 ) 42 (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): Gross Amounts Recognized Gross Amounts Offset in the Balance Sheets Net Amounts Presented in the Balance Sheets Offsetting Derivative Assets (Liabilities) As of December 31, 2018 Liquefaction Supply Derivatives $ 63 $ (26 ) $ 37 Liquefaction Supply Derivatives (92 ) 12 (80 ) As of December 31, 2017 Liquefaction Supply Derivatives $ 64 $ (6 ) $ 58 Liquefaction Supply Derivatives (3 ) — (3 ) |
Other Non-Current Assets
Other Non-Current Assets | 12 Months Ended |
Dec. 31, 2018 | |
Other Assets, Noncurrent [Abstract] | |
Other Non-Current Assets | OTHER NON-CURRENT ASSETS As of December 31, 2018 and 2017 , other non-current assets, net consisted of the following (in millions): December 31, 2018 2017 Advances made under EPC and non-EPC contracts $ 14 $ 26 Advances made to municipalities for water system enhancements 90 93 Advances and other asset conveyances to third parties to support LNG terminals 36 30 Tax-related payments and receivables — 1 Information technology service assets 16 19 Other 2 — Total other non-current assets, net $ 158 $ 169 |
Accrued Liabilities
Accrued Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Accrued Liabilities, Current [Abstract] | |
Accrued Liabilities | ACCRUED LIABILITIES As of December 31, 2018 and 2017 , accrued liabilities consisted of the following (in millions): December 31, 2018 2017 Interest costs and related debt fees $ 186 $ 230 Accrued natural gas purchases 518 298 Liquefaction Project costs 64 78 Total accrued liabilities $ 768 $ 606 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt | DEBT As of December 31, 2018 and 2017 , our debt consisted of the following (in millions): December 31, 2018 2017 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 (150 ) (173 ) Total long-term debt, net 13,500 13,477 Current debt $1.2 billion Working Capital Facility (“Working Capital Facility”) — — Total debt, net $ 13,500 $ 13,477 Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2018 (in millions): Years Ending December 31, Principal Payments 2019 $ — 2020 — 2021 2,000 2022 1,000 2023 1,500 Thereafter 9,150 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 first-priority basis by a security interest in all of the membership interests in us and substantially all of our assets. We may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25 :1.00 is satisfied. Semi-annual principal payments for the 2037 Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. As of December 31, 2018 , we were in compliance with all covenants related to the Senior Notes . Interest on the Senior Notes is payable semi-annually in arrears. 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, 2018 (in millions): Working Capital Facility Original facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 425 Available commitment $ 775 Interest rate LIBOR plus 1.75% or base rate plus 0.75% Maturity date December 31, 2020, with various terms for underlying loans In September 2015, we entered into the Working Capital Facility , which is intended to be used for loans (the “Working Capital Facility”) , 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, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase 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, 2018 , no LC Draw s 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 business days’ notice. LC Loans have a term of up to one year. Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the Working Capital Facility , (2) the date 15 days after such Swing Line Loan is made and (3) the first borrowing date for a Working Capital Loan or Swing Line Loan occurring at least three business days following the date the Swing Line Loan is made. We are required to reduce the aggregate outstanding principal amount of all Working Capital Loans to zero for a period of five consecutive business days at least once each year. The Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. As of December 31, 2018 , we were in compliance with all covenants related to the Working Capital Facility . 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 basis with the Senior Notes . Interest Expense Total interest expense consisted of the following (in millions): Year Ended December 31, 2018 2017 2016 Total interest cost $ 791 $ 779 $ 649 Capitalized interest (202 ) (285 ) (463 ) Total interest expense, net $ 589 $ 494 $ 186 Fair Value Disclosures The following table shows the carrying amount, which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in millions): December 31, 2018 December 31, 2017 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior notes (1) $ 12,709 $ 13,235 $ 12,687 $ 13,955 2037 Senior Notes (2) 791 817 790 871 (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 | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenues from Contracts with Customers | REVENUES FROM CONTRACTS WITH CUSTOMERS The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, 2018 2017 2016 LNG revenues $ 4,687 $ 2,615 $ 535 LNG revenues—affiliate 1,299 1,389 294 Total revenues from customers 5,986 4,004 829 Gains from derivative instruments (1) 140 20 4 Total revenues $ 6,126 $ 4,024 $ 833 (1) Includes the realized value associated with a portion of derivative instruments that settle through physical delivery. 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. 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 sale 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 revenues on our Balance Sheets (in millions): Year Ended December 31, 2018 2017 Deferred revenues, beginning of period $ 84 $ 46 Cash received but not yet recognized 91 84 Revenue recognized from prior period deferral (84 ) (46 ) Deferred revenues, end of period $ 91 $ 84 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, 2018 and 2017 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, 2018 and 2017 : December 31, 2018 December 31, 2017 Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Weighted Average Recognition Timing (years) (1) LNG revenues $ 53.6 10 $ 55.7 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 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 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. Approximately 57% and 58% of our LNG revenues were related to variable consideration received from customers during the years ended December 31, 2018 and 2017 , respectively. All of our LNG revenues—affiliate were related to variable consideration received from customers during each of the years ended December 31, 2018 and 2017 . 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 | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS Below is a summary of our related party transactions as reported on our Statements of Operations for the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, 2018 2017 2016 LNG revenues—affiliate Cheniere Marketing SPA and Cheniere Marketing Master SPA $ 1,299 $ 1,389 $ 294 Cost of sales—affiliate Cargo loading fees under TUA 32 23 5 Fees under the Pre-commercial LNG Marketing Agreement — — 2 Total cost of sales—affiliate 32 23 7 Operating and maintenance expense—affiliate TUA 256 190 61 Natural Gas Transportation Agreement 80 73 45 Services Agreements 87 65 22 LNG Site Sublease Agreement — 1 1 Total operating and maintenance expense—affiliate 423 329 129 Development expense—affiliate Services Agreements — — 1 General and administrative expense—affiliate Services Agreements 50 58 68 LNG Terminal-Related Agreements As of December 31, 2018 and 2017 , we had $113 million and $163 million of accounts receivable—affiliate, respectively, under the agreements described below. 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 2.0 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 . In connection with the assignment, we, Cheniere Investments and SPLNG also entered into a terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use our reserved capacity under the TUA and had the obligation to pay the TUA Fees required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal and its respective percentage of TUA Fees payable was reduced from 100% to zero as each of Trains 1 through 4 reached commercial operations. Cheniere Partners has guaranteed our obligations under our TUA and the obligations of Cheniere Investments under the TURA . 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 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. Cheniere Marketing SPA Cheniere Marketing has an 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 . 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 obligates Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) has control of, and is commissioning, Train 5 of the Liquefaction Project. 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 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 of 20 years from commercial operation of Train 2 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 ten -year terms. 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, 2018 and 2017 , we had $210 million and $26 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate. 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 management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our behalf and providing contract administration services for all contracts associated with the Liquefaction Project . Prior to the substantial completion of each Train of the Liquefaction Project , we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train. Cheniere Investments Information Technology Services Agreement Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investment’s 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. 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 10 -year extensions 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. Under this agreement, we conveyed to SPLNG $253 million of assets for the year ended December 31, 2016 which were recorded as non-cash distributions to affiliates. We did no t 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 that allow us to sell and purchase natural gas and LNG with SPLNG. Natural gas and LNG purchased under these agreements are recorded as inventory, 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. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2018 | |
Leases [Abstract] | |
Leases | LEASES During the years ended December 31, 2018, 2017 and 2016 , we recognized rental expense for all operating leases of $5 million , $3 million and $2 million , respectively, related primarily to land sites for the Liquefaction Project. We have an agreement with SPLNG to sublease a portion of its Sabine Pass LNG terminal site for the Liquefaction Project. See Note 12—Related Party Transactions for additional information regarding this sublease agreement. Future annual minimum lease payments, excluding inflationary adjustments and payments to affiliates, are as follows (in millions): Years ending December 31, Operating Leases (1) 2019 through 2023 $ 2 Thereafter 7 Total $ 9 (1) Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components . |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2018 , are not recognized as liabilities but require disclosures in our Financial Statements. LNG Terminal Commitments and Contingencies Obligations under EPC Contract We have lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Train 5 and Train 6 of the Liquefaction Project. The EPC contract prices for Train 5 of the Liquefaction Project and Train 6 of the Liquefaction Project are approximately $3.1 billion and $2.5 billion , respectively, reflecting amounts incurred under change orders through December 31, 2018 , including estimated costs for an optional third marine berth. We have the right to terminate the EPC contracts 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 index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The terms of these contracts range up to six years, some of which commence upon the satisfaction of certain conditions precedent. As of December 31, 2018 , we have secured up to approximately 3,464 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent are met. Additionally, we have transportation and storage service agreements for the Liquefaction Project. The initial term of the transportation agreements ranges up to 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The terms of our storage service agreements range up to ten years. As of December 31, 2018 , 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 Due (1) 2019 $ 2,465 2020 1,377 2021 1,010 2022 756 2023 641 Thereafter 1,652 Total $ 7,901 (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread . Amounts included are based on prices and basis spreads as of December 31, 2018 . Obligations under LNG TUAs We have a TUA with SPLNG pursuant to which we have reserved approximately 2.0 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 3, we gained access to a portion of Total ’s capacity and other services provided under Total ’s TUA with SPLNG. Upon substantial completion of Train 5, we will gain access to substantially all of Total ’s capacity. 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 Trains 5 and 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. State Tax Sharing Agreement We have a state tax sharing agreement with Cheniere. See Note 12—Related Party Transactions for additional information regarding this agreement. Other Commitments 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. Additionally, we have various lease commitments, as disclosed in Note 13—Leases . 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, 2018 , there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows. |
Customer Concentration
Customer Concentration | 12 Months Ended |
Dec. 31, 2018 | |
Risks and Uncertainties [Abstract] | |
Customer Concentration | 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 from External Customers Percentage of Accounts Receivable from External Customers Year Ended December 31, December 31, 2018 2017 2016 2018 2017 Customer A 30% 43% 77% 35% 39% Customer B 23% 30% * 23% 32% Customer C 24% 25% —% 30% 27% Customer D 20% —% —% * —% * 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, 2018 2017 2016 United States $ 1,580 $ 1,161 $ 414 South Korea 1,168 666 — Ireland 1,098 787 63 India 981 — 23 Other countries — 21 39 Total $ 4,827 $ 2,635 $ 539 |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | SUPPLEMENTAL CASH FLOW INFORMATION The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2018 2017 2016 Cash paid during the period for interest, net of amounts capitalized $ 604 $ 438 $ 75 Non-cash distributions to affiliates for conveyance of assets — — 253 The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $256 million , $268 million and $263 million , as of December 31, 2018 , 2017 and 2016, respectively. |
Recent Accounting Standards
Recent Accounting Standards | 12 Months Ended |
Dec. 31, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recent Accounting Standards | RECENT ACCOUNTING STANDARDS The following table provides a brief description of a recent accounting standard that had not been adopted by us as of December 31, 2018 : Standard Description Expected Date of Adoption Effect on our Financial Statements or Other Significant Matters ASU 2016-02, Leases (Topic 842) , and subsequent amendments thereto This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available. January 1, 2019 We will adopt this standard on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard will not have a material impact on our Financial Statements but will result in additional disclosures including the significant judgments and assumptions used in applying the standard. Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period: Standard Description Date of Adoption Effect on our Financial Statements or Other Significant Matters ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , and subsequent amendments thereto This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”). January 1, 2018 We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported Financial Statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 11—Revenues from Contracts with Customers for additional disclosures. ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach. January 1, 2018 The adoption of this guidance did not have an impact on our Financial Statements or related disclosures. |
Summarized Quarterly Financial
Summarized Quarterly Financial Data (unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data (unaudited) | Summarized Quarterly Financial Data—(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2018: Revenues $ 1,518 $ 1,333 $ 1,454 $ 1,821 Income from operations 391 339 384 406 Net income 242 193 243 266 Year ended December 31, 2017: Revenues $ 823 $ 925 $ 834 $ 1,442 Income from operations 145 105 109 422 Net income (loss) (4 ) (20 ) (12 ) 286 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Basis of Presentation, Policy | 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. On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying Financial Statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported Financial Statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. |
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 the recoverability of property, plant and equipment, derivative instruments, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. |
Fair Value, Policy | Fair Value 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 other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. 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 assets and liabilities initially measured at fair value include intangible assets and AROs. |
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 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 allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses. The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral. We did no t recognize any impairment expense related to accounts receivable during the years ended December 31, 2018, 2017 and 2016 . |
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 front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train. Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed. |
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. We did no t recognize any impairment expense related to property, plant and equipment during the years ended December 31, 2018, 2017 and 2016 , respectively. |
Interest Capitalization, Policy | Interest Capitalization We capitalize interest and other related debt costs during the construction period of our LNG terminals and related pipelines as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset. |
Derivative Instruments, Policy | Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. 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, including completing contemporaneous hedge documentation. We did no t have any derivative instruments designated as cash flow hedges during the years ended December 31, 2018, 2017 and 2016 . See Note 7—Derivative Instruments for additional details about our derivative instruments. |
Concentration of Credit Risk, Policy | Concentration of Credit Risk Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. 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 contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments. We have entered into fixed price SPAs with terms of at least 20 years with seven unaffiliated third parties. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration. |
Debt, Policy | Debt Our debt consists of current and long-term secured 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. 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 of debt are recorded in gain (loss) on modification or extinguishment of debt on our Statements of Operations. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Balance Sheets. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on modification or extinguishment of debt. |
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 no t recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial. |
Income Taxes, Policy | 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 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. At December 31, 2018 , the tax basis of our assets and liabilities was $2.6 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 reportable segment. Our chief operating decision maker reviews the financial results of SPL in total when evaluating financial performance and for purposes of allocating resources. |
Restricted Cash (Tables)
Restricted Cash (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Restricted Cash [Abstract] | |
Schedule of Restricted Cash | As of December 31, 2018 and 2017 , restricted cash consisted of the following (in millions): December 31, 2018 2017 Current restricted cash Liquefaction Project $ 756 $ 544 |
Accounts and Other Receivables
Accounts and Other Receivables (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Schedule of Accounts and Other Receivables | As of December 31, 2018 and 2017 , accounts and other receivables consisted of the following (in millions): December 31, 2018 2017 Trade receivable $ 330 $ 185 Other accounts receivable 16 4 Total accounts and other receivables $ 346 $ 189 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Inventory Disclosure [Abstract] | |
Schedule of Inventory | As of December 31, 2018 and 2017 , inventory consisted of the following (in millions): December 31, 2018 2017 Natural gas $ 28 $ 17 LNG 6 26 Materials and other 53 42 Total inventory $ 87 $ 85 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | As of December 31, 2018 and 2017 , property, plant and equipment, net consisted of the following (in millions): December 31, 2018 2017 LNG terminal costs LNG terminal $ 10,004 $ 9,963 LNG terminal construction-in-process 3,866 3,283 Accumulated depreciation (667 ) (330 ) Total LNG terminal costs, net 13,203 12,916 Fixed assets Fixed assets 14 10 Accumulated depreciation (8 ) (6 ) Total fixed assets, net 6 4 Property, plant and equipment, net $ 13,209 $ 12,920 |
Property, Plant And Equipment, Estimated, Useful Lives Table | The identifiable components of the Liquefaction Project with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows: Components Useful life (yrs) Water pipelines 30 Liquefaction processing equipment 6-50 Other 15-30 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Fair Value of Derivative Assets and Liabilities | The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2018 and 2017 , which are classified as other current assets , non-current derivative assets , derivative liabilities or non-current derivative liabilities in our Balance Sheets (in millions). Fair Value Measurements as of December 31, 2018 December 31, 2017 Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Liquefaction Supply Derivatives asset (liability) $ 5 $ (23 ) $ (25 ) $ (43 ) $ 2 $ 10 $ 43 $ 55 |
Fair Value Measurement Inputs and Valuation Techniques | The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2018 : Net Fair Value Liability (in millions) Valuation Approach Significant Unobservable Input Significant Unobservable Inputs Range Physical Liquefaction Supply Derivatives $(25) Market approach incorporating present value techniques Basis Spread $(0.892) - $0.085 |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation | The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, 2018 2017 2016 Balance, beginning of period $ 43 $ 79 $ 32 Realized and mark-to-market gains (losses): Included in cost of sales (1) (3 ) (37 ) 48 Purchases and settlements: Purchases (37 ) 14 1 Settlements (1) (29 ) (12 ) (2 ) Transfers out of Level 3 (2) 1 (1 ) — Balance, end of period $ (25 ) $ 43 $ 79 Change in unrealized gains (losses) relating to instruments still held at end of period $ (3 ) $ (37 ) $ 49 (1) Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016. (2) Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements. |
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): Gross Amounts Recognized Gross Amounts Offset in the Balance Sheets Net Amounts Presented in the Balance Sheets Offsetting Derivative Assets (Liabilities) As of December 31, 2018 Liquefaction Supply Derivatives $ 63 $ (26 ) $ 37 Liquefaction Supply Derivatives (92 ) 12 (80 ) As of December 31, 2017 Liquefaction Supply Derivatives $ 64 $ (6 ) $ 58 Liquefaction Supply Derivatives (3 ) — (3 ) |
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 Operations during the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, 2018 2017 2016 Interest Rate Derivatives loss $ — $ (2 ) $ (6 ) |
Liquefaction Supply Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
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 Sheet Location December 31, 2018 December 31, 2017 Other current assets $ 6 $ 41 Non-current derivative assets 31 17 Total derivative assets 37 58 Derivative liabilities (66 ) — Non-current derivative liabilities (14 ) (3 ) Total derivative liabilities (80 ) (3 ) Derivative asset (liability), net $ (43 ) $ 55 (1) Does not include collateral calls of $1 million for such contracts, which are included in other current assets in our Balance Sheets as of both December 31, 2018 and 2017 . |
Derivative Instruments, Gain (Loss) | The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives on our Statements of Operations during the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, Statement of Operations Location (1) 2018 2017 2016 Liquefaction Supply Derivatives loss LNG revenues $ (1 ) $ — $ — Liquefaction Supply Derivatives gain (loss) Cost of sales (100 ) (24 ) 42 (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) | 12 Months Ended |
Dec. 31, 2018 | |
Other Assets, Noncurrent [Abstract] | |
Schedule of Other Non-Current Assets | As of December 31, 2018 and 2017 , other non-current assets, net consisted of the following (in millions): December 31, 2018 2017 Advances made under EPC and non-EPC contracts $ 14 $ 26 Advances made to municipalities for water system enhancements 90 93 Advances and other asset conveyances to third parties to support LNG terminals 36 30 Tax-related payments and receivables — 1 Information technology service assets 16 19 Other 2 — Total other non-current assets, net $ 158 $ 169 |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accrued Liabilities, Current [Abstract] | |
Schedule of Accrued Liabilities | As of December 31, 2018 and 2017 , accrued liabilities consisted of the following (in millions): December 31, 2018 2017 Interest costs and related debt fees $ 186 $ 230 Accrued natural gas purchases 518 298 Liquefaction Project costs 64 78 Total accrued liabilities $ 768 $ 606 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Debt Instruments | As of December 31, 2018 and 2017 , our debt consisted of the following (in millions): December 31, 2018 2017 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 (150 ) (173 ) Total long-term debt, net 13,500 13,477 Current debt $1.2 billion Working Capital Facility (“Working Capital Facility”) — — Total debt, net $ 13,500 $ 13,477 |
Schedule of Maturities of Long-term Debt | Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2018 (in millions): Years Ending December 31, Principal Payments 2019 $ — 2020 — 2021 2,000 2022 1,000 2023 1,500 Thereafter 9,150 Total $ 13,650 |
Schedule of Line of Credit Facilities | Below is a summary of our Working Capital Facility as of December 31, 2018 (in millions): Working Capital Facility Original facility size $ 1,200 Less: Outstanding balance — Letters of credit issued 425 Available commitment $ 775 Interest rate LIBOR plus 1.75% or base rate plus 0.75% Maturity date December 31, 2020, with various terms for underlying loans |
Schedule of Interest Expense | Total interest expense consisted of the following (in millions): Year Ended December 31, 2018 2017 2016 Total interest cost $ 791 $ 779 $ 649 Capitalized interest (202 ) (285 ) (463 ) Total interest expense, net $ 589 $ 494 $ 186 |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments | The following table shows the carrying amount, which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in millions): December 31, 2018 December 31, 2017 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior notes (1) $ 12,709 $ 13,235 $ 12,687 $ 13,955 2037 Senior Notes (2) 791 817 790 871 (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) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, 2018 2017 2016 LNG revenues $ 4,687 $ 2,615 $ 535 LNG revenues—affiliate 1,299 1,389 294 Total revenues from customers 5,986 4,004 829 Gains from derivative instruments (1) 140 20 4 Total revenues $ 6,126 $ 4,024 $ 833 (1) Includes the realized value associated with a portion of derivative instruments that settle through physical delivery. |
Contract Balances Reconciliation | The following table reflects the changes in our contract liabilities, which we classify as deferred revenues on our Balance Sheets (in millions): Year Ended December 31, 2018 2017 Deferred revenues, beginning of period $ 84 $ 46 Cash received but not yet recognized 91 84 Revenue recognized from prior period deferral (84 ) (46 ) Deferred revenues, end of period $ 91 $ 84 |
Transaction Price Allocated to Future Performance Obligations | The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2018 and 2017 : December 31, 2018 December 31, 2017 Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Weighted Average Recognition Timing (years) (1) LNG revenues $ 53.6 10 $ 55.7 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. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 years ended December 31, 2018, 2017 and 2016 (in millions): Year Ended December 31, 2018 2017 2016 LNG revenues—affiliate Cheniere Marketing SPA and Cheniere Marketing Master SPA $ 1,299 $ 1,389 $ 294 Cost of sales—affiliate Cargo loading fees under TUA 32 23 5 Fees under the Pre-commercial LNG Marketing Agreement — — 2 Total cost of sales—affiliate 32 23 7 Operating and maintenance expense—affiliate TUA 256 190 61 Natural Gas Transportation Agreement 80 73 45 Services Agreements 87 65 22 LNG Site Sublease Agreement — 1 1 Total operating and maintenance expense—affiliate 423 329 129 Development expense—affiliate Services Agreements — — 1 General and administrative expense—affiliate Services Agreements 50 58 68 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Leases [Abstract] | |
Schedule of Future Minimum Rental Payments for Operating Leases | Future annual minimum lease payments, excluding inflationary adjustments and payments to affiliates, are as follows (in millions): Years ending December 31, Operating Leases (1) 2019 through 2023 $ 2 Thereafter 7 Total $ 9 (1) Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components . |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Natural Gas Supply, Transportation And Storage Service Agreements [Member] | |
Long-term Purchase Commitment [Line Items] | |
Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block] | As of December 31, 2018 , 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 Due (1) 2019 $ 2,465 2020 1,377 2021 1,010 2022 756 2023 641 Thereafter 1,652 Total $ 7,901 (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread . Amounts included are based on prices and basis spreads as of December 31, 2018 . |
Customer Concentration (Tables)
Customer Concentration (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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 balances of 10% or greater of total accounts receivable from external customers: Percentage of Total Revenues from External Customers Percentage of Accounts Receivable from External Customers Year Ended December 31, December 31, 2018 2017 2016 2018 2017 Customer A 30% 43% 77% 35% 39% Customer B 23% 30% * 23% 32% Customer C 24% 25% —% 30% 27% Customer D 20% —% —% * —% * 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, 2018 2017 2016 United States $ 1,580 $ 1,161 $ 414 South Korea 1,168 666 — Ireland 1,098 787 63 India 981 — 23 Other countries — 21 39 Total $ 4,827 $ 2,635 $ 539 |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2018 2017 2016 Cash paid during the period for interest, net of amounts capitalized $ 604 $ 438 $ 75 Non-cash distributions to affiliates for conveyance of assets — — 253 |
Recent Accounting Standards (Ta
Recent Accounting Standards (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recent Accounting Standards, Not Yet Adopted | The following table provides a brief description of a recent accounting standard that had not been adopted by us as of December 31, 2018 : Standard Description Expected Date of Adoption Effect on our Financial Statements or Other Significant Matters ASU 2016-02, Leases (Topic 842) , and subsequent amendments thereto This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available. January 1, 2019 We will adopt this standard on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard will not have a material impact on our Financial Statements but will result in additional disclosures including the significant judgments and assumptions used in applying the standard. |
Recent Accounting Standards, Adopted | Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period: Standard Description Date of Adoption Effect on our Financial Statements or Other Significant Matters ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , and subsequent amendments thereto This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”). January 1, 2018 We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported Financial Statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See Note 11—Revenues from Contracts with Customers for additional disclosures. ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach. January 1, 2018 The adoption of this guidance did not have an impact on our Financial Statements or related disclosures. |
Summarized Quarterly Financia_2
Summarized Quarterly Financial Data (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Summarized Quarterly Financial Data—(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2018: Revenues $ 1,518 $ 1,333 $ 1,454 $ 1,821 Income from operations 391 339 384 406 Net income 242 193 243 266 Year ended December 31, 2017: Revenues $ 823 $ 925 $ 834 $ 1,442 Income from operations 145 105 109 422 Net income (loss) (4 ) (20 ) (12 ) 286 |
Organization and Nature of Op_2
Organization and Nature of Operations (Details) | 12 Months Ended |
Dec. 31, 2018itemmilliontonnes / yrbcf / dBcfebcfmemberstrainsm³ | |
Organization And Nature Of Operations [Line Items] | |
Limited Liability Company (LLC), Number Of Members | members | 1 |
Regasification Capacity | bcf | 2 |
Sabine Pass LNG Terminal [Member] | |
Organization And Nature Of Operations [Line Items] | |
Number of LNG Storage Tanks | item | 5 |
Storage Capacity | Bcfe | 16.9 |
Number of marine berths | item | 2 |
Volume of Vessel | m³ | 266,000 |
Regasification Capacity | bcf / d | 4 |
Number of Liquefaction LNG Trains | trains | 6 |
Train Nominal Capacity | 4.5 |
Sabine Pass LNG Terminal [Member] | Minimum [Member] | |
Organization And Nature Of Operations [Line Items] | |
Run Rate Adjusted Nominal Production Capacity, per Train | 4.5 |
Sabine Pass LNG Terminal [Member] | Maximum [Member] | |
Organization And Nature Of Operations [Line Items] | |
Run Rate Adjusted Nominal Production Capacity, per Train | 4.9 |
Cheniere [Member] | Cheniere Partners [Member] | |
Organization And Nature Of Operations [Line Items] | |
Noncontrolling Interest, Ownership Percentage by Parent | 48.60% |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)unitcustomer | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Impairment expense related to accounts receivable | $ 0 | $ 0 | $ 0 |
Impairment expense related to property, plant and equipment | 0 | 0 | 0 |
Derivative instruments designated as cash flow hedges | 0 | $ 0 | $ 0 |
Income Tax Expense (Benefit) | 0 | ||
Taxes, Difference in Bases, Amount | $ 2,600,000,000 | ||
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] | |||
Concentration Risk, Number of Significant Customers | customer | 7 | ||
Minimum [Member] | Customer Concentration Risk [Member] | SPA Customers [Member] | |||
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
SPA, Term of Agreement | 20 years | ||
Maximum [Member] | Sabine Pass LNG Terminal [Member] | |||
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Property Lease Term | 90 years |
Restricted Cash (Details)
Restricted Cash (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Restricted Cash and Cash Equivalents Items [Line Items] | ||
Restricted cash | $ 756 | $ 544 |
Liquefaction Project [Member] | ||
Restricted Cash and Cash Equivalents Items [Line Items] | ||
Restricted cash | $ 756 | $ 544 |
Accounts and Other Receivable_2
Accounts and Other Receivables (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Receivables [Abstract] | ||
Trade receivable | $ 330 | $ 185 |
Other accounts receivable | 16 | 4 |
Total accounts and other receivables | $ 346 | $ 189 |
Inventory (Details)
Inventory (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Inventory [Line Items] | ||
Inventory | $ 87 | $ 85 |
Natural gas [Member] | ||
Inventory [Line Items] | ||
Inventory | 28 | 17 |
LNG [Member] | ||
Inventory [Line Items] | ||
Inventory | 6 | 26 |
Materials and other [Member] | ||
Inventory [Line Items] | ||
Inventory | $ 53 | $ 42 |
Property, Plant and Equipment -
Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |||
Depreciation expense | $ 339 | $ 257 | $ 77 |
Offsets to LNG terminal costs | $ 94 | $ 301 | $ 201 |
Property, Plant and Equipment_2
Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, net | $ 13,209 | $ 12,920 |
LNG terminal costs [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Accumulated depreciation | (667) | (330) |
Property, plant and equipment, net | 13,203 | 12,916 |
LNG terminal [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 10,004 | 9,963 |
LNG terminal construction-in-process [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 3,866 | 3,283 |
Fixed assets [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 14 | 10 |
Accumulated depreciation | (8) | (6) |
Property, plant and equipment, net | $ 6 | $ 4 |
Property, Plant and Equipment_3
Property, Plant and Equipment - Estimated Useful Lives (Details) | 12 Months Ended |
Dec. 31, 2018 | |
LNG terminal costs [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 6 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 | 6 years |
Liquefaction processing equipment [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 50 years |
Other [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 15 years |
Other [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 30 years |
Derivative Instruments - Narrat
Derivative Instruments - Narrative (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($)tbtu | Dec. 31, 2017USD ($)tbtu | Dec. 31, 2016USD ($) | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Payments upon termination of Interest Rate Derivatives | $ 101 | $ 26 | $ (36) | |
Energy Units Secured Through Natural Gas Supply Contracts | tbtu | 3,464 | 2,214 | ||
Credit Facilities [Member] | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Line of Credit Facility, Decrease | $ 1,600 | |||
Interest Rate Derivatives [Member] | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Payments upon termination of Interest Rate Derivatives | $ 7 | |||
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Derivative, Term of Contract | 6 years | |||
Liquefaction Supply Derivatives [Member] | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Derivative, Notional Amount | tbtu | 2,978 | 1,520 |
Derivative Instruments - Fair V
Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | $ (43) | $ 55 |
Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 5 | 2 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (23) | 10 |
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 | $ (25) | $ 43 |
Derivative Instruments - Fair_2
Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member] | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Net Fair Value Liability | $ (25,000,000) |
Minimum [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Significant Unobservable Inputs Range | (0.892) |
Maximum [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Significant Unobservable Inputs Range | $ 0.085 |
Derivative Instruments - Schedu
Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Balance, beginning of period | $ 43 | $ 79 | $ 32 | |
Realized and mark-to-market gains (losses): | ||||
Included in cost of sales | [1] | (3) | (37) | 48 |
Purchases and settlements: | ||||
Purchases | (37) | 14 | 1 | |
Settlements | [1] | (29) | (12) | (2) |
Transfers out of Level 3 | [2] | 1 | (1) | 0 |
Balance, end of period | (25) | 43 | 79 | |
Change in unrealized gains (losses) relating to instruments still held at end of period | $ (3) | $ (37) | 49 | |
Decrease In Fair Value Realized And Capitalized During Period | $ 1 | |||
[1] | Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016. | |||
[2] | Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements. |
Derivative Instruments - Fair_3
Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivatives, Fair Value [Line Items] | |||
Non-current derivative assets | $ 31 | $ 17 | |
Derivative liabilities | (66) | 0 | |
Non-current derivative liabilities | (14) | (3) | |
Liquefaction Supply Derivatives [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Total derivative assets | [1] | 37 | 58 |
Total derivative liabilities | [1] | (80) | (3) |
Derivative asset (liability), net | [1] | (43) | 55 |
Derivative, collateral call | 1 | 1 | |
Liquefaction Supply Derivatives [Member] | Other current assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative assets | [1] | 6 | 41 |
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Non-current derivative assets | [1] | 31 | 17 |
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative liabilities | [1] | (66) | 0 |
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Non-current derivative liabilities | [1] | $ (14) | $ (3) |
[1] | Does not include collateral calls of $1 million for such contracts, which are included in other current assets in our Balance Sheets as of both December 31, 2018 and 2017 |
Derivative Instruments - Deriva
Derivative Instruments - Derivative Gain (Loss) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Interest Rate Derivatives [Member] | Derivative loss, net [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative gain (loss), net | $ 0 | $ (2) | $ (6) | |
Liquefaction Supply Derivatives [Member] | LNG revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative gain (loss), net | [1] | (1) | 0 | 0 |
Liquefaction Supply Derivatives [Member] | Cost of sales [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative gain (loss), net | [1] | $ (100) | $ (24) | $ 42 |
[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 Instruments - Deri_2
Derivative Instruments - Derivative Net Presentation on Balance Sheets (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Liquefaction Supply Derivatives Asset [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Gross Amounts Recognized | $ 63 | $ 64 |
Derivative Asset, Gross Amounts Offset in the Balance Sheets | (26) | (6) |
Net Amounts Presented in our Balance Sheets | 37 | 58 |
Liquefaction Supply Derivatives Liability [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Gross Amounts Recognized | (92) | (3) |
Derivative Liability, Gross Amounts Offset in the Balance Sheets | 12 | 0 |
Net Amounts Presented in our Balance Sheets | $ (80) | $ (3) |
Other Non-Current Assets (Detai
Other Non-Current Assets (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Other Assets, Noncurrent [Abstract] | ||
Advances made under EPC and non-EPC contracts | $ 14 | $ 26 |
Advances made to municipalities for water system enhancements | 90 | 93 |
Advances and other asset conveyances to third parties to support LNG terminals | 36 | 30 |
Tax-related payments and receivables | 0 | 1 |
Information technology service assets | 16 | 19 |
Other | 2 | 0 |
Other non-current assets, net | $ 158 | $ 169 |
Accrued Liabilities (Details)
Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Accrued Liabilities, Current [Abstract] | ||
Interest costs and related debt fees | $ 186 | $ 230 |
Accrued natural gas purchases | 518 | 298 |
Liquefaction Project costs | 64 | 78 |
Total accrued liabilities | $ 768 | $ 606 |
Debt - Schedule of Debt Instrum
Debt - Schedule of Debt Instruments (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Unamortized discount, premium and debt issuance costs, net | $ (150,000,000) | $ (173,000,000) |
Long-term Debt, Net | 13,500,000,000 | 13,477,000,000 |
Current Debt, Working Capital Facility | 0 | 0 |
Total Debt, Net | 13,500,000,000 | 13,477,000,000 |
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 |
Debt - Schedule of Maturities (
Debt - Schedule of Maturities (Details) $ in Millions | Dec. 31, 2018USD ($) |
Long-term Debt, Fiscal Year Maturity [Abstract] | |
2,019 | $ 0 |
2,020 | 0 |
2,021 | 2,000 |
2,022 | 1,000 |
2,023 | 1,500 |
Thereafter | 9,150 |
Total | $ 13,650 |
Debt - Senior Notes (Details)
Debt - Senior Notes (Details) | 12 Months Ended |
Dec. 31, 2018Rate | |
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 ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
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 | 425,000,000 | |
Available commitment | $ 775,000,000 | |
Debt Instrument, Description of Variable Rate Basis | LIBOR or base rate | |
Debt Instrument, Maturity Date, Description | December 31, 2020, with various terms for underlying loans | |
Line of Credit Facility, Commitment Fee Percentage | 0.70% | |
Line of Credit Facility, Number of Business Days Notice Required for Repayment of Debt Without Penalty | 3 days | |
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 | |
Working Capital Facility [Member] | Completion of Train Six Financing [Member] | Maximum [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility Permitted Increase | 390,000,000 | |
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% | |
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 | |
LC Loan [Member] | Maximum [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Term | 1 year | |
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 |
Debt - Interest Expense (Detail
Debt - Interest Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |||
Total interest cost | $ 791 | $ 779 | $ 649 |
Capitalized interest | (202) | (285) | (463) |
Total interest expense, net | $ 589 | $ 494 | $ 186 |
Debt - Schedule of Carrying Val
Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt, Carrying Value | $ 13,500 | $ 13,477 | |
Senior Notes [Member] | Carrying Amount [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt, Carrying Value | [1] | 12,709 | 12,687 |
Senior Notes [Member] | Estimated Fair Value [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes, Estimated Fair Value | [1] | 13,235 | 13,955 |
2037 Senior Notes [Member] | Carrying Amount [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt, Carrying Value | [2] | 791 | 790 |
2037 Senior Notes [Member] | Estimated Fair Value [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes, Estimated Fair Value | [2] | $ 817 | $ 871 |
[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 _3
Revenues from Contracts with Customers - Narrative (Details) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation of Revenue [Line Items] | ||
LNG Volume, Sales Price Percentage of Henry Hub | 115.00% | |
LNG [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue, Variable Consideration Received From Customers, Percentage | 57.00% | 58.00% |
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 | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Disaggregation of Revenue [Line Items] | ||||||||||||
Revenue earned from contracts with customers | $ 5,986 | $ 4,004 | $ 829 | |||||||||
Revenues | $ 1,821 | $ 1,454 | $ 1,333 | $ 1,518 | $ 1,442 | $ 834 | $ 925 | $ 823 | 6,126 | 4,024 | 833 | |
LNG [Member] | ||||||||||||
Disaggregation of Revenue [Line Items] | ||||||||||||
Revenue earned from contracts with customers | 4,687 | 2,615 | 535 | |||||||||
Revenues | 4,827 | 2,635 | 539 | |||||||||
LNG—affiliate [Member] | ||||||||||||
Disaggregation of Revenue [Line Items] | ||||||||||||
Revenue earned from contracts with customers | 1,299 | 1,389 | 294 | |||||||||
Derivative Instruments [Member] | ||||||||||||
Disaggregation of Revenue [Line Items] | ||||||||||||
Revenues | [1] | $ 140 | $ 20 | $ 4 | ||||||||
[1] | Includes the realized value associated with a portion of derivative instruments that settle through physical delivery. |
Revenues from Contracts with _5
Revenues from Contracts with Customers - Schedule of Deferred Revenue Reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Change In Contract With Customer, Liability [Roll Forward] | ||
Deferred revenues, beginning of period | $ 84 | $ 46 |
Cash received but not yet recognized | 91 | 84 |
Revenue recognized from prior period deferral | (84) | (46) |
Deferred revenues, end of period | $ 91 | $ 84 |
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 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Unsatisfied Transaction Price | $ 53.6 | $ 55.7 | |
Weighted Average Recognition Timing | [1] | 10 years | 10 years |
[1] | The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price. |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Related Party Transaction [Line Items] | |||
Cost of sales—affiliate | $ 32 | $ 23 | $ 7 |
Operating and maintenance expense—affiliate | 423 | 329 | 129 |
Development expense—affiliate | 0 | 0 | 1 |
General and administrative expense—affiliate | 50 | 58 | 68 |
Cheniere Marketing SPA and Cheniere Marketing Master SPA [Member] | |||
Related Party Transaction [Line Items] | |||
LNG revenues—affiliate | 1,299 | 1,389 | 294 |
Terminal Use Agreement [Member] | |||
Related Party Transaction [Line Items] | |||
Cost of sales—affiliate | 32 | 23 | 5 |
Operating and maintenance expense—affiliate | 256 | 190 | 61 |
Fees under the Pre-commercial LNG Marketing Agreement | |||
Related Party Transaction [Line Items] | |||
Cost of sales—affiliate | 0 | 0 | 2 |
Natural Gas Transportation Agreement [Member] | |||
Related Party Transaction [Line Items] | |||
Operating and maintenance expense—affiliate | 80 | 73 | 45 |
Service Agreements [Member] | |||
Related Party Transaction [Line Items] | |||
Operating and maintenance expense—affiliate | 87 | 65 | 22 |
Development expense—affiliate | 0 | 0 | 1 |
General and administrative expense—affiliate | 50 | 58 | 68 |
LNG Site Sublease Agreement [Member] | |||
Related Party Transaction [Line Items] | |||
Operating and maintenance expense—affiliate | $ 0 | $ 1 | $ 1 |
Related Party Transactions - Na
Related Party Transactions - Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)bcf / dbcfitem$ / MMBTU | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Related Party Transaction [Line Items] | |||
Accounts receivable—affiliate | $ 113,000,000 | $ 163,000,000 | |
Regasification Capacity | bcf | 2 | ||
Advances to affiliate | $ 210,000,000 | 26,000,000 | |
LNG Terminal-Related Agreements [Member] | |||
Related Party Transaction [Line Items] | |||
Accounts receivable—affiliate | $ 113,000,000 | 163,000,000 | |
Terminal Use Agreement [Member] | SPLNG [Member] | |||
Related Party Transaction [Line Items] | |||
Regasification Capacity | bcf / d | 2 | ||
Related Party Transaction, Committed Annual Fee | $ 250,000,000 | ||
Terminal Use Rights Assignment and Agreement [Member] | SPLNG [Member] | Cheniere Investments [Member] | Maximum [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Percentage Of Committed Monthly Payment | 100.00% | ||
Terminal Use Rights Assignment and Agreement [Member] | SPLNG [Member] | Cheniere Investments [Member] | Minimum [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Percentage Of Committed Monthly Payment | 0.00% | ||
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 | $ / MMBTU | 3 | ||
Natural Gas Transportation Agreement [Member] | CTPL [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Agreement Term | 20 years | ||
Related Party Agreement, Termination Notice Period | 1 year | ||
Related Party Agreement, Number Of Available Extensions | item | 2 | ||
Related Party Agreement, Term Of Available Extension | 10 years | ||
Service Agreements [Member] | |||
Related Party Transaction [Line Items] | |||
Advances to affiliate | $ 210,000,000 | 26,000,000 | |
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% | ||
Related Party Transaction, Committed Monthly Fee | $ 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% | ||
Related Party Transaction, Committed Monthly Fee | $ 541,667 | ||
LNG Site Sublease Agreement [Member] | SPLNG [Member] | |||
Related Party Transaction [Line Items] | |||
Annual Sublease Payment | $ 1,000,000 | ||
Term of available extension | 10 years | ||
Review Period for Inflation Adjustment | 5 years | ||
Cooperation Agreement [Member] | SPLNG [Member] | |||
Related Party Transaction [Line Items] | |||
Assets conveyed under the agreement | $ 0 | $ 0 | $ 253,000,000 |
Tax Sharing Agreement [Member] | Cheniere [Member] | |||
Related Party Transaction [Line Items] | |||
Income Taxes Paid, Net | $ 0 |
Leases (Details)
Leases (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Leases [Abstract] | ||||
Operating Leases, Rent Expense | $ 5 | $ 3 | $ 2 | |
2019 through 2023 | [1] | 2 | ||
Thereafter | [1] | 7 | ||
Total | [1] | $ 9 | ||
[1] | Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components. |
Commitments and Contingencies -
Commitments and Contingencies - Narrative (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018USD ($)tbtubcfitem | Dec. 31, 2017tbtu | |
Commitments and Contingencies [Line Items] | ||
Energy Units Secured Through Natural Gas Supply Contracts | tbtu | 3,464 | 2,214 |
Regasification Capacity | bcf | 2 | |
Loss Contingency, Pending Claims, Number | item | 0 | |
Bechtel EPC Contracts [Member] | ||
Commitments and Contingencies [Line Items] | ||
Contract termination convenience penalty | $ 30 | |
Bechtel EPC Contract, Train 5 [Member] | ||
Commitments and Contingencies [Line Items] | ||
Long-term Purchase Commitment, Amount | 3,100 | |
Bechtel EPC Contract, Train 6 [Member] | ||
Commitments and Contingencies [Line Items] | ||
Long-term Purchase Commitment, Amount | $ 2,500 | |
Natural Gas Supply Agreement [Member] | Maximum [Member] | ||
Commitments and Contingencies [Line Items] | ||
Long-term Purchase Commitment, Period | 6 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, 2018USD ($) | [1] |
Long-term Purchase Commitment [Line Items] | ||
2,019 | $ 2,465 | |
2,020 | 1,377 | |
2,021 | 1,010 | |
2,022 | 756 | |
2,023 | 641 | |
Thereafter | 1,652 | |
Total | $ 7,901 | |
[1] | Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on prices and basis spreads as of December 31, 2018. |
Customer Concentration - Schedu
Customer Concentration - Schedule of Revenue and Accounts Receivable by Major Customers (Details) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Customer A [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 30.00% | 43.00% | 77.00% |
Customer A [Member] | Accounts Receivable from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 35.00% | 39.00% | |
Customer B [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 23.00% | 30.00% | |
Customer B [Member] | Accounts Receivable from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 23.00% | 32.00% | |
Customer C [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 24.00% | 25.00% | 0.00% |
Customer C [Member] | Accounts Receivable from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 30.00% | 27.00% | |
Customer D [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 20.00% | 0.00% | 0.00% |
Customer D [Member] | Accounts Receivable from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 0.00% |
Customer Concentration - Sche_2
Customer Concentration - Schedule of Revenues from External Customers by Country (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Concentration Risk [Line Items] | |||||||||||
Revenues from External Customers | $ 1,821 | $ 1,454 | $ 1,333 | $ 1,518 | $ 1,442 | $ 834 | $ 925 | $ 823 | $ 6,126 | $ 4,024 | $ 833 |
Geographic Concentration Risk [Member] | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Revenues from External Customers | 4,827 | 2,635 | 539 | ||||||||
Geographic Concentration Risk [Member] | United States | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Revenues from External Customers | 1,580 | 1,161 | 414 | ||||||||
Geographic Concentration Risk [Member] | South Korea | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Revenues from External Customers | 1,168 | 666 | 0 | ||||||||
Geographic Concentration Risk [Member] | Ireland | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Revenues from External Customers | 1,098 | 787 | 63 | ||||||||
Geographic Concentration Risk [Member] | India | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Revenues from External Customers | 981 | 0 | 23 | ||||||||
Geographic Concentration Risk [Member] | Other countries | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Revenues from External Customers | $ 0 | $ 21 | $ 39 |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid during the period for interest, net of amounts capitalized | $ 604 | $ 438 | $ 75 |
Non-cash distributions to affiliates for conveyance of assets | 0 | 0 | 253 |
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) | $ 256 | $ 268 | $ 263 |
Summarized Quarterly Financia_3
Summarized Quarterly Financial Data (unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 1,821 | $ 1,454 | $ 1,333 | $ 1,518 | $ 1,442 | $ 834 | $ 925 | $ 823 | $ 6,126 | $ 4,024 | $ 833 |
Income from operations | 406 | 384 | 339 | 391 | 422 | 109 | 105 | 145 | 1,520 | 781 | 50 |
Net income (loss) | $ 266 | $ 243 | $ 193 | $ 242 | $ 286 | $ (12) | $ (20) | $ (4) | $ 944 | $ 250 | $ (193) |