Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 17, 2017 | Jun. 30, 2016 | |
Entity Information [Line Items] | |||
Entity Registrant Name | Cheniere Energy Partners, L.P. | ||
Entity Central Index Key | 1,383,650 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 1.4 | ||
Common Units [Member] | |||
Entity Information [Line Items] | |||
Entity Units, Units Outstanding | 57,109,223 | ||
Class B Units [Member] | |||
Entity Information [Line Items] | |||
Entity Units, Units Outstanding | 145,333,334 | ||
Subordinated Units [Member] | |||
Entity Information [Line Items] | |||
Entity Units, Units Outstanding | 135,383,831 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets | ||
Cash and cash equivalents | $ 0 | $ 146,221 |
Restricted cash | 604,944 | 274,557 |
Accounts and other receivables | 90,196 | 741 |
Accounts receivable—affiliate | 99,336 | 1,271 |
Advances to affiliate | 37,697 | 39,836 |
Inventory | 97,431 | 16,667 |
Other current assets | 28,656 | 14,182 |
Total current assets | 958,260 | 493,475 |
Non-current restricted cash | 0 | 13,650 |
Property, plant and equipment, net | 14,158,187 | 11,931,602 |
Debt issuance costs, net | 120,704 | 132,091 |
Non-current derivative assets | 82,861 | 30,304 |
Other non-current assets, net | 222,328 | 232,031 |
Total assets | 15,542,340 | 12,833,153 |
Current liabilities | ||
Accounts payable | 27,162 | 16,407 |
Accrued liabilities | 417,502 | 224,292 |
Current debt, net | 223,500 | 1,673,379 |
Due to affiliates | 99,529 | 115,123 |
Deferred revenue | 72,631 | 26,669 |
Deferred revenue—affiliate | 717 | 717 |
Derivative liabilities | 14,446 | 6,430 |
Other current liabilities | 224 | 0 |
Total current liabilities | 855,711 | 2,063,017 |
Long-term debt, net | 14,209,229 | 10,018,325 |
Non-current deferred revenue | 5,500 | 9,500 |
Non-current derivative liabilities | 2,001 | 2,884 |
Other non-current liabilities | 165 | 175 |
Other non-current liabilities—affiliate | 26,680 | 26,321 |
Commitments and contingencies (see Note 14) | ||
Partners’ equity | ||
Common unitholders’ interest (57.1 million units issued and outstanding at December 31, 2016 and 2015) | 129,712 | 305,747 |
Class B unitholders’ interest (145.3 million units issued and outstanding at December 31, 2016 and 2015) | 62,256 | (37,429) |
Subordinated unitholders’ interest (135.4 million units issued and outstanding at December 31, 2016 and 2015) | 239,909 | 428,035 |
General partner’s interest (2% interest with 6.9 million units issued and outstanding at December 31, 2016 and 2015) | 11,177 | 16,578 |
Total partners’ equity | 443,054 | 712,931 |
Total liabilities and partners’ equity | $ 15,542,340 | $ 12,833,153 |
Consolidated Balance Sheets Par
Consolidated Balance Sheets Parentheticals - shares shares in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
General Partner Ownership Interest Percentage | 2.00% | 2.00% |
General Partners' Capital Account, Units Issued | 6,894 | 6,894 |
General partner units outstanding | 6,894 | 6,894 |
Common Units [Member] | ||
Limited Partners' Capital Account, Units Issued | 57,109 | 57,084 |
Partnership unitholders units outstanding | 57,109 | 57,084 |
Class B Units [Member] | ||
Limited Partners' Capital Account, Units Issued | 145,333 | 145,333 |
Partnership unitholders units outstanding | 145,333 | 145,333 |
Subordinated Units [Member] | ||
Limited Partners' Capital Account, Units Issued | 135,384 | 135,384 |
Partnership unitholders units outstanding | 135,384 | 135,384 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues | |||
LNG revenues | $ 539,468 | $ 0 | $ 0 |
LNG revenues—affiliate | 293,957 | 0 | 0 |
Regasification revenues | 263,030 | 265,637 | 265,740 |
Regasification revenues—affiliate | 3,785 | 4,391 | 2,958 |
Total revenues | 1,100,240 | 270,028 | 268,698 |
Operating costs and expenses | |||
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below) | 410,433 | (31,466) | (342) |
Cost of sales—affiliate | 1,490 | 0 | 0 |
Operating and maintenance expense | 126,878 | 62,406 | 63,161 |
Operating and maintenance expense—affiliate | 52,137 | 29,379 | 21,115 |
Development expense | 126 | 2,850 | 9,319 |
Development expense—affiliate | 396 | 722 | 1,153 |
General and administrative expense | 13,200 | 15,079 | 13,807 |
General and administrative expense—affiliate | 89,523 | 122,312 | 101,369 |
Depreciation and amortization expense | 155,621 | 65,704 | 58,601 |
Total operating costs and expenses | 849,804 | 266,986 | 268,183 |
Income from operations | 250,436 | 3,042 | 515 |
Other income (expense) | |||
Interest expense, net of capitalized interest | (356,900) | (184,600) | (177,032) |
Loss on early extinguishment of debt | (71,824) | (96,273) | (114,335) |
Derivative gain (loss), net | 5,544 | (41,722) | (119,401) |
Other income | 1,549 | 662 | 217 |
Total other expense | (421,631) | (321,933) | (410,551) |
Net loss | $ (171,195) | $ (318,891) | $ (410,036) |
Basic and diluted net loss per common unit | $ (0.20) | $ (0.43) | $ (0.89) |
Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation | 57,086 | 57,081 | 57,079 |
Consolidated Statement of Partn
Consolidated Statement of Partners' Equity - USD ($) shares in Thousands, $ in Thousands | Total | Common Units [Member] | Class B Units [Member] | Subordinated Units [Member] | General Partner [Member] |
Units, Outstanding, beginning of period at Dec. 31, 2013 | 57,078 | 145,333 | 135,384 | ||
Partners' equity, beginning of period at Dec. 31, 2013 | $ 1,639,744 | $ 711,771 | $ (38,216) | $ 931,074 | $ 35,115 |
General partner units, Outstanding, beginning of period at Dec. 31, 2013 | 6,894 | ||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Net loss | (410,036) | (119,175) | 0 | (282,660) | $ (8,201) |
Distributions | (99,015) | $ (97,035) | 0 | 0 | (1,980) |
Issuance of common units as compensation to non-management directors, units | 2 | ||||
Issuance of common units as compensation to non-management directors | 36 | $ 36 | $ 0 | $ 0 | 0 |
Units, Outstanding, end of period at Dec. 31, 2014 | 57,080 | 145,333 | 135,384 | ||
Partners' equity, end of period at Dec. 31, 2014 | 1,130,729 | $ 495,597 | $ (38,216) | $ 648,414 | $ 24,934 |
General partner units, Outstanding, end of period at Dec. 31, 2014 | 6,894 | ||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Net loss | (318,891) | (92,688) | 0 | (219,825) | $ (6,378) |
Distributions | (99,018) | $ (97,038) | 0 | 0 | (1,980) |
Issuance of common units as compensation to non-management directors, units | 4 | ||||
Issuance of common units as compensation to non-management directors | 111 | $ 109 | 0 | 0 | 2 |
Amortization of beneficial conversion feature of Class B units | 0 | $ (233) | $ 787 | $ (554) | 0 |
Units, Outstanding, end of period at Dec. 31, 2015 | 57,084 | 145,333 | 135,384 | ||
Partners' equity, end of period at Dec. 31, 2015 | $ 712,931 | $ 305,747 | $ (37,429) | $ 428,035 | $ 16,578 |
General partner units, Outstanding, end of period at Dec. 31, 2015 | 6,894 | 6,894 | |||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||
Net loss | $ (171,195) | (49,763) | 0 | (118,008) | $ (3,424) |
Distributions | (99,025) | $ (97,045) | 0 | 0 | (1,980) |
Issuance of common units as compensation to non-management directors, units | 25 | ||||
Issuance of common units as compensation to non-management directors | 343 | $ 340 | 0 | 0 | 3 |
Amortization of beneficial conversion feature of Class B units | 0 | $ (29,567) | $ 99,685 | $ (70,118) | 0 |
Units, Outstanding, end of period at Dec. 31, 2016 | 57,109 | 145,333 | 135,384 | ||
Partners' equity, end of period at Dec. 31, 2016 | $ 443,054 | $ 129,712 | $ 62,256 | $ 239,909 | $ 11,177 |
General partner units, Outstanding, end of period at Dec. 31, 2016 | 6,894 | 6,894 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Cash flows from operating activities | |||
Net loss | $ (171,195,000) | $ (318,891,000) | $ (410,036,000) |
Adjustments to reconcile net loss to net cash used in operating activities: | |||
Non-cash LNG inventory write-downs | 0 | 17,537,000 | 24,461,000 |
Depreciation and amortization expense | 155,621,000 | 65,704,000 | 58,601,000 |
Amortization of debt issuance costs, deferred commitment fees, premium and discount | 29,774,000 | 12,174,000 | 14,264,000 |
Loss on early extinguishment of debt | 71,824,000 | 96,273,000 | 114,335,000 |
Total (gains) losses on derivatives, net | (47,882,000) | 7,154,000 | 117,701,000 |
Net cash used for settlement of derivative instruments | (8,301,000) | (41,398,000) | (21,581,000) |
Other | 772,000 | 85,000 | 15,000 |
Changes in operating assets and liabilities: | |||
Accounts and other receivables | (90,122,000) | 259,000 | (293,000) |
Accounts receivable—affiliate | (98,032,000) | 1,248,000 | (503,000) |
Advances to affiliate | 442,000 | (12,513,000) | (12,586,000) |
Inventory | (58,030,000) | (25,037,000) | (19,008,000) |
Accounts payable and accrued liabilities | 166,710,000 | (996,000) | 3,949,000 |
Due to affiliates | 11,288,000 | 14,882,000 | (15,842,000) |
Deferred revenue | 41,961,000 | (3,986,000) | (3,938,000) |
Other, net | (6,324,000) | (12,010,000) | (4,236,000) |
Other, net—affiliate | 1,245,000 | 28,416,000 | 17,653,000 |
Net cash used in operating activities | (249,000) | (171,099,000) | (137,044,000) |
Cash flows from investing activities | |||
Property, plant and equipment, net | (2,315,081,000) | (2,912,080,000) | (2,645,553,000) |
Other | (38,318,000) | (62,448,000) | (38,880,000) |
Net cash used in investing activities | (2,353,399,000) | (2,974,528,000) | (2,684,433,000) |
Cash flows from financing activities | |||
Proceeds from issuances of debt | 8,002,500,000 | 2,860,000,000 | 2,584,500,000 |
Repayments of debt | (5,250,500,000) | 0 | (177,000,000) |
Debt issuance and deferred financing costs | (114,724,000) | (169,924,000) | (101,787,000) |
Debt extinguishment costs | (14,087,000) | 0 | 0 |
Distributions to owners | (99,025,000) | (99,018,000) | (98,979,000) |
Net cash provided by financing activities | 2,524,164,000 | 2,591,058,000 | 2,206,734,000 |
Net increase (decrease) in cash, cash equivalents and restricted cash | 170,516,000 | (554,569,000) | (614,743,000) |
Cash, cash equivalents and restricted cash—beginning of period | 434,428,000 | 988,997,000 | 1,603,740,000 |
Cash, cash equivalents and restricted cash—end of period | 604,944,000 | 434,428,000 | 988,997,000 |
Balances per Consolidated Balance Sheets: | |||
Cash and cash equivalents | 0 | 146,221,000 | 248,830,000 |
Restricted cash | 604,944,000 | 274,557,000 | 195,702,000 |
Non-current restricted cash | 0 | 13,650,000 | 544,465,000 |
Total cash, cash equivalents and restricted cash | $ 604,944,000 | $ 434,428,000 | $ 988,997,000 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | ORGANIZATION AND NATURE OF OPERATIONS We are a publicly traded Delaware limited partnership (NYSE MKT: CQP) formed by Cheniere. T hrough our wholly owned subsidiary, SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 and 2 have commenced operating activities, Train 3 is undergoing commissioning and has produced LNG, Trains 4 and 5 are under construction and Train 6 is fully permitted. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa of LNG. Through our wholly owned subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two marine berths that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We also own a 94 -mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through our wholly owned subsidiary, CTPL. As of December 31, 2016 , Cheniere owned 100% of our general partner interest and 82.6% of Cheniere Holdings, which owned 12.0 million of our common units, 45.3 million of our Class B units and 135.4 million of our subordinated units. |
Unitholders' Equity
Unitholders' Equity | 12 Months Ended |
Dec. 31, 2016 | |
Partners' Capital Notes [Abstract] | |
Unitholders' Equity | UNITHOLDERS’ EQUITY The common units, Class B units and subordinated units represent limited partner interests in us. The holders of the units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from operating surplus as defined in the partnership agreement. The holders of common units have the right to receive initial quarterly distributions of $0.425 per common unit, plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. The holders of subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distribution requirement for our common unitholders and general partner and certain reserves. Subordinated units will convert into common units on a one-for-one basis when we meet financial tests specified in the partnership agreement. Although common and subordinated unitholders are not obligated to fund losses of the Partnership, their capital accounts, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continue to share in losses. The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights (“IDRs”) , which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met. The higher percentages range from 15% to 50% . During 2012, Blackstone CQP Holdco and Cheniere completed their purchases of a new class of equity interests representing limited partner interests in us (“Class B units”) for total consideration of $1.5 billion and $500.0 million , respectively. Proceeds from the financings were used to fund a portion of the costs of developing, constructing and placing into service the first two Train s of the Liquefaction Project . In May 2013, Cheniere purchased an additional 12.0 million Class B units for consideration of $180.0 million in connection with our acquisition of CTPL and Cheniere Pipeline GP Interests, LLC. In 2013, Cheniere formed Cheniere Holdings to hold its limited partner interests in us. The Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units . The Class B units are not entitled to cash distributions except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. On a quarterly basis beginning on the date of the initial purchase date of the Class B units , the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco was 1.86 and 1.83 , respectively, as of December 31, 2016 . The Class B units will mandatorily convert into common units on the first business day following the record date of our first distribution after the substantial completion date of Train 3 of the Liquefaction Project , but in any case no earlier than the first business day following the record date of our distribution with respect to the quarter ended June 30, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Our Consolidated Financial Statements have been prepared in accordance with GAAP . The Consolidated Financial Statements include the accounts of Cheniere Energy Partners, L.P. and its majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall consolidated financial position, operating results or cash flows. In 2016, we started production at the Liquefaction Project . As a result, we introduced a new line item entitled “cost of sales” and modified the components of activity included in “operating and maintenance expense” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made to the prior periods. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the Liquefaction Project , and other costs related to converting natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense. Operating and maintenance expense now includes costs associated with operating and maintaining the Liquefaction Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs. Additionally, we distinguished and reclassified our historical “revenues” line item into “LNG revenues” and “regasification revenues.” LNG revenues include fees that are received pursuant to our SPAs and related LNG marketing activities. Regasification revenues include LNG regasification capacity reservation fees that are received pursuant to our TUAs and tug services fees that are received by Sabine Pass Tug Services, LLC (“ Tug Services ”), a wholly owned subsidiary of SPLNG. Use of Estimates The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, collectability of accounts receivable, 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 techniques 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 8—Derivative Instruments . The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 11—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 Fees received pursuant to SPAs are recognized as LNG revenues 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. LNG revenues are recognized when LNG is delivered to the counterparty, either at the Sabine Pass LNG terminal or at the counterparty’s LNG receiving terminal, based on the terms of the contract. LNG regasification capacity reservation fees are recognized as regasification revenues over the term of the respective TUAs. Advance capacity reservation fees are initially deferred and amortized over a 10 -year period as a reduction of a customer’s regasification capacity reservation fees payable under its TUA. Under each of these TUAs, SPLNG is entitled to retain 2% of LNG delivered for each customer’s account at the Sabine Pass LNG terminal, which is recognized as revenue as SPLNG performs the services set forth in each customer’s TUA. 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 Consolidated 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 bad debt expense related to accounts receivable during the years ended December 31, 2016, 2015 and 2014 . Inventory LNG and natural gas inventory are recorded at weighted average cost and materials and other inventory are recorded at cost. Inventory is subject to lower of cost or market (“LCM”) adjustments at the end of each period. Our LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal that are recorded in operating and maintenance expense on our Consolidated Statements of Operations. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price recoveries occur on the same inventory in the same fiscal year. These recoveries are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. During the years ended December 31, 2016 , 2015 and 2014 , we recognized zero , $17.5 million , and $24.5 million , respectively, as operating and maintenance expense as a result of LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. Accounting for LNG Activities Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals and related pipelines. 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 lease is obtained, the costs are expensed. We capitalize interest and other related debt costs during the construction period of our LNG terminal and related pipeline. Upon commencement of operations, capitalized interest, as a component of the total cost, is amortized over the estimated useful life of the asset. 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 and general and administrative activities are charged to expense as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. 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 other operating costs and expenses. Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We recorded $0.4 million , zero and zero impairments related to property, plant and equipment during the years ended December 31, 2016, 2015 and 2014 , respectively. Regulated Natural Gas Pipelines The Creole Trail Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities. Items that may influence our assessment are: • inability to recover cost increases due to rate caps and rate case moratoriums; • inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings; • excess capacity; • increased competition and discounting in the markets we serve; and • impacts of ongoing regulatory initiatives in the natural gas industry. Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service. Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria 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 current 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, 2016, 2015 and 2014 . See Note 8—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. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. 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 as other current asset. 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. SPL has entered into six fixed price 20 -year SPAs with six unaffiliated third parties. SPL is dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective SPAs. During the year ended December 31, 2016 , we received 77% of our net LNG revenues from one SPA customer. SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal, which accounts for substantially all of our regasification revenues. SPLNG is dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. SPLNG has mitigated this credit risk by securing TUAs for a significant portion of its regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA. 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 Consolidated 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 gains and losses on the extinguishment of debt on our Consolidated 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 Consolidated Balance Sheet. 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 early 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. Our assessment of AROs is described below. We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero . We have no t recorded an ARO associated with the Creole Trail Pipeline . We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly. Income Taxes We are not subject to federal or state income taxes, as our partners are taxed individually on their allocable share of our taxable income. At December 31, 2016 , the tax basis of our assets and liabilities was $329.8 million less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our tax sharing agreements. Business Segment Our liquefaction and regasification operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of Cheniere Partners in total when evaluating financial performance and for purposes of allocating resources. |
Restricted Cash
Restricted Cash | 12 Months Ended |
Dec. 31, 2016 | |
Cash and Cash Equivalents [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 Consolidated Balance Sheets. As of December 31, 2016 and 2015 , restricted cash consisted of the following (in thousands): December 31, 2016 2015 Current restricted cash SPLNG debt service and interest payment $ — $ 77,415 Liquefaction Project 357,953 189,260 CTPL construction and interest payment — 7,882 CQP and cash held by guarantor subsidiaries 246,991 — Total current restricted cash $ 604,944 $ 274,557 Non-current restricted cash SPLNG debt service $ — $ 13,650 In February 2016, we entered into a $2.8 billion credit facility (the “2016 CQP Credit Facilities”) . We, and Cheniere Investments, SPLNG and CTPL as our guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to us. Specifically, we, Cheniere Investments, SPLNG and CTPL may only withdraw funds from collateral accounts held at a designated depositary bank on a monthly basis and for specific purposes, including for the payment of operating expenses. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions. |
Accounts and Other Receivables
Accounts and Other Receivables | 12 Months Ended |
Dec. 31, 2016 | |
Receivables [Abstract] | |
Accounts and Other Receivables | ACCOUNTS AND OTHER RECEIVABLES As of December 31, 2016 and 2015 , accounts and other receivables consisted of the following (in thousands): December 31, 2016 2015 SPL trade receivable $ 87,555 $ — SPLNG trade receivable 396 — Other accounts receivable 2,245 741 Total accounts and other receivables $ 90,196 $ 741 Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of SPL’s debt holders, SPL is required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. As of December 31, 2016 , approximately 99% of our trade receivable balance was from two SPA customers. |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2016 | |
Inventory Disclosure [Abstract] | |
Inventory | INVENTORY As of December 31, 2016 and 2015 , inventory consisted of the following (in thousands): December 31, 2016 2015 Natural gas $ 14,755 $ 5,724 LNG 45,410 3,690 Materials and other 37,266 7,253 Total inventory $ 97,431 $ 16,667 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands): December 31, 2016 2015 LNG terminal costs LNG terminal $ 7,975,814 $ 2,478,036 LNG terminal construction-in-process 6,728,305 9,859,836 LNG site and related costs, net 128 135 Accumulated depreciation (552,905 ) (411,907 ) Total LNG terminal costs, net 14,151,342 11,926,100 Fixed assets and other Computer and office equipment 1,224 1,126 Furniture and fixtures 1,667 1,375 Computer software 9,608 4,238 Machinery and equipment 2,017 1,906 Vehicles 3,392 2,081 Other 2,024 93 Accumulated depreciation (13,087 ) (5,317 ) Total fixed assets and other, net 6,845 5,502 Property, plant and equipment, net $ 14,158,187 $ 11,931,602 Depreciation expense during the years ended December 31, 2016, 2015 and 2014 was $147.9 million , $64.6 million and $58.6 million , respectively. During the year ended December 31, 2016 , we realized offsets to LNG terminal costs of $201.0 million that was related to the sale of commissioning cargoes because this amount was earned prior to the start of commercial operations, during the testing phase for the construction of Trains 1 and 2 of the Liquefaction Project . LNG Terminal Costs The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows: Components Useful life (yrs) LNG storage tanks 50 Natural gas pipeline facilities 40 Marine berth, electrical, facility and roads 35 Regasification processing equipment 30 Sendout pumps 20 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, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | DERIVATIVE INSTRUMENTS We have entered into the following derivative instruments that are reported at fair value: • interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under certain of our credit facilities (“Interest Rate Derivatives”) ; • 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”) ; and • commodity derivatives to hedge the exposure to price risk attributable to future: (1) sales of our LNG inventory and (2) purchases of natural gas to operate the Sabine Pass LNG terminal (“Natural Gas Derivatives”) . None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations . SPLNG has elected to account for a portion of the Natural Gas Derivatives as normal purchase normal sale transactions, exempt from fair value accounting. Gains and losses for these physical hedges are not reflected on our Consolidated Statements of Operations until the period of delivery. SPLNG had not posted collateral for such forward contracts as of December 31, 2016 and 2015 . The following table (in thousands) 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, 2016 and 2015 , which are classified as other current assets , non-current derivative assets , derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets. Fair Value Measurements as of December 31, 2016 December 31, 2015 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 SPL Interest Rate Derivatives liability $ — $ (6,224 ) $ — $ (6,224 ) $ — $ (8,740 ) $ — $ (8,740 ) CQP Interest Rate Derivatives asset — 13,108 — 13,108 — — — — Liquefaction Supply Derivatives asset (liability) (4,483 ) (1,474 ) 79,022 73,065 — (25 ) 32,492 32,467 Natural Gas Derivatives asset — — — — — 39 — 39 We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. The estimated fair values of our Natural Gas Derivatives are the amounts at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. 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 particular 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. Internal fair value models include conditions precedent to the respective long-term natural gas supply contracts. As of December 31, 2016 and 2015 , some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow. Accordingly, our internal fair value models are based on market prices that equate to our own contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. 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 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 as of the reporting date. As all of our Physical Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2016 : Net Fair Value Asset (in thousands) Valuation Technique Significant Unobservable Input Significant Unobservable Inputs Range Physical Liquefaction Supply Derivatives $79,022 Income Approach Basis Spread $(0.260) - $(0.003) The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2016 and 2015 : Year Ended December 31, 2016 2015 Balance, beginning of period $ 32,492 $ 342 Realized and mark-to-market gains: Included in cost of sales (1) 48,218 32,150 Purchases and settlements: Purchases 538 — Settlements (1) (2,226 ) — Transfers out of Level 3 — — Balance, end of period $ 79,022 $ 32,492 Change in unrealized gains relating to instruments still held at end of period $ 48,938 $ 32,150 (1) Does not include the decrease in fair value of $0.7 million related to the realized gains capitalized during the year ended December 31, 2016 . 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. 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 SPL Interest Rate Derivatives SPL has entered into interest rate swaps (“SPL Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “2015 SPL Credit Facilities”) . The SPL Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities . In March 2015, SPL settled a portion of the SPL Interest Rate Derivatives and recognized a derivative loss of $34.7 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments under the previous credit facilities. CQP Interest Rate Derivatives In March 2016, we entered into interest rate swaps (“CQP Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2016 CQP Credit Facilities . The CQP Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities . As of December 31, 2016 , we had the following Interest Rate Derivatives outstanding: Initial Notional Amount Maximum Notional Amount Effective Date Maturity Date Weighted Average Fixed Interest Rate Paid Variable Interest Rate Received SPL Interest Rate Derivatives $20.0 million $628.8 million August 14, 2012 July 31, 2019 1.98% One-month LIBOR CQP Interest Rate Derivatives $225.0 million $1.3 billion March 22, 2016 February 29, 2020 1.19% One-month LIBOR The following table (in thousands) shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets: December 31, 2016 December 31, 2015 SPL Interest Rate Derivatives CQP Interest Rate Derivatives Total SPL Interest Rate Derivatives CQP Interest Rate Derivatives Total Balance Sheet Location Non-current derivative assets $ — $ 16,073 $ 16,073 $ — $ — $ — Derivative liabilities (4,223 ) (2,965 ) (7,188 ) (5,940 ) — (5,940 ) Non-current derivative liabilities (2,001 ) — (2,001 ) (2,800 ) — (2,800 ) Total derivative liabilities (6,224 ) (2,965 ) (9,189 ) (8,740 ) — (8,740 ) Derivative asset (liability), net $ (6,224 ) $ 13,108 $ 6,884 $ (8,740 ) $ — $ (8,740 ) The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2016, 2015 and 2014 : Year Ended December 31, 2016 2015 2014 SPL Interest Rate Derivatives loss $ (5,934 ) $ (41,722 ) $ (119,401 ) CQP Interest Rate Derivatives gain 11,478 — — Commodity Derivatives Liquefaction Supply Derivatives SPL has entered into 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 primarily range from approximately one to seven years and commence upon the satisfaction of certain conditions precedent, including but not limited to the date of first commercial delivery of specified Trains of the Liquefaction Project . We recognize our Physical Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Physical Liquefaction Supply Derivatives are reported in earnings. As of December 31, 2016 , SPL has secured up to approximately 1,993.9 million MMBtu of natural gas feedstock through natural gas supply contracts. The notional natural gas position of our Physical Liquefaction Supply Derivatives was approximately 1,111.4 million MMBtu as of December 31, 2016 . 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. The notional natural gas position of our Financial Liquefaction Supply Derivatives was approximately 5.6 million MMBtu as of December 31, 2016 . Natural Gas Derivatives Our Natural Gas Derivatives were executed through over-the-counter contracts which were subject to nominal credit risk as these transactions settled on a daily margin basis with investment grade financial institutions. We were required by these financial institutions to use margin deposits as credit support for our Natural Gas Derivatives activities. As of December 31, 2016 , we did not have any open Natural Gas Derivatives positions or margin deposits at financial institutions. We recognize all commodity derivative instruments that qualify for derivative accounting treatment, including our Liquefaction Supply Derivatives and our Natural Gas Derivatives (collectively, “Commodity Derivatives”) , as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Commodity Derivatives are reported in earnings. The following table (in thousands) shows the fair value and location of our Commodity Derivatives on our Consolidated Balance Sheets: December 31, 2016 December 31, 2015 Liquefaction Supply Derivatives (1) Natural Gas Derivatives Total Liquefaction Supply Derivatives Natural Gas Derivatives (2) Total Balance Sheet Location Other current assets $ 13,535 $ — $ 13,535 $ 2,737 $ 39 $ 2,776 Non-current derivative assets 66,788 — 66,788 30,304 — 30,304 Total derivative assets 80,323 — 80,323 33,041 39 33,080 Derivative liabilities (7,258 ) — (7,258 ) (490 ) — (490 ) Non-current derivative liabilities — — — (84 ) — (84 ) Total derivative liabilities (7,258 ) — (7,258 ) (574 ) — (574 ) Derivative asset, net $ 73,065 $ — $ 73,065 $ 32,467 $ 39 $ 32,506 (1) Does not include collateral of $6.0 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2016 . (2) Does not include collateral of $0.4 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015 . The following table (in thousands) shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2016, 2015 and 2014 : Year Ended December 31, Statement of Operations Location (1) 2016 2015 2014 Liquefaction Supply Derivatives loss LNG revenues $ (8 ) $ — $ — Liquefaction Supply Derivatives gain (2) Cost (cost recovery) of sales (42,172 ) (32,503 ) (342 ) Natural Gas Derivatives loss LNG revenues — — (31 ) Natural Gas Derivatives gain Operating and maintenance expense (174 ) (2,065 ) (1,389 ) (1) Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument. (2) Does not include the realized value associated with derivative instruments that settle through physical delivery. The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our Commodity Derivatives are in an asset position. Balance Sheet Presentation Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross and net basis: Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets (Liabilities) As of December 31, 2016 SPL Interest Rate Derivatives $ (6,229 ) $ 5 $ (6,224 ) CQP Interest Rate Derivatives 16,073 — 16,073 CQP Interest Rate Derivatives (3,020 ) 55 (2,965 ) Liquefaction Supply Derivatives 82,116 (1,793 ) 80,323 Liquefaction Supply Derivatives (11,078 ) 3,820 (7,258 ) As of December 31, 2015 SPL Interest Rate Derivatives $ (8,740 ) $ — $ (8,740 ) Liquefaction Supply Derivatives 33,636 (595 ) 33,041 Liquefaction Supply Derivatives (574 ) — (574 ) Natural Gas Derivatives 188 (149 ) 39 |
Other Non-Current Assets
Other Non-Current Assets | 12 Months Ended |
Dec. 31, 2016 | |
Other Assets, Noncurrent [Abstract] | |
Other Non-Current Assets | OTHER NON-CURRENT ASSETS As of December 31, 2016 and 2015 , other non-current assets consisted of the following (in thousands): December 31, 2016 2015 Advances made under EPC and non-EPC contracts $ 22,809 $ 32,049 Advances made to municipalities for water system enhancements 95,495 89,953 Advances and other asset conveyances to third parties to support LNG terminals 30,707 28,850 Tax-related payments and receivables 27,781 27,615 Information technology service assets 27,416 30,371 Other 18,120 23,193 Total other non-current assets, net $ 222,328 $ 232,031 |
Accrued Liabilities
Accrued Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Accrued Liabilities, Current [Abstract] | |
Accrued Liabilities | ACCRUED LIABILITIES As of December 31, 2016 and 2015 , accrued liabilities consisted of the following (in thousands): December 31, 2016 2015 Interest costs and related debt fees $ 205,312 $ 150,336 Sabine Pass LNG terminal and related pipeline costs 210,670 70,924 Other accrued liabilities 1,520 3,032 Total accrued liabilities $ 417,502 $ 224,292 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt | DEBT As of December 31, 2016 and 2015, our debt consisted of the following (in thousands): December 31, 2016 2015 Long-term debt: SPLNG 6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) $ — $ 420,000 SPL 5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7,181 and $8,718 2,007,181 2,008,718 6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”) 1,000,000 1,000,000 5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5,657 and $6,392 1,505,657 1,506,392 5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”) 2,000,000 2,000,000 5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”) 2,000,000 2,000,000 5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”) 1,500,000 — 5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”) 1,500,000 — 2015 SPL Credit Facilities 314,000 845,000 CTPL $400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429 — 398,571 Cheniere Partners 2016 CQP Credit Facilities 2,560,000 — Unamortized debt issuance costs (1) (177,609 ) (160,356 ) Total long-term debt, net 14,209,229 10,018,325 Current debt: 7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of zero and $4,303 — 1,661,197 $1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”) 223,500 15,000 Unamortized debt issuance costs (1) — (2,818 ) Total current debt, net 223,500 1,673,379 Total debt, net $ 14,432,729 $ 11,691,704 (1) Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $160.4 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015 . 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, 2016 (in thousands): Years Ending December 31, Principal Payments 2017 $ 223,500 2018 — 2019 — 2020 2,874,000 2021 2,000,000 Thereafter 9,500,000 Total $ 14,597,500 Senior Notes SPLNG Senior Notes In November 2016, SPLNG repaid the 2016 SPLNG Senior Notes and redeemed all of the outstanding 2020 SPLNG Senior Notes at a price equal to 103.250% of the principal amount of the 2020 SPLNG Senior Notes . SPL Senior Notes The terms of the 2021 SPL Senior Notes , 2022 SPL Senior Notes , 2023 SPL Senior Notes , 2024 SPL Senior Notes , 2025 SPL Senior Notes , 2026 SPL Senior Notes and the 2027 SPL Senior Notes (collectively, the “SPL Senior Notes”) are governed by a common indenture (the “SPL Indenture”) , and interest on the SPL Senior Notes is payable semi-annually in arrears. The SPL Indenture contains customary terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to: incur additional indebtedness; issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness; purchase, redeem or retire capital stock; sell or transfer assets, including capital stock of SPL’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; incur liens; enter into transactions with affiliates; consolidate, merge, sell or lease all or substantially all of SPL’s assets; and enter into certain LNG sales contracts. See Note 18—Subsequent Events for additional information regarding covenants under the SPL Indenture . Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL 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 for the prior 12 -month period and a projected debt service coverage ratio for the upcoming 12-month period of 1.25 :1.00 are satisfied. At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes and 2027 SPL Senior Notes , in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price set forth in the SPL Indenture , plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes and 2027 SPL Senior Notes , in which case the time period is six months before the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption. In connection with the issuance of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes , SPL entered into registration rights agreements (the “SPL Registration Rights Agreements”) . Under the terms of the SPL Registration Rights Agreements , SPL has agreed, and any future guarantors will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective registration statements relating to offers to exchange any and all of the 2026 SPL Senior Notes and 2027 SPL Senior Notes for like aggregate principal amounts of debt securities of SPL with terms identical in all material respects to the respective senior notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after June 14, 2016 and September 23, 2016, respectively. Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective shelf registration statements relating to resales of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes . SPL will be obligated to pay additional interest on these senior notes if it fails to comply with its obligation to register them within the specified time period. Credit Facilities Below is a summary of our credit facilities outstanding as of December 31, 2016 (in thousands): 2015 SPL Credit Facilities SPL Working Capital Facility 2016 CQP Credit Facilities Original facility size $ 4,600,000 $ 1,200,000 $ 2,800,000 Outstanding balance 314,000 223,500 2,560,000 Commitments prepaid or terminated 2,643,867 — — Letters of credit issued — 323,677 45,000 Available commitment $ 1,642,133 $ 652,823 $ 195,000 Interest rate LIBOR plus 1.30% - 1.75% or base rate plus 1.75% LIBOR plus 1.75% or base rate plus 0.75% LIBOR plus 2.25% or base rate plus 1.25% (1) Maturity date Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date December 31, 2020, with various terms for underlying loans February 25, 2020, with principals due quarterly commencing on February 19, 2019 (1) There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019. 2015 SPL Credit Facilities In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion . The 2015 SPL Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project . Borrowings under the 2015 SPL Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. During 2016, in conjunction with the issuance of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes , SPL prepaid outstanding borrowings and terminated commitments under the 2015 SPL Credit Facilities for approximately $2.6 billion . These prepayments and termination of commitments resulted in a write-off of debt issuance costs and payment of fees associated with the 2015 SPL Credit Facilities of $52.2 million during the year ended December 31, 2016 . Loans under the 2015 SPL Credit Facilities accrue interest at a variable rate per annum equal to, at SPL’s election, LIBOR or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.30% to 1.75% , depending on the applicable 2015 SPL Credit Facility , and the applicable margin for base rate loans is 1.75% . Interest on LIBOR loans is due and payable at the end of each LIBOR period and interest on base rate loans is due and payable at the end of each quarter. In addition, SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 SPL Credit Facilities . The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee calculated at a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility . The principal of the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project . Scheduled repayments are based upon an 18 -year amortization profile, with the remaining balance due upon the maturity of the 2015 SPL Credit Facilities . The 2015 SPL Credit Facilities contain conditions precedent for borrowings, as well as customary affirmative and negative covenants. The obligations of SPL under the 2015 SPL Credit Facilities are secured by substantially all of the assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and the SPL Working Capital Facility . Under the terms of the 2015 SPL Credit Facilities , SPL is required to hedge not less than 65% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. Additionally, SPL may not make any distributions until certain conditions have been met, including that deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25 :1.00 is satisfied. SPL Working Capital Facility In September 2015, SPL entered into the SPL Working Capital Facility , which is intended to be used for loans to SPL (“Working Capital Loans”) , the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“Swing Line Loans”) , primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project . SPL may, from time to time, request increases in the commitments under the SPL 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 SPL 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 SPL Working Capital Facility is 1.75% per annum, and the applicable margin for base rate loans under the SPL 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. SPL pays (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 SPL Working Capital Facility . If draws are made upon a letter of credit issued under the SPL Working Capital Facility and SPL does not elect for such draw (an “LC Draw”) to be deemed an LC Loan, SPL is 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, 2016 , no LC Draw s had been made upon any letters of credit issued under the SPL Working Capital Facility . The SPL 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 SPL 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. SPL is 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 SPL Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of SPL under the SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and the 2015 SPL Credit Facilities . 2016 CQP Credit Facilities In February 2016, we entered into the $2.8 billion 2016 CQP Credit Facilities , which consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 million CTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that was used to repay and redeem the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes in November 2016, (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six -month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes. The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0% ), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter. We incurred $73.1 million of debt issuance costs related to the 2016 CQP Credit Facilities during the year ended December 31, 2016 . The prepayment of the CTPL Term Loan and the redemption of the 2020 SPLNG Senior Notes resulted in a write-off of unamortized discount and debt issuance costs and redemption premium of $19.6 million during the year ended December 31, 2016 . We pay a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019. The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit our ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the terms of the 2016 CQP Credit Facilities , we are required to hedge not less than 50% of the variable interest rate exposure on its projected aggregate outstanding balance, maintain a minimum debt service coverage ratio of at least 1.15 x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55 x in order to incur additional indebtedness to refinance a portion of the existing obligations. The 2016 CQP Credit Facilities are unconditionally guaranteed by each of our subsidiaries other than SPL and certain of our subsidiaries owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities. Interest Expense Total interest expense consisted of the following (in thousands): Year Ended December 31, 2016 2015 2014 Total interest cost $ 841,022 $ 707,724 $ 580,236 Capitalized interest (484,122 ) (523,124 ) (403,204 ) Total interest expense, net $ 356,900 $ 184,600 $ 177,032 Fair Value Disclosures The following table (in thousands) shows the carrying amount and estimated fair value of our debt: December 31, 2016 December 31, 2015 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior Notes, net of premium or discount (1) $ 11,512,838 $ 12,308,736 $ 10,596,307 $ 9,525,809 CTPL Term Loan, net of discount (2) — — 398,571 400,000 Credit facilities (2) (3) 3,097,500 3,097,500 860,000 860,000 (1) Includes 2016 SPLNG Senior Notes , 2020 SPLNG Senior Notes and SPL Senior Notes (collectively, the “Senior Notes”) . The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the Senior Notes and other similar instruments. (2) The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. (3) Includes 2015 SPL Credit Facilities , SPL Working Capital Facility and 2016 CQP Credit Facilities . |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014 (in thousands): Year Ended December 31, 2016 2015 2014 LNG revenues—affiliate Cheniere Marketing SPA and Cheniere Marketing Master SPA $ 293,957 $ — $ — Regasification revenues—affiliate Contracts for Sale and Purchase of Natural Gas and LNG 918 672 3 Tug Boat Lease Sharing Agreement 2,867 2,792 2,800 Other agreements — 927 155 Total regasification revenues—affiliate 3,785 4,391 2,958 Cost of sales—affiliate Fees under the Pre-commercial LNG Marketing Agreement 1,490 — — Operating and maintenance expense—affiliate Contracts for Sale and Purchase of Natural Gas and LNG 607 1,121 — Services Agreements 51,579 28,267 21,164 Other agreements (49 ) (9 ) (49 ) Total operating and maintenance expense—affiliate 52,137 29,379 21,115 Development expense—affiliate Services Agreements 396 722 1,153 General and administrative expense—affiliate Services Agreements 89,523 122,312 101,369 LNG Terminal Capacity Agreements Terminal Use Agreements SPL obtained approximately 2.0 Bcf/d of regasification capacity under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”) , continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project . In connection with this TUA , SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is recorded as operating and maintenance expense on our Consolidated Statements of Operations. Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments has the right to use SPL’s reserved capacity under the TUA and has the obligation to pay the TUA Fees required by the TUA to SPLNG. However, the revenue earned by SPLNG from the TUA Fees and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our Financial Statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA . In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project , Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing during the years ended December 31, 2016, 2015 and 2014 , respectively, related to the Amended and Restated VCRA . Cheniere Marketing SPA Cheniere Marketing has entered into an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL 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 In May 2015, SPL entered into an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement. Commissioning Confirmation In May 2015, under the Cheniere Marketing Master SPA, SPL executed a confirmation with Cheniere Marketing that obligates Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) has control of, and is commissioning, the first four Trains of the Liquefaction Project . Pre-commercial LNG Marketing Agreement In May 2015, SPL entered into an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell certain quantities of pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC, one of SPL’s SPA customers. SPL pays a fee to Cheniere Marketing for marketing and transportation, which is based on volume sold under this agreement. Services Agreements As of December 31, 2016 and 2015 , we had $37.7 million and $39.8 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under the services agreements described below are recorded in general and administrative expense—affiliate. Cheniere Partners Services Agreement We have entered into a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $2.8 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement. Cheniere Investments Information Technology Services Agreement Cheniere Investments has entered into an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere 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. SPLNG O&M Agreement SPLNG has entered into a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SPLNG incurs a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between SPLNG and Cheniere Investments at the beginning of each operating year. In addition, SPLNG incurs costs to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the SPLNG O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to such subsidiary. SPLNG MSA SPLNG has entered into a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the SPLNG O&M Agreement . SPLNG incurs a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA . SPL O&M Agreement SPL has entered into an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments pursuant to which SPL receives all of the necessary services required to construct, operate and maintain the Liquefaction Project . Before the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on behalf of SPL, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After the Liquefaction Project is operational, the services include all necessary services required to operate and maintain the Liquefaction Project . Before the Liquefaction Project is operational, in addition to reimbursement of operating expenses, SPL is 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 Liquefaction Project is operational, SPL 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 such Train. Cheniere Investments provides the services required under the SPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPL O&M Agreement are required to be remitted to such subsidiary. SPL MSA SPL has entered into a management services agreement (the “SPL 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 SPL O&M Agreement . The services include, among other services, exercising the day-to-day management of SPL’s affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s business and operations, entering into financial derivatives on SPL’s behalf and providing contract administration services for all contracts associated with the Liquefaction Project . Under the SPL MSA , SPL pays a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train. CTPL O&M Agreement CTPL has entered into an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline . CTPL is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M Agreement are required to be remitted to such subsidiary. CTPL MSA CTPL has entered into a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the modification and operation of the Creole Trail Pipeline , excluding those matters provided for under the CTPL O&M Agreement . The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations and providing contract administration services for all contracts associated with the pipeline facilities. Under the CTPL MSA , CTPL pays a monthly fee equal to 3.0% of the capital expenditures to enable bi-directional natural gas flow on the Creole Trail Pipeline incurred in the previous month. Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”) SPLNG has executed CEAs with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten -year initiative represented an aggregate commitment of $24.5 million in order to aid in their reconstruction efforts following Hurricane Rita, which SPLNG fulfilled in the first quarter of 2016. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs . In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to, and in the year the Cameron Parish dollar-for-dollar credit is applied against, ad valorem tax levied on our LNG terminal. On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of December 31, 2016 and 2015 , we had $24.5 million and $22.1 million , respectively, of both other non-current assets resulting from SPLNG’s ad valorem tax payments and non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing. Contracts for Sale and Purchase of Natural Gas and LNG SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal. Tug Boat Lease Sharing Agreement In connection with its tug boat lease, Tug Services entered into a tug sharing agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. LNG Terminal Export Agreement In January 2010, SPLNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal. SPLNG did no t record any revenues associated with this agreement during the years ended December 31, 2016, 2015 and 2014 . State Tax Sharing Agreements In November 2006, SPLNG entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG 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, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its 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 SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008. In August 2012, SPL entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPL 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, SPL will pay to Cheniere an amount equal to the state and local tax that SPL would be required to pay if SPL’s 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 SPL under this agreement; therefore, Cheniere has not demanded any such payments from SPL. The agreement is effective for tax returns due on or after August 2012. In May 2013, CTPL entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL 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, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s 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 CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
Leases | LEASES During the years ended December 31, 2016, 2015 and 2014 , we recognized rental expense for all operating leases of $11.1 million , $10.5 million and $10.5 million , respectively, related primarily to office space and land sites. Our land site leases for the Sabine Pass LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years . Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands): Years Ending December 31, Operating Leases (1) 2017 $ 2,308 2018 2,262 2019 2,262 2020 2,262 2021 2,239 Thereafter 45,372 Total $ 56,705 (1) Includes certain lease option renewals that are reasonably assured . |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2016 , are not recognized as liabilities but require disclosures in our Consolidated Financial Statements. LNG Terminal Commitments and Contingencies Obligations under EPC Contracts SPL has entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 3 through 5 of the Liquefaction Project . The EPC contract for Trains 3 and 4 and the EPC contract for Train 5 provide that SPL will pay Bechtel contract prices of $3.9 billion and $3.0 billion , respectively, subject to adjustment by change order. SPL has the right to terminate each EPC contract for its 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 $30.0 million depending on the termination date. Obligations under SPAs SPL has entered into third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver 401.5 million MMBtu per year of LNG to the customers’ vessels for Trains 1 and 2 of the Liquefaction Project and 628.5 million MMBtu per year of LNG for Trains 3 through 5 of the Liquefaction Project , subject to completion of construction. Obligations under LNG TUAs SPLNG has entered into third-party TUAs with Total Gas & Power North America, Inc. and Chevron U.S.A. Inc. to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal. Obligations under Natural Gas Supply, Transportation and Storage Service Agreements SPL has entered into index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project . The terms of these contracts primarily range from approximately one to six years and commence upon the occurrence of conditions precedent, including SPL’s declaration to the respective natural gas supplier that it is ready to commence the term of the supply arrangement in anticipation of the date of first commercial operation of the applicable, specified Trains of the Liquefaction Project . As of December 31, 2016 , SPL has secured up to approximately 1,993.9 MMBtu of natural gas feedstock through natural gas supply contracts, of which we determined that we have purchase obligations for the contracts for which conditions precedent were met. Additionally, SPL has entered into transportation and storage service agreements for the Liquefaction Project . The initial term of the transportation agreements ranges from 10 to 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The term of the SPL storage service agreements ranges from three to ten years. As of December 31, 2016 , SPL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in thousands): Years Ending December 31, Payments Due (1) 2017 $ 1,611,296 2018 1,192,791 2019 1,019,309 2020 1,055,497 2021 903,425 Thereafter 2,169,912 Total $ 7,952,230 (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, 2016 . Services Agreements We have entered into certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements. Restricted Net Assets At December 31, 2016 , our restricted net assets of consolidated subsidiaries were approximately $2.6 billion . Other Commitments State Tax Sharing Agreements SPLNG, SPL and CTPL have entered into state tax sharing agreements with Cheniere. See Note 12—Related Party Transactions for information regarding such agreements. Other Agreements In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. 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, 2016 , 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. |
Net Loss per Common Unit
Net Loss per Common Unit | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Net Loss per Common Unit | NET LOSS PER COMMON UNIT Net loss per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net loss based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statements of Partners’ Equity. On January 20, 2017 , we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on February 13, 2017 to unitholders of record as of February 2, 2017 for the period from October 1, 2016 to December 31, 2016 . The two-class method dictates that net income (loss) for a period be reduced by the amount of available cash that will be distributed with respect to that period and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and other participating securities on a pro rata basis based on provisions of the partnership agreement. Historical income (loss) attributable to a company that was purchased from an entity under common control is allocated to the predecessor owner in accordance with the terms of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings. The Class B units were issued at a discount to the market price of the common units into which they are convertible. This discount, totaling $2,130.0 million , represents a beneficial conversion feature and is reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statements of Partners’ Equity. The beneficial conversion feature is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortize the beneficial conversion feature assuming a conversion date of August 2017 for Cheniere Holdings’ and Blackstone CQP Holdco ’s Class B units , although actual conversion may occur prior to or after these assumed dates. We are amortizing using the effective yield method with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone CQP Holdco ’s Class B units , respectively. The impact of the beneficial conversion feature is also included in earnings per unit for the years ended December 31, 2016, 2015 and 2014 . Based on the capital structure as of December 31, 2016 , the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature is as follows in 2017 (in thousands): Common Units Class B Units Subordinated Units $(594,470) $2,004,209 $(1,409,739) Under our partnership agreement, the IDR s participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDR s from participating in undistributed net income (loss). We did not allocate earnings or losses to IDR holders for the purpose of the two-class method earnings per unit calculation for any of the periods presented. The following table (in thousands, except per unit data) provides a reconciliation of net loss and the allocation of net loss to the common units, the subordinated units and the general partner units for purposes of computing net loss per unit. Limited Partner Units Total Common Units Class B Units Subordinated Units General Partner Units Year Ended December 31, 2016 Net loss $ (171,195 ) Declared distributions 99,028 97,047 — — 1,981 Amortization of beneficial conversion feature of Class B units — (29,801 ) 100,472 (70,671 ) — Assumed allocation of undistributed net loss $ (270,223 ) (78,547 ) — (186,271 ) (5,404 ) Assumed allocation of net income (loss) $ (11,301 ) $ 100,472 $ (256,942 ) $ (3,423 ) Weighted average units outstanding 57,086 145,333 135,384 Net loss per unit $ (0.20 ) $ (1.90 ) Year Ended December 31, 2015 Net loss $ (318,891 ) Declared distributions 99,018 97,038 — — 1,980 Assumed allocation of undistributed net loss $ (417,909 ) (121,468 ) — (288,083 ) (8,358 ) Assumed allocation of net loss $ (24,430 ) $ — $ (288,083 ) $ (6,378 ) Weighted average units outstanding 57,081 145,333 135,384 Net loss per unit $ (0.43 ) $ (2.13 ) Year Ended December 31, 2014 Net loss $ (410,036 ) Declared distributions 99,015 97,036 — — 1,979 Assumed allocation of undistributed net loss $ (509,051 ) (147,952 ) — (350,918 ) (10,181 ) Assumed allocation of net loss $ (50,916 ) $ — $ (350,918 ) $ (8,202 ) Weighted average units outstanding 57,079 145,333 135,384 Net loss per unit $ (0.89 ) $ (2.59 ) |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | SUPPLEMENTAL CASH FLOW INFORMATION The following table (in thousands) provides supplemental disclosure of cash flow information: Year Ended December 31, 2016 2015 2014 Cash paid during the period for interest, net of amounts capitalized $ 242,005 $ 135,836 $ 130,578 Non-cash conveyance of assets — 13,169 — The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $267.1 million , $230.7 million and $124.7 million as of December 31, 2016 , 2015 and 2014 , respectively. |
Recent Accounting Standards
Recent Accounting Standards | 12 Months Ended |
Dec. 31, 2016 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recent Accounting Standards | RECENT ACCOUNTING STANDARDS The following table provides a brief description of recent accounting standards that had not been adopted by the Partnership as of December 31, 2016 : Standard Description Expected Date of Adoption Effect on our Consolidated 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 continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we plan to adopt this standard using the full retrospective approach and we do not currently anticipate that the adoption will have a material impact upon our revenues. The Financial Accounting Standards Board (the “FASB”) has issued and may issue in the future amendments and interpretive guidance which may cause our evaluation to change. Furthermore, we routinely enter into new contracts and we cannot predict with certainty whether the accounting for any future contract under the new standard would result in a significant change from existing guidance. Because this assessment is preliminary and the accounting for revenue recognition is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact that recognizing fulfillment costs as assets will have on our Consolidated Financial Statements. ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively. January 1, 2017 The adoption of this guidance will not have a material impact on our Consolidated Financial Statements or related disclosures. ASU 2016-02, Leases (Topic 842) 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 must be adopted using a modified retrospective approach with certain available practical expedients. January 1, 2019 We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, whether we will elect to early adopt this standard or which, if any, practical expedients we will elect upon transition. Standard Description Expected Date of Adoption Effect on our Consolidated Financial Statements or Other Significant Matters 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 We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures. Additionally, the following table provides a brief description of recent accounting standards that were adopted by the Partnership during the reporting period: Standard Description Date of Adoption Effect on our Consolidated Financial Statements or Other Significant Matters ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis These amendments primarily affect asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. January 1, 2016 The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures. ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements These standards require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented. January 1, 2016 Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 11—Debt for additional disclosures. Standard Description Date of Adoption Effect on our Consolidated Financial Statements or Other Significant Matters ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions This standard requires a master limited partnership to allocate net income (losses) of a transferred business entirely to the general partner when computing earnings per unit for periods before the dropdown transaction occurred. This guidance also requires a master limited partnership to disclose the effects of the dropdown transaction on net income (losses) per unit for the periods before and after the dropdown transaction occurred. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented. January 1, 2016 The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures. ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern This standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted. December 31, 2016 The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures. ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) This standard requires an entity to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented. December 31, 2016 As a result of adopting this standard, our Consolidated Statements of Cash Flows now reconciles the balance of total cash, cash equivalents and restricted cash from the beginning of the period to the end of the period. This resulted in changes to previously reported cash flows from operating, investing and financing activities. ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business This standard narrows the accounting definition of a business and clarifies that when substantially all of the fair value of an integrated set of assets and activities is concentrated in a single asset or a group of similar assets, the integrated set of assets and activities is not a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill and consolidation. This guidance may be early adopted and must be adopted prospectively. December 31, 2016 The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS SPL Senior Notes In January 2017, SPL was assigned a second investment grade rating on its senior secured notes by rating agencies. As a result, certain covenants, including those that limit SPL’s ability to make certain investments, under the SPL Indenture are no longer applicable. SPL Private Placement Notes In February 2017, SPL entered into a Note Purchase Agreement with various purchasers to issue and sell $800 million aggregate principal amount of 5.00% senior secured notes due 2037 in a private placement conducted pursuant to Section 4(a)(2) of the Securities Act. |
Summarized Quarterly Financial
Summarized Quarterly Financial Information (unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data (unaudited) | Summarized Quarterly Financial Data—(in thousands, except per unit amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2016: Revenues $ 67,047 $ 151,171 $ 331,409 $ 550,613 Income (loss) from operations (9,463 ) 12,594 47,898 199,407 Net income (loss) (74,906 ) (100,125 ) (81,509 ) 85,345 Basic net income (loss) per common unit (1) $ (0.08 ) $ (0.21 ) $ (0.27 ) $ 0.07 Diluted net income (loss) per common unit (1) $ (0.08 ) $ (0.21 ) $ (0.27 ) $ 0.07 Year ended December 31, 2015: Revenues $ 67,530 $ 67,689 $ 67,537 $ 67,272 Income (loss) from operations (9,822 ) (4,318 ) 35,921 (18,739 ) Net loss (178,676 ) (60,043 ) (24,132 ) (56,040 ) Basic net income (loss) per common unit (1) $ (0.61 ) $ (0.01 ) $ 0.18 $ 0.01 Diluted net loss per common unit (1) $ (0.61 ) $ (0.01 ) $ (0.03 ) $ (0.09 ) (1) The sum of the quarterly net income (loss) per common unit may not equal the full year amount as the undistributed income and loss allocations and computations of the weighted average common units outstanding for basic and diluted common units outstanding for each quarter and the full year are performed independently. |
Schedule I_Condensed Financial
Schedule I—Condensed Financial Information of Registrant | 12 Months Ended |
Dec. 31, 2016 | |
Parent Company [Member] | |
Condensed Financial Statements, Captions [Line Items] | |
Schedule I—Condensed Financial Information of Registrant | SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT CHENIERE ENERGY PARTNERS, L.P. CONDENSED BALANCE SHEETS (in thousands) December 31, 2016 2015 ASSETS Current assets Cash and cash equivalents $ — $ 109,950 Restricted cash 234,407 — Prepaid expenses and other 447 187 Total current assets 234,854 110,137 Property, plant and equipment, net 78,789 58,410 Debt issuance and deferred financing costs, net 62,048 — Investment in affiliates 2,616,985 544,589 Non-current derivative assets 16,073 — Other non-current assets 45 953 Total assets $ 3,008,794 $ 714,089 LIABILITIES AND PARTNERS’ EQUITY Current liabilities Derivative liabilities $ 2,965 $ — Other current liabilities 2,775 1,158 Total current liabilities 5,740 1,158 Long-term debt 2,560,000 — Partners’ equity 443,054 712,931 Total liabilities and partners’ equity $ 3,008,794 $ 714,089 The accompanying notes are an integral part of these condensed financial statements. CHENIERE ENERGY PARTNERS, L.P. CONDENSED STATEMENTS OF OPERATIONS (in thousands) Year Ended December 31, 2016 2015 2014 Operating costs and expenses Operating and maintenance expense $ 5,326 $ 2,905 $ — General and administrative expense 3,927 2,760 3,383 General and administrative expense—affiliate 11,704 11,546 11,556 Depreciation and amortization expense 632 72 — Total operating costs and expenses 21,589 17,283 14,939 Other income (expense) Interest expense, net of capitalized interest (22,858 ) — — Derivative gain, net 11,478 — — Other income 351 173 162 Equity loss of affiliates (138,577 ) (301,781 ) (395,259 ) Total other expense (149,606 ) (301,608 ) (395,097 ) Net loss $ (171,195 ) $ (318,891 ) $ (410,036 ) The accompanying notes are an integral part of these condensed financial statements. CHENIERE ENERGY PARTNERS, L.P. CONDENSED STATEMENTS OF CASH FLOWS (in thousands) Year Ended December 31, 2016 2015 2014 Cash flows used in operating activities $ (52,488 ) $ (43,723 ) $ (40,948 ) Cash flows from investing activities Property, plant and equipment, net — (671 ) — Investments in subsidiaries (2,428,967 ) 12,832 (61,350 ) Distributions received from affiliates, net 217,994 18,400 108,625 Net cash provided by (used in) investing activities (2,210,973 ) 30,561 47,275 Cash flows from financing activities Proceeds from issuance of debt 2,560,000 — — Debt issuance and deferred financing costs (73,060 ) — — Distributions to owners (99,025 ) (99,018 ) (98,979 ) Other 3 — — Net cash provided by (used in) financing activities 2,387,918 (99,018 ) (98,979 ) Net increase (decrease) in cash, cash equivalents and restricted cash 124,457 (112,180 ) (92,652 ) Cash, cash equivalents and restricted cash—beginning of period 109,950 222,130 314,782 Cash, cash equivalents and restricted cash—end of period $ 234,407 $ 109,950 $ 222,130 Balances per Condensed Balance Sheets: December 31 2016 2015 2014 Cash and cash equivalents $ — $ 109,950 $ 222,130 Restricted cash 234,407 — — Total cash, cash equivalents and restricted cash $ 234,407 $ 109,950 $ 222,130 The accompanying notes are an integral part of these condensed financial statements. CHENIERE ENERGY PARTNERS, L.P. NOTES TO CONDENSED FINANCIAL STATEMENTS NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The Condensed Financial Statements represent the financial information required by Securities and Exchange Commission Regulation S-X 5-04 for Cheniere Partners. A substantial amount of Cheniere Partners’ operating, investing and financing activities are conducted by its affiliates. In the Condensed Financial Statements, Cheniere Partners’ investments in affiliates are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are recorded on the Condensed Balance Sheets. The gain (loss) from operations of the affiliates is reported on a net basis as equity loss of affiliates. The Condensed Financial Statements should be read in conjunction with Cheniere Partners’ Consolidated Financial Statements. NOTE 2—SUPPLEMENTAL CASH FLOW INFORMATION The following table provides supplemental disclosure of cash flow information (in thousands): Year Ended December 31, 2016 2015 2014 Non-cash capital contributions (1) $ 138,577 $ 301,781 $ 395,259 (1) Amounts represent equity loss of affiliates not funded by Cheniere Partners. |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation, Policy | Basis of Presentation Our Consolidated Financial Statements have been prepared in accordance with GAAP . The Consolidated Financial Statements include the accounts of Cheniere Energy Partners, L.P. and its majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall consolidated financial position, operating results or cash flows. In 2016, we started production at the Liquefaction Project . As a result, we introduced a new line item entitled “cost of sales” and modified the components of activity included in “operating and maintenance expense” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made to the prior periods. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the Liquefaction Project , and other costs related to converting natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense. Operating and maintenance expense now includes costs associated with operating and maintaining the Liquefaction Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs. Additionally, we distinguished and reclassified our historical “revenues” line item into “LNG revenues” and “regasification revenues.” LNG revenues include fees that are received pursuant to our SPAs and related LNG marketing activities. Regasification revenues include LNG regasification capacity reservation fees that are received pursuant to our TUAs and tug services fees that are received by Sabine Pass Tug Services, LLC (“ Tug Services ”), a wholly owned subsidiary of SPLNG. |
Use of Estimates, Policy | Use of Estimates The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, collectability of accounts receivable, 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 techniques 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 8—Derivative Instruments . The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 11—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 Fees received pursuant to SPAs are recognized as LNG revenues 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. LNG revenues are recognized when LNG is delivered to the counterparty, either at the Sabine Pass LNG terminal or at the counterparty’s LNG receiving terminal, based on the terms of the contract. LNG regasification capacity reservation fees are recognized as regasification revenues over the term of the respective TUAs. Advance capacity reservation fees are initially deferred and amortized over a 10 -year period as a reduction of a customer’s regasification capacity reservation fees payable under its TUA. Under each of these TUAs, SPLNG is entitled to retain 2% of LNG delivered for each customer’s account at the Sabine Pass LNG terminal, which is recognized as revenue as SPLNG performs the services set forth in each customer’s TUA. |
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 Consolidated 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 bad debt expense related to accounts receivable during the years ended December 31, 2016, 2015 and 2014 . |
Inventory, Policy | Inventory LNG and natural gas inventory are recorded at weighted average cost and materials and other inventory are recorded at cost. Inventory is subject to lower of cost or market (“LCM”) adjustments at the end of each period. Our LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal that are recorded in operating and maintenance expense on our Consolidated Statements of Operations. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price recoveries occur on the same inventory in the same fiscal year. These recoveries are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. During the years ended December 31, 2016 , 2015 and 2014 , we recognized zero , $17.5 million , and $24.5 million , respectively, as operating and maintenance expense as a result of LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. |
Accounting for LNG Activities, Policy | Accounting for LNG Activities Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals and related pipelines. 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 lease is obtained, the costs are expensed. We capitalize interest and other related debt costs during the construction period of our LNG terminal and related pipeline. Upon commencement of operations, capitalized interest, as a component of the total cost, is amortized over the estimated useful life of the asset. |
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 and general and administrative activities are charged to expense as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. 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 other operating costs and expenses. Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We recorded $0.4 million , zero and zero impairments related to property, plant and equipment during the years ended December 31, 2016, 2015 and 2014 , respectively. |
Regulated Natural Gas Pipelines, Policy | Regulated Natural Gas Pipelines The Creole Trail Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities. Items that may influence our assessment are: • inability to recover cost increases due to rate caps and rate case moratoriums; • inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings; • excess capacity; • increased competition and discounting in the markets we serve; and • impacts of ongoing regulatory initiatives in the natural gas industry. Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service. |
Derivative Instruments, Policy | Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria 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 current 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, 2016, 2015 and 2014 . See Note 8—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. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. 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 as other current asset. 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. SPL has entered into six fixed price 20 -year SPAs with six unaffiliated third parties. SPL is dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective SPAs. During the year ended December 31, 2016 , we received 77% of our net LNG revenues from one SPA customer. SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal, which accounts for substantially all of our regasification revenues. SPLNG is dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. SPLNG has mitigated this credit risk by securing TUAs for a significant portion of its regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA. |
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 Consolidated 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 gains and losses on the extinguishment of debt on our Consolidated 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 Consolidated Balance Sheet. 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 early 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. Our assessment of AROs is described below. We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero . We have no t recorded an ARO associated with the Creole Trail Pipeline . We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly. |
Income Taxes, Policy | Income Taxes We are not subject to federal or state income taxes, as our partners are taxed individually on their allocable share of our taxable income. At December 31, 2016 , the tax basis of our assets and liabilities was $329.8 million less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our tax sharing agreements. |
Business Segment, Policy | Business Segment Our liquefaction and regasification operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of Cheniere Partners in total when evaluating financial performance and for purposes of allocating resources. |
Restricted Cash (Tables)
Restricted Cash (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Cash and Cash Equivalents [Abstract] | |
Schedule of Restricted Cash | As of December 31, 2016 and 2015 , restricted cash consisted of the following (in thousands): December 31, 2016 2015 Current restricted cash SPLNG debt service and interest payment $ — $ 77,415 Liquefaction Project 357,953 189,260 CTPL construction and interest payment — 7,882 CQP and cash held by guarantor subsidiaries 246,991 — Total current restricted cash $ 604,944 $ 274,557 Non-current restricted cash SPLNG debt service $ — $ 13,650 |
Accounts and Other Receivables
Accounts and Other Receivables (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Receivables [Abstract] | |
Schedule of Accounts and Other Receivables | As of December 31, 2016 and 2015 , accounts and other receivables consisted of the following (in thousands): December 31, 2016 2015 SPL trade receivable $ 87,555 $ — SPLNG trade receivable 396 — Other accounts receivable 2,245 741 Total accounts and other receivables $ 90,196 $ 741 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Inventory Disclosure [Abstract] | |
Schedule of Inventory | As of December 31, 2016 and 2015 , inventory consisted of the following (in thousands): December 31, 2016 2015 Natural gas $ 14,755 $ 5,724 LNG 45,410 3,690 Materials and other 37,266 7,253 Total inventory $ 97,431 $ 16,667 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands): December 31, 2016 2015 LNG terminal costs LNG terminal $ 7,975,814 $ 2,478,036 LNG terminal construction-in-process 6,728,305 9,859,836 LNG site and related costs, net 128 135 Accumulated depreciation (552,905 ) (411,907 ) Total LNG terminal costs, net 14,151,342 11,926,100 Fixed assets and other Computer and office equipment 1,224 1,126 Furniture and fixtures 1,667 1,375 Computer software 9,608 4,238 Machinery and equipment 2,017 1,906 Vehicles 3,392 2,081 Other 2,024 93 Accumulated depreciation (13,087 ) (5,317 ) Total fixed assets and other, net 6,845 5,502 Property, plant and equipment, net $ 14,158,187 $ 11,931,602 |
Property, Plant and Equipment, Estimated Useful Lives | The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows: Components Useful life (yrs) LNG storage tanks 50 Natural gas pipeline facilities 40 Marine berth, electrical, facility and roads 35 Regasification processing equipment 30 Sendout pumps 20 Liquefaction processing equipment 6-50 Other 15-30 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Fair Value of Derivative Assets and Liabilities | The following table (in thousands) 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, 2016 and 2015 , which are classified as other current assets , non-current derivative assets , derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets. Fair Value Measurements as of December 31, 2016 December 31, 2015 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 SPL Interest Rate Derivatives liability $ — $ (6,224 ) $ — $ (6,224 ) $ — $ (8,740 ) $ — $ (8,740 ) CQP Interest Rate Derivatives asset — 13,108 — 13,108 — — — — Liquefaction Supply Derivatives asset (liability) (4,483 ) (1,474 ) 79,022 73,065 — (25 ) 32,492 32,467 Natural Gas Derivatives asset — — — — — 39 — 39 |
Fair Value Inputs, Assets, Quantitative Information | The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2016 : Net Fair Value Asset (in thousands) Valuation Technique Significant Unobservable Input Significant Unobservable Inputs Range Physical Liquefaction Supply Derivatives $79,022 Income Approach Basis Spread $(0.260) - $(0.003) |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2016 and 2015 : Year Ended December 31, 2016 2015 Balance, beginning of period $ 32,492 $ 342 Realized and mark-to-market gains: Included in cost of sales (1) 48,218 32,150 Purchases and settlements: Purchases 538 — Settlements (1) (2,226 ) — Transfers out of Level 3 — — Balance, end of period $ 79,022 $ 32,492 Change in unrealized gains relating to instruments still held at end of period $ 48,938 $ 32,150 (1) Does not include the decrease in fair value of $0.7 million related to the realized gains capitalized during the year ended December 31, 2016 . |
Derivative Net Presentation on Consolidated Balance Sheets | The following table (in thousands) shows the fair value of our derivatives outstanding on a gross and net basis: Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets (Liabilities) As of December 31, 2016 SPL Interest Rate Derivatives $ (6,229 ) $ 5 $ (6,224 ) CQP Interest Rate Derivatives 16,073 — 16,073 CQP Interest Rate Derivatives (3,020 ) 55 (2,965 ) Liquefaction Supply Derivatives 82,116 (1,793 ) 80,323 Liquefaction Supply Derivatives (11,078 ) 3,820 (7,258 ) As of December 31, 2015 SPL Interest Rate Derivatives $ (8,740 ) $ — $ (8,740 ) Liquefaction Supply Derivatives 33,636 (595 ) 33,041 Liquefaction Supply Derivatives (574 ) — (574 ) Natural Gas Derivatives 188 (149 ) 39 |
Interest Rate Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | As of December 31, 2016 , we had the following Interest Rate Derivatives outstanding: Initial Notional Amount Maximum Notional Amount Effective Date Maturity Date Weighted Average Fixed Interest Rate Paid Variable Interest Rate Received SPL Interest Rate Derivatives $20.0 million $628.8 million August 14, 2012 July 31, 2019 1.98% One-month LIBOR CQP Interest Rate Derivatives $225.0 million $1.3 billion March 22, 2016 February 29, 2020 1.19% One-month LIBOR |
Fair Value of Derivative Instruments by Balance Sheet Location | The following table (in thousands) shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets: December 31, 2016 December 31, 2015 SPL Interest Rate Derivatives CQP Interest Rate Derivatives Total SPL Interest Rate Derivatives CQP Interest Rate Derivatives Total Balance Sheet Location Non-current derivative assets $ — $ 16,073 $ 16,073 $ — $ — $ — Derivative liabilities (4,223 ) (2,965 ) (7,188 ) (5,940 ) — (5,940 ) Non-current derivative liabilities (2,001 ) — (2,001 ) (2,800 ) — (2,800 ) Total derivative liabilities (6,224 ) (2,965 ) (9,189 ) (8,740 ) — (8,740 ) Derivative asset (liability), net $ (6,224 ) $ 13,108 $ 6,884 $ (8,740 ) $ — $ (8,740 ) |
Derivative Instruments, Gain (Loss) | The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2016, 2015 and 2014 : Year Ended December 31, 2016 2015 2014 SPL Interest Rate Derivatives loss $ (5,934 ) $ (41,722 ) $ (119,401 ) CQP Interest Rate Derivatives gain 11,478 — — |
Commodity Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Fair Value of Derivative Instruments by Balance Sheet Location | The following table (in thousands) shows the fair value and location of our Commodity Derivatives on our Consolidated Balance Sheets: December 31, 2016 December 31, 2015 Liquefaction Supply Derivatives (1) Natural Gas Derivatives Total Liquefaction Supply Derivatives Natural Gas Derivatives (2) Total Balance Sheet Location Other current assets $ 13,535 $ — $ 13,535 $ 2,737 $ 39 $ 2,776 Non-current derivative assets 66,788 — 66,788 30,304 — 30,304 Total derivative assets 80,323 — 80,323 33,041 39 33,080 Derivative liabilities (7,258 ) — (7,258 ) (490 ) — (490 ) Non-current derivative liabilities — — — (84 ) — (84 ) Total derivative liabilities (7,258 ) — (7,258 ) (574 ) — (574 ) Derivative asset, net $ 73,065 $ — $ 73,065 $ 32,467 $ 39 $ 32,506 (1) Does not include collateral of $6.0 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2016 . (2) Does not include collateral of $0.4 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015 . |
Derivative Instruments, Gain (Loss) | The following table (in thousands) shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2016, 2015 and 2014 : Year Ended December 31, Statement of Operations Location (1) 2016 2015 2014 Liquefaction Supply Derivatives loss LNG revenues $ (8 ) $ — $ — Liquefaction Supply Derivatives gain (2) Cost (cost recovery) of sales (42,172 ) (32,503 ) (342 ) Natural Gas Derivatives loss LNG revenues — — (31 ) Natural Gas Derivatives gain Operating and maintenance expense (174 ) (2,065 ) (1,389 ) (1) Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument. (2) Does not include the realized value associated with derivative instruments that settle through physical delivery. |
Other Non-Current Assets (Table
Other Non-Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Assets, Noncurrent [Abstract] | |
Schedule of Other Non-Current Assets | As of December 31, 2016 and 2015 , other non-current assets consisted of the following (in thousands): December 31, 2016 2015 Advances made under EPC and non-EPC contracts $ 22,809 $ 32,049 Advances made to municipalities for water system enhancements 95,495 89,953 Advances and other asset conveyances to third parties to support LNG terminals 30,707 28,850 Tax-related payments and receivables 27,781 27,615 Information technology service assets 27,416 30,371 Other 18,120 23,193 Total other non-current assets, net $ 222,328 $ 232,031 |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accrued Liabilities, Current [Abstract] | |
Schedule of Accrued Liabilities | As of December 31, 2016 and 2015 , accrued liabilities consisted of the following (in thousands): December 31, 2016 2015 Interest costs and related debt fees $ 205,312 $ 150,336 Sabine Pass LNG terminal and related pipeline costs 210,670 70,924 Other accrued liabilities 1,520 3,032 Total accrued liabilities $ 417,502 $ 224,292 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of Debt Instruments | As of December 31, 2016 and 2015, our debt consisted of the following (in thousands): December 31, 2016 2015 Long-term debt: SPLNG 6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) $ — $ 420,000 SPL 5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7,181 and $8,718 2,007,181 2,008,718 6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”) 1,000,000 1,000,000 5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5,657 and $6,392 1,505,657 1,506,392 5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”) 2,000,000 2,000,000 5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”) 2,000,000 2,000,000 5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”) 1,500,000 — 5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”) 1,500,000 — 2015 SPL Credit Facilities 314,000 845,000 CTPL $400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429 — 398,571 Cheniere Partners 2016 CQP Credit Facilities 2,560,000 — Unamortized debt issuance costs (1) (177,609 ) (160,356 ) Total long-term debt, net 14,209,229 10,018,325 Current debt: 7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of zero and $4,303 — 1,661,197 $1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”) 223,500 15,000 Unamortized debt issuance costs (1) — (2,818 ) Total current debt, net 223,500 1,673,379 Total debt, net $ 14,432,729 $ 11,691,704 (1) Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $160.4 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015 . |
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, 2016 (in thousands): Years Ending December 31, Principal Payments 2017 $ 223,500 2018 — 2019 — 2020 2,874,000 2021 2,000,000 Thereafter 9,500,000 Total $ 14,597,500 |
Schedule of Line of Credit Facilities | Below is a summary of our credit facilities outstanding as of December 31, 2016 (in thousands): 2015 SPL Credit Facilities SPL Working Capital Facility 2016 CQP Credit Facilities Original facility size $ 4,600,000 $ 1,200,000 $ 2,800,000 Outstanding balance 314,000 223,500 2,560,000 Commitments prepaid or terminated 2,643,867 — — Letters of credit issued — 323,677 45,000 Available commitment $ 1,642,133 $ 652,823 $ 195,000 Interest rate LIBOR plus 1.30% - 1.75% or base rate plus 1.75% LIBOR plus 1.75% or base rate plus 0.75% LIBOR plus 2.25% or base rate plus 1.25% (1) Maturity date Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date December 31, 2020, with various terms for underlying loans February 25, 2020, with principals due quarterly commencing on February 19, 2019 (1) There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019. |
Schedule of Interest Expense | Total interest expense consisted of the following (in thousands): Year Ended December 31, 2016 2015 2014 Total interest cost $ 841,022 $ 707,724 $ 580,236 Capitalized interest (484,122 ) (523,124 ) (403,204 ) Total interest expense, net $ 356,900 $ 184,600 $ 177,032 |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments | The following table (in thousands) shows the carrying amount and estimated fair value of our debt: December 31, 2016 December 31, 2015 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Senior Notes, net of premium or discount (1) $ 11,512,838 $ 12,308,736 $ 10,596,307 $ 9,525,809 CTPL Term Loan, net of discount (2) — — 398,571 400,000 Credit facilities (2) (3) 3,097,500 3,097,500 860,000 860,000 (1) Includes 2016 SPLNG Senior Notes , 2020 SPLNG Senior Notes and SPL Senior Notes (collectively, the “Senior Notes”) . The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the Senior Notes and other similar instruments. (2) The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. (3) Includes 2015 SPL Credit Facilities , SPL Working Capital Facility and 2016 CQP Credit Facilities . |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014 (in thousands): Year Ended December 31, 2016 2015 2014 LNG revenues—affiliate Cheniere Marketing SPA and Cheniere Marketing Master SPA $ 293,957 $ — $ — Regasification revenues—affiliate Contracts for Sale and Purchase of Natural Gas and LNG 918 672 3 Tug Boat Lease Sharing Agreement 2,867 2,792 2,800 Other agreements — 927 155 Total regasification revenues—affiliate 3,785 4,391 2,958 Cost of sales—affiliate Fees under the Pre-commercial LNG Marketing Agreement 1,490 — — Operating and maintenance expense—affiliate Contracts for Sale and Purchase of Natural Gas and LNG 607 1,121 — Services Agreements 51,579 28,267 21,164 Other agreements (49 ) (9 ) (49 ) Total operating and maintenance expense—affiliate 52,137 29,379 21,115 Development expense—affiliate Services Agreements 396 722 1,153 General and administrative expense—affiliate Services Agreements 89,523 122,312 101,369 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
Schedule of Future Minimum Rental Payments for Operating Leases | Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands): Years Ending December 31, Operating Leases (1) 2017 $ 2,308 2018 2,262 2019 2,262 2020 2,262 2021 2,239 Thereafter 45,372 Total $ 56,705 (1) Includes certain lease option renewals that are reasonably assured . |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
SPL [Member] | Natural Gas Supply Transportation And Storage Service Agreements [Member] | |
Long-term Purchase Commitment [Line Items] | |
Contractual Obligation, Fiscal Year Maturity Schedule | As of December 31, 2016 , SPL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in thousands): Years Ending December 31, Payments Due (1) 2017 $ 1,611,296 2018 1,192,791 2019 1,019,309 2020 1,055,497 2021 903,425 Thereafter 2,169,912 Total $ 7,952,230 (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, 2016 . |
Net Loss per Common Unit (Table
Net Loss per Common Unit (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts | Based on the capital structure as of December 31, 2016 , the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature is as follows in 2017 (in thousands): Common Units Class B Units Subordinated Units $(594,470) $2,004,209 $(1,409,739) |
Schedule of Net Loss per Common Unit | The following table (in thousands, except per unit data) provides a reconciliation of net loss and the allocation of net loss to the common units, the subordinated units and the general partner units for purposes of computing net loss per unit. Limited Partner Units Total Common Units Class B Units Subordinated Units General Partner Units Year Ended December 31, 2016 Net loss $ (171,195 ) Declared distributions 99,028 97,047 — — 1,981 Amortization of beneficial conversion feature of Class B units — (29,801 ) 100,472 (70,671 ) — Assumed allocation of undistributed net loss $ (270,223 ) (78,547 ) — (186,271 ) (5,404 ) Assumed allocation of net income (loss) $ (11,301 ) $ 100,472 $ (256,942 ) $ (3,423 ) Weighted average units outstanding 57,086 145,333 135,384 Net loss per unit $ (0.20 ) $ (1.90 ) Year Ended December 31, 2015 Net loss $ (318,891 ) Declared distributions 99,018 97,038 — — 1,980 Assumed allocation of undistributed net loss $ (417,909 ) (121,468 ) — (288,083 ) (8,358 ) Assumed allocation of net loss $ (24,430 ) $ — $ (288,083 ) $ (6,378 ) Weighted average units outstanding 57,081 145,333 135,384 Net loss per unit $ (0.43 ) $ (2.13 ) Year Ended December 31, 2014 Net loss $ (410,036 ) Declared distributions 99,015 97,036 — — 1,979 Assumed allocation of undistributed net loss $ (509,051 ) (147,952 ) — (350,918 ) (10,181 ) Assumed allocation of net loss $ (50,916 ) $ — $ (350,918 ) $ (8,202 ) Weighted average units outstanding 57,079 145,333 135,384 Net loss per unit $ (0.89 ) $ (2.59 ) |
Supplemental Cash Flow Inform40
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | The following table (in thousands) provides supplemental disclosure of cash flow information: Year Ended December 31, 2016 2015 2014 Cash paid during the period for interest, net of amounts capitalized $ 242,005 $ 135,836 $ 130,578 Non-cash conveyance of assets — 13,169 — |
Recent Accounting Standards (Ta
Recent Accounting Standards (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recent Accounting Standards, Not Yet Adopted | The following table provides a brief description of recent accounting standards that had not been adopted by the Partnership as of December 31, 2016 : Standard Description Expected Date of Adoption Effect on our Consolidated 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 continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we plan to adopt this standard using the full retrospective approach and we do not currently anticipate that the adoption will have a material impact upon our revenues. The Financial Accounting Standards Board (the “FASB”) has issued and may issue in the future amendments and interpretive guidance which may cause our evaluation to change. Furthermore, we routinely enter into new contracts and we cannot predict with certainty whether the accounting for any future contract under the new standard would result in a significant change from existing guidance. Because this assessment is preliminary and the accounting for revenue recognition is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact that recognizing fulfillment costs as assets will have on our Consolidated Financial Statements. ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively. January 1, 2017 The adoption of this guidance will not have a material impact on our Consolidated Financial Statements or related disclosures. ASU 2016-02, Leases (Topic 842) 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 must be adopted using a modified retrospective approach with certain available practical expedients. January 1, 2019 We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows, whether we will elect to early adopt this standard or which, if any, practical expedients we will elect upon transition. Standard Description Expected Date of Adoption Effect on our Consolidated Financial Statements or Other Significant Matters 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 We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures. |
Recent Accounting Standards, Adopted | Additionally, the following table provides a brief description of recent accounting standards that were adopted by the Partnership during the reporting period: Standard Description Date of Adoption Effect on our Consolidated Financial Statements or Other Significant Matters ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis These amendments primarily affect asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. January 1, 2016 The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures. ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements These standards require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented. January 1, 2016 Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 11—Debt for additional disclosures. Standard Description Date of Adoption Effect on our Consolidated Financial Statements or Other Significant Matters ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions This standard requires a master limited partnership to allocate net income (losses) of a transferred business entirely to the general partner when computing earnings per unit for periods before the dropdown transaction occurred. This guidance also requires a master limited partnership to disclose the effects of the dropdown transaction on net income (losses) per unit for the periods before and after the dropdown transaction occurred. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented. January 1, 2016 The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures. ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern This standard requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. Early adoption is permitted. December 31, 2016 The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures. ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) This standard requires an entity to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented. December 31, 2016 As a result of adopting this standard, our Consolidated Statements of Cash Flows now reconciles the balance of total cash, cash equivalents and restricted cash from the beginning of the period to the end of the period. This resulted in changes to previously reported cash flows from operating, investing and financing activities. ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business This standard narrows the accounting definition of a business and clarifies that when substantially all of the fair value of an integrated set of assets and activities is concentrated in a single asset or a group of similar assets, the integrated set of assets and activities is not a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill and consolidation. This guidance may be early adopted and must be adopted prospectively. December 31, 2016 The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures. |
Summarized Quarterly Financia42
Summarized Quarterly Financial Information (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Summarized Quarterly Financial Data—(in thousands, except per unit amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2016: Revenues $ 67,047 $ 151,171 $ 331,409 $ 550,613 Income (loss) from operations (9,463 ) 12,594 47,898 199,407 Net income (loss) (74,906 ) (100,125 ) (81,509 ) 85,345 Basic net income (loss) per common unit (1) $ (0.08 ) $ (0.21 ) $ (0.27 ) $ 0.07 Diluted net income (loss) per common unit (1) $ (0.08 ) $ (0.21 ) $ (0.27 ) $ 0.07 Year ended December 31, 2015: Revenues $ 67,530 $ 67,689 $ 67,537 $ 67,272 Income (loss) from operations (9,822 ) (4,318 ) 35,921 (18,739 ) Net loss (178,676 ) (60,043 ) (24,132 ) (56,040 ) Basic net income (loss) per common unit (1) $ (0.61 ) $ (0.01 ) $ 0.18 $ 0.01 Diluted net loss per common unit (1) $ (0.61 ) $ (0.01 ) $ (0.03 ) $ (0.09 ) (1) The sum of the quarterly net income (loss) per common unit may not equal the full year amount as the undistributed income and loss allocations and computations of the weighted average common units outstanding for basic and diluted common units outstanding for each quarter and the full year are performed independently. |
Schedule I_Condensed Financia43
Schedule I—Condensed Financial Information of Registrant (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Condensed Financial Statements, Captions [Line Items] | |
Schedule of Cash Flow, Supplemental Disclosures | The following table (in thousands) provides supplemental disclosure of cash flow information: Year Ended December 31, 2016 2015 2014 Cash paid during the period for interest, net of amounts capitalized $ 242,005 $ 135,836 $ 130,578 Non-cash conveyance of assets — 13,169 — |
Parent Company [Member] | |
Condensed Financial Statements, Captions [Line Items] | |
Condensed Balance Sheets | CHENIERE ENERGY PARTNERS, L.P. CONDENSED BALANCE SHEETS (in thousands) December 31, 2016 2015 ASSETS Current assets Cash and cash equivalents $ — $ 109,950 Restricted cash 234,407 — Prepaid expenses and other 447 187 Total current assets 234,854 110,137 Property, plant and equipment, net 78,789 58,410 Debt issuance and deferred financing costs, net 62,048 — Investment in affiliates 2,616,985 544,589 Non-current derivative assets 16,073 — Other non-current assets 45 953 Total assets $ 3,008,794 $ 714,089 LIABILITIES AND PARTNERS’ EQUITY Current liabilities Derivative liabilities $ 2,965 $ — Other current liabilities 2,775 1,158 Total current liabilities 5,740 1,158 Long-term debt 2,560,000 — Partners’ equity 443,054 712,931 Total liabilities and partners’ equity $ 3,008,794 $ 714,089 |
Condensed Statements of Operations | CHENIERE ENERGY PARTNERS, L.P. CONDENSED STATEMENTS OF OPERATIONS (in thousands) Year Ended December 31, 2016 2015 2014 Operating costs and expenses Operating and maintenance expense $ 5,326 $ 2,905 $ — General and administrative expense 3,927 2,760 3,383 General and administrative expense—affiliate 11,704 11,546 11,556 Depreciation and amortization expense 632 72 — Total operating costs and expenses 21,589 17,283 14,939 Other income (expense) Interest expense, net of capitalized interest (22,858 ) — — Derivative gain, net 11,478 — — Other income 351 173 162 Equity loss of affiliates (138,577 ) (301,781 ) (395,259 ) Total other expense (149,606 ) (301,608 ) (395,097 ) Net loss $ (171,195 ) $ (318,891 ) $ (410,036 ) |
Condensed Statements of Cash Flows | CHENIERE ENERGY PARTNERS, L.P. CONDENSED STATEMENTS OF CASH FLOWS (in thousands) Year Ended December 31, 2016 2015 2014 Cash flows used in operating activities $ (52,488 ) $ (43,723 ) $ (40,948 ) Cash flows from investing activities Property, plant and equipment, net — (671 ) — Investments in subsidiaries (2,428,967 ) 12,832 (61,350 ) Distributions received from affiliates, net 217,994 18,400 108,625 Net cash provided by (used in) investing activities (2,210,973 ) 30,561 47,275 Cash flows from financing activities Proceeds from issuance of debt 2,560,000 — — Debt issuance and deferred financing costs (73,060 ) — — Distributions to owners (99,025 ) (99,018 ) (98,979 ) Other 3 — — Net cash provided by (used in) financing activities 2,387,918 (99,018 ) (98,979 ) Net increase (decrease) in cash, cash equivalents and restricted cash 124,457 (112,180 ) (92,652 ) Cash, cash equivalents and restricted cash—beginning of period 109,950 222,130 314,782 Cash, cash equivalents and restricted cash—end of period $ 234,407 $ 109,950 $ 222,130 Balances per Condensed Balance Sheets: December 31 2016 2015 2014 Cash and cash equivalents $ — $ 109,950 $ 222,130 Restricted cash 234,407 — — Total cash, cash equivalents and restricted cash $ 234,407 $ 109,950 $ 222,130 |
Schedule of Cash Flow, Supplemental Disclosures | The following table provides supplemental disclosure of cash flow information (in thousands): Year Ended December 31, 2016 2015 2014 Non-cash capital contributions (1) $ 138,577 $ 301,781 $ 395,259 (1) Amounts represent equity loss of affiliates not funded by Cheniere Partners. |
Organization and Nature of Op44
Organization and Nature of Operations (Details) shares in Millions | 12 Months Ended | |
Dec. 31, 2016miitemmilliontonnes / yrbcf / dBcfetrainssharesm³ | Dec. 31, 2015 | |
Organization and Nature of Operations [Line Items] | ||
General Partner Ownership Interest Percentage | 2.00% | 2.00% |
Sabine Pass LNG Terminal [Member] | ||
Organization and Nature of Operations [Line Items] | ||
Number of Liquefaction LNG Trains | trains | 6 | |
Train Nominal Capacity | milliontonnes / yr | 4.5 | |
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 | |
Creole Trail Pipeline [Member] | ||
Organization and Nature of Operations [Line Items] | ||
Length Of Natural Gas Pipeline | mi | 94 | |
Cheniere [Member] | Cheniere Partners [Member] | ||
Organization and Nature of Operations [Line Items] | ||
General Partner Ownership Interest Percentage | 100.00% | |
Cheniere [Member] | Cheniere Holdings [Member] | ||
Organization and Nature of Operations [Line Items] | ||
Noncontrolling Interest, Ownership Percentage by Parent | 82.60% | |
Cheniere Holdings [Member] | Common Units [Member] | ||
Organization and Nature of Operations [Line Items] | ||
Partners Capital Account, Units, Units Held | 12 | |
Cheniere Holdings [Member] | Class B Units [Member] | ||
Organization and Nature of Operations [Line Items] | ||
Partners Capital Account, Units, Units Held | 45.3 | |
Cheniere Holdings [Member] | Subordinated Units [Member] | ||
Organization and Nature of Operations [Line Items] | ||
Partners Capital Account, Units, Units Held | 135.4 |
Unitholders' Equity (Details)
Unitholders' Equity (Details) $ / shares in Units, shares in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |
May 31, 2013USD ($)shares | Dec. 31, 2016Rate$ / shares | Dec. 31, 2012USD ($)item | |
Maximum [Member] | |||
Other Ownership Interests [Line Items] | |||
Number of days after quarter end distribution is paid | 45 days | ||
Common Units [Member] | |||
Other Ownership Interests [Line Items] | |||
Distributions Per Limited Partnership Unit Outstanding, Basic | $ / shares | $ 0.425 | ||
General Partner [Member] | Minimum [Member] | |||
Other Ownership Interests [Line Items] | |||
Distributions entitled by General Partner, Percentage | 2.00% | ||
Incentive Distribution, Quarterly Distribution Additional Target Percentage | 15.00% | ||
General Partner [Member] | Maximum [Member] | |||
Other Ownership Interests [Line Items] | |||
Incentive Distribution, Quarterly Distribution Additional Target Percentage | 50.00% | ||
Class B Units [Member] | |||
Other Ownership Interests [Line Items] | |||
Partnership Units, Conversion Ratio, Quarterly Compounded Rate | 0.035 | ||
Class B Unit Financing [Member] | |||
Other Ownership Interests [Line Items] | |||
Number of Liquefaction LNG Trains | item | 2 | ||
Blackstone [Member] | Class B Units [Member] | |||
Other Ownership Interests [Line Items] | |||
Proceeds from sale of partnership common and general partner units | $ | $ 1,500 | ||
Partnership Units, Accreted Conversion Ratio | Rate | 1.83 | ||
Cheniere [Member] | Class B Units [Member] | |||
Other Ownership Interests [Line Items] | |||
Proceeds from sale of partnership common and general partner units | $ | $ 180 | $ 500 | |
Additional units purchased, shares | shares | 12 | ||
Cheniere Holdings [Member] | Class B Units [Member] | |||
Other Ownership Interests [Line Items] | |||
Partnership Units, Accreted Conversion Ratio | Rate | 1.86 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies (Details) | 12 Months Ended | ||
Dec. 31, 2016USD ($)customeritem | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Basis of Presentation and Summary of Significant Accounting Policies [Line Items] | |||
Advanced Capacity Reservation Fees Amortization Period | 10 years | ||
Retained Percentage Of LNG Delivered | 2.00% | ||
Bad debt expense | $ 0 | $ 0 | $ 0 |
Inventory Write-down | 0 | 17,537,000 | 24,461,000 |
Impairments related to property, plant and equipment | 400,000 | 0 | 0 |
Derivative instruments designated as cash flow hedges | 0 | $ 0 | $ 0 |
Taxes, Difference in Bases, Amount | 329,800,000 | ||
Sabine Pass LNG Terminal [Member] | |||
Basis of Presentation and Summary of Significant Accounting Policies [Line Items] | |||
Asset Retirement Obligation | 0 | ||
Creole Trail Pipeline [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 | 2 | ||
Customer Concentration Risk [Member] | LNG Revenues [Member] | |||
Basis of Presentation and Summary of Significant Accounting Policies [Line Items] | |||
Concentration Risk, Percentage | 77.00% | ||
Customer Concentration Risk [Member] | LNG Revenues [Member] | SPA Customers [Member] | |||
Basis of Presentation and Summary of Significant Accounting Policies [Line Items] | |||
Concentration Risk, Number Of Significant Customers | customer | 1 | ||
Maximum [Member] | Sabine Pass LNG Terminal [Member] | |||
Basis of Presentation and Summary of Significant Accounting Policies [Line Items] | |||
Property lease term | 90 years | ||
SPL [Member] | Customer Concentration Risk [Member] | SPA Customers [Member] | |||
Basis of Presentation and Summary of Significant Accounting Policies [Line Items] | |||
Number Of Fixed Price Contracts | item | 6 | ||
Sale And Purchase Agreement Term Of Agreement | 20 years | ||
Sale And Purchase Agreement Number Of Unaffiliated Counterparties | customer | 6 | ||
SPLNG [Member] | Customer Concentration Risk [Member] | TUA Customers [Member] | |||
Basis of Presentation and Summary of Significant Accounting Policies [Line Items] | |||
Concentration Risk, Number Of Significant Customers | customer | 2 |
Restricted Cash (Details)
Restricted Cash (Details) - USD ($) | Dec. 31, 2016 | Feb. 29, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted cash | $ 604,944,000 | $ 274,557,000 | $ 195,702,000 | |
Non-current restricted cash | 0 | 13,650,000 | $ 544,465,000 | |
SPLNG Debt Service And Interest Payment [Member] | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted cash | 0 | 77,415,000 | ||
Liquefaction Project [Member] | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted cash | 357,953,000 | 189,260,000 | ||
CTPL Construction And Interest Payment [Member] | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted cash | 0 | 7,882,000 | ||
CQP And Cash Held By Guarantor Subsidiaries [Member] | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted cash | 246,991,000 | 0 | ||
SPLNG Debt Service [Member] | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Non-current restricted cash | $ 0 | $ 13,650,000 | ||
2016 CQP Credit Facilities [Member] | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,800,000,000 |
Accounts and Other Receivable48
Accounts and Other Receivables (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016USD ($)customer | Dec. 31, 2015USD ($) | |
Accounts and Other Receivables [Line Items] | ||
Other accounts receivable | $ 2,245 | $ 741 |
Total accounts and other receivables | $ 90,196 | 741 |
Customer Concentration Risk [Member] | Trade Receivable [Member] | ||
Accounts and Other Receivables [Line Items] | ||
Concentration Risk, Percentage | 99.00% | |
Customer Concentration Risk [Member] | SPA Customers [Member] | ||
Accounts and Other Receivables [Line Items] | ||
Concentration Risk, Number Of Significant Customers | customer | 2 | |
SPL [Member] | ||
Accounts and Other Receivables [Line Items] | ||
Trade receivable | $ 87,555 | 0 |
SPLNG [Member] | ||
Accounts and Other Receivables [Line Items] | ||
Trade receivable | $ 396 | $ 0 |
Inventory (Details)
Inventory (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Inventory [Line Items] | ||
Inventory | $ 97,431 | $ 16,667 |
Natural gas [Member] | ||
Inventory [Line Items] | ||
Inventory | 14,755 | 5,724 |
LNG [Member] | ||
Inventory [Line Items] | ||
Inventory | 45,410 | 3,690 |
Materials and other [Member] | ||
Inventory [Line Items] | ||
Inventory | $ 37,266 | $ 7,253 |
Property, Plant and Equipment -
Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, net | $ 14,158,187 | $ 11,931,602 | |
Depreciation expense | 147,900 | 64,600 | $ 58,600 |
Property, plant and equipment, reduction for testing costs recovered | 201,000 | ||
LNG terminal costs [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Accumulated depreciation | (552,905) | (411,907) | |
Property, plant and equipment, net | 14,151,342 | 11,926,100 | |
LNG terminal [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 7,975,814 | 2,478,036 | |
LNG terminal construction-in-process [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 6,728,305 | 9,859,836 | |
LNG site and related costs, net [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 128 | 135 | |
Fixed assets and other [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Accumulated depreciation | (13,087) | (5,317) | |
Property, plant and equipment, net | 6,845 | 5,502 | |
Computer and office equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,224 | 1,126 | |
Furniture and fixtures [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 1,667 | 1,375 | |
Computer software [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 9,608 | 4,238 | |
Machinery and equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 2,017 | 1,906 | |
Vehicles [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 3,392 | 2,081 | |
Other [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 2,024 | $ 93 |
Property, Plant and Equipment51
Property, Plant and Equipment - Estimated Useful Lives (Details) | 12 Months Ended |
Dec. 31, 2016 | |
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 |
LNG storage tanks [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 50 years |
Natural gas pipeline facilities [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 40 years |
Marine berth, electrical, facility and roads [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 35 years |
Regasification processing equipment [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 30 years |
Sendout pumps [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 20 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) MMBTU in Millions, $ in Millions | 1 Months Ended | 12 Months Ended |
Mar. 31, 2015USD ($) | Dec. 31, 2016MMBTU | |
Physical Liquefaction Supply Derivatives [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, Notional Amount | 1,111.4 | |
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, Term of Contract | 1 year | |
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, Term of Contract | 7 years | |
Financial Liquefaction Supply Derivatives [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, Notional Amount | 5.6 | |
SPL [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Energy Units Secured Through Long-Term Supply Contracts | 1,993.9 | |
SPL [Member] | SPL Previous Credit Facilities [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Line of Credit Facility, Decrease, Net | $ | $ 1,800 | |
SPL [Member] | SPL Interest Rate Derivatives [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative Loss, Net | $ | $ 34.7 |
Derivative Instruments - Fair V
Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
SPL Interest Rate Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | $ (6,224) | $ (8,740) |
SPL Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
SPL Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (6,224) | (8,740) |
SPL Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
CQP Interest Rate Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 13,108 | 0 |
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 13,108 | 0 |
CQP Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
Liquefaction Supply Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 73,065 | 32,467 |
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (4,483) | 0 |
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (1,474) | (25) |
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 79,022 | 32,492 |
Natural Gas Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 39 |
Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 39 |
Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | $ 0 | $ 0 |
Derivative Instruments - Fair54
Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member] | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |
Net Fair Value Asset | $ 79,022,000 |
Valuation Technique | Income Approach |
Significant Unobservable Input | Basis Spread |
Minimum [Member] | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |
Significant Unobservable Input Range | $ (0.260) |
Maximum [Member] | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |
Significant Unobservable Input Range | $ (0.003) |
Derivative Instruments - Schedu
Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Balance, beginning of period | $ 32,492 | $ 342 | |
Realized and mark-to-market gains: | |||
Included in cost of sales | [1] | 48,218 | 32,150 |
Purchases and settlements: | |||
Purchases | 538 | 0 | |
Settlements | [1] | (2,226) | 0 |
Transfers out of Level 3 | 0 | 0 | |
Balance, end of period | 79,022 | 32,492 | |
Change in unrealized gains relating to instruments still held at end of period | 48,938 | $ 32,150 | |
Decrease in Fair Value Realized and Capitalized During Period | $ 700 | ||
[1] | Does not include the decrease in fair value of $0.7 million related to the realized gains capitalized during the year ended December 31, 2016 |
Derivative Instruments - Sche56
Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
SPL Interest Rate Derivatives [Member] | |
Derivative [Line Items] | |
Notional Amount | $ 20 |
Effective Date | Aug. 14, 2012 |
Maturity Date | Jul. 31, 2019 |
Weighted Average Fixed Interest Rate Paid | 1.98% |
Variable Interest Rate Received | One-month LIBOR |
SPL Interest Rate Derivatives [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Notional Amount | $ 628.8 |
CQP Interest Rate Derivatives [Member] | |
Derivative [Line Items] | |
Notional Amount | $ 225 |
Effective Date | Mar. 22, 2016 |
Maturity Date | Feb. 29, 2020 |
Weighted Average Fixed Interest Rate Paid | 1.19% |
Variable Interest Rate Received | One-month LIBOR |
CQP Interest Rate Derivatives [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Notional Amount | $ 1,300 |
Derivative Instruments - Fair57
Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative assets | $ 82,861 | $ 30,304 | |||
Derivative liabilities | (14,446) | (6,430) | |||
Non-current derivative liabilities | (2,001) | (2,884) | |||
Interest Rate Derivatives [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Total derivative liabilities | (9,189) | (8,740) | |||
Derivative asset (liability), net | 6,884 | (8,740) | |||
Interest Rate Derivatives [Member] | Non-current derivative assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative assets | 16,073 | 0 | |||
Interest Rate Derivatives [Member] | Derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative liabilities | (7,188) | (5,940) | |||
Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative liabilities | (2,001) | (2,800) | |||
SPL Interest Rate Derivatives [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Total derivative liabilities | (6,224) | (8,740) | |||
Derivative asset (liability), net | (6,224) | (8,740) | |||
SPL Interest Rate Derivatives [Member] | Non-current derivative assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative assets | 0 | 0 | |||
SPL Interest Rate Derivatives [Member] | Derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative liabilities | (4,223) | (5,940) | |||
SPL Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative liabilities | (2,001) | (2,800) | |||
CQP Interest Rate Derivatives [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Total derivative liabilities | (2,965) | 0 | |||
Derivative asset (liability), net | 13,108 | 0 | |||
CQP Interest Rate Derivatives [Member] | Non-current derivative assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative assets | 16,073 | 0 | |||
CQP Interest Rate Derivatives [Member] | Derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative liabilities | (2,965) | 0 | |||
CQP Interest Rate Derivatives [Member] | Non-current derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative liabilities | 0 | 0 | |||
Commodity Derivatives [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Total derivative assets | 80,323 | 33,080 | |||
Total derivative liabilities | (7,258) | (574) | |||
Derivative asset (liability), net | 73,065 | 32,506 | |||
Commodity Derivatives [Member] | Other current assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Other current assets | 13,535 | 2,776 | |||
Commodity Derivatives [Member] | Non-current derivative assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative assets | 66,788 | 30,304 | |||
Commodity Derivatives [Member] | Derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative liabilities | (7,258) | (490) | |||
Commodity Derivatives [Member] | Non-current derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative liabilities | 0 | (84) | |||
Liquefaction Supply Derivatives [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Total derivative assets | 80,323 | [1] | 33,041 | ||
Total derivative liabilities | (7,258) | [1] | (574) | ||
Derivative asset (liability), net | 73,065 | [1] | 32,467 | ||
Liquefaction Supply Derivatives [Member] | Other current assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Other current assets | 13,535 | [1] | 2,737 | ||
Derivative, Collateral, Right to Reclaim Cash | 6,000 | ||||
Liquefaction Supply Derivatives [Member] | Non-current derivative assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative assets | 66,788 | [1] | 30,304 | ||
Liquefaction Supply Derivatives [Member] | Derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative liabilities | (7,258) | [1] | (490) | ||
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative liabilities | 0 | [1] | (84) | ||
Natural Gas Derivatives [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Total derivative assets | 0 | 39 | [2] | ||
Total derivative liabilities | 0 | 0 | [2] | ||
Derivative asset (liability), net | 0 | 39 | [2] | ||
Natural Gas Derivatives [Member] | Other current assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Other current assets | 0 | 39 | [2] | ||
Derivative, Collateral, Right to Reclaim Cash | [2] | 400 | |||
Natural Gas Derivatives [Member] | Non-current derivative assets [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative assets | 0 | 0 | [2] | ||
Natural Gas Derivatives [Member] | Derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative liabilities | 0 | 0 | [2] | ||
Natural Gas Derivatives [Member] | Non-current derivative liabilities [Member] | |||||
Derivatives, Fair Value [Line Items] | |||||
Non-current derivative liabilities | $ 0 | $ 0 | [2] | ||
[1] | Does not include collateral of $6.0 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2016. | ||||
[2] | Does not include collateral of $0.4 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015. |
Derivative Instruments - Deriva
Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
SPL Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ (5,934) | $ (41,722) | $ (119,401) | |
CQP Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | 11,478 | 0 | 0 | |
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | (8) | 0 | 0 | |
Liquefaction Supply Derivatives [Member] | Cost (cost recovery) of sales [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | [1] | 42,172 | 32,503 | 342 |
Natural Gas Derivatives [Member] | LNG Revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | (31) | |
Natural Gas Derivatives [Member] | Operating and maintenance expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 174 | $ 2,065 | $ 1,389 | |
[1] | Does not include the realized value associated with derivative instruments that settle through physical delivery. |
Derivative Instruments - Balanc
Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
SPL Interest Rate Derivative Liability [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Gross Amounts Recognized | $ (6,229) | $ (8,740) |
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet | 5 | 0 |
Derivative Assets (Liabilities), at Fair Value, Net | (6,224) | (8,740) |
CQP Interest Rate Derivative Asset [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Gross Amounts Recognized | 16,073 | |
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet | 0 | |
Derivative Assets (Liabilities), at Fair Value, Net | 16,073 | |
CQP Interest Rate Derivative Liability [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Gross Amounts Recognized | (3,020) | |
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet | 55 | |
Derivative Assets (Liabilities), at Fair Value, Net | (2,965) | |
Liquefaction Supply Derivative Asset [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Gross Amounts Recognized | 82,116 | 33,636 |
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet | (1,793) | (595) |
Derivative Assets (Liabilities), at Fair Value, Net | 80,323 | 33,041 |
Liquefaction Supply Derivative Liability [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Gross Amounts Recognized | (11,078) | (574) |
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet | 3,820 | 0 |
Derivative Assets (Liabilities), at Fair Value, Net | $ (7,258) | (574) |
Natural Gas Derivative Asset [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Gross Amounts Recognized | 188 | |
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet | (149) | |
Derivative Assets (Liabilities), at Fair Value, Net | $ 39 |
Other Non-Current Assets (Detai
Other Non-Current Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Other Assets, Noncurrent [Abstract] | ||
Advances made under EPC and non-EPC contracts | $ 22,809 | $ 32,049 |
Advances made to municipalities for water system enhancements | 95,495 | 89,953 |
Advances and other asset conveyances to third parties to support LNG terminals | 30,707 | 28,850 |
Tax-related payments and receivables | 27,781 | 27,615 |
Information technology service assets | 27,416 | 30,371 |
Other | 18,120 | 23,193 |
Other non-current assets, net | $ 222,328 | $ 232,031 |
Accrued Liabilities (Details)
Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Accrued Liabilities, Current [Abstract] | ||
Interest costs and related debt fees | $ 205,312 | $ 150,336 |
Sabine Pass LNG terminal and related pipeline costs | 210,670 | 70,924 |
Other accrued liabilities | 1,520 | 3,032 |
Total accrued liabilities | $ 417,502 | $ 224,292 |
Debt - Schedule of Debt Instrum
Debt - Schedule of Debt Instruments (Details) - USD ($) | Dec. 31, 2016 | Feb. 29, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 14,209,229,000 | $ 10,018,325,000 | ||
Unamortized Debt Issuance Costs, Noncurrent | [1] | (177,609,000) | (160,356,000) | |
Current Debt, Net | 223,500,000 | 1,673,379,000 | ||
Unamortized Debt Issuance Costs, Current | [1] | 0 | (2,818,000) | |
Total Debt, Net | 14,432,729,000 | 11,691,704,000 | ||
Accounting Standards Update 2015-03 [Member] | Debt Issuance Costs, Net [Member] | ||||
Debt Instrument [Line Items] | ||||
Unamortized Debt Issuance Costs, Noncurrent | (160,356,000) | |||
Unamortized Debt Issuance Costs, Current | (2,818,000) | |||
Accounting Standards Update 2015-03 [Member] | Long-term Debt, Net [Member] | ||||
Debt Instrument [Line Items] | ||||
Unamortized Debt Issuance Costs, Noncurrent | 160,356,000 | |||
Accounting Standards Update 2015-03 [Member] | Current Debt, Net [Member] | ||||
Debt Instrument [Line Items] | ||||
Unamortized Debt Issuance Costs, Current | 2,818,000 | |||
2020 SPLNG Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 0 | 420,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | |||
2021 SPL Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 2,007,181,000 | 2,008,718,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.625% | |||
Debt Instrument, Unamortized Premium | $ 7,181,000 | 8,718,000 | ||
2022 SPL Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 1,000,000,000 | 1,000,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.25% | |||
2023 SPL Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 1,505,657,000 | 1,506,392,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.625% | |||
Debt Instrument, Unamortized Premium | $ 5,657,000 | 6,392,000 | ||
2024 SPL Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 2,000,000,000 | 2,000,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.75% | |||
2025 SPL Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 2,000,000,000 | 2,000,000,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.625% | |||
2026 SPL Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 1,500,000,000 | 0 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.875% | |||
2027 SPL Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 1,500,000,000 | 0 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | |||
2015 SPL Credit Facilities [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | $ 314,000,000 | 845,000,000 | ||
CTPL Term Loan [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | 0 | 398,571,000 | ||
Line of Credit Facility, Maximum Borrowing Capacity | 400,000,000 | |||
Debt Instrument, Unamortized Discount | 0 | 1,429,000 | ||
2016 CQP Credit Facilities [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Net | 2,560,000,000 | 0 | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,800,000,000 | |||
2016 SPLNG Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Current Debt, Net | $ 0 | 1,661,197,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 7.50% | |||
Debt Instrument, Unamortized Discount | $ 0 | 4,303,000 | ||
SPL Working Capital Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Current Debt, Net | 223,500,000 | $ 15,000,000 | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,200,000,000 | |||
[1] | Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively for each reporting period presented. As a result, we reclassified $160.4 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015. |
Debt - Schedule of Maturities (
Debt - Schedule of Maturities (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Long-term Debt, Fiscal Year Maturity [Abstract] | |
2,017 | $ 223,500 |
2,018 | 0 |
2,019 | 0 |
2,020 | 2,874,000 |
2,021 | 2,000,000 |
Thereafter | 9,500,000 |
Total | $ 14,597,500 |
Debt - Senior Notes (Details)
Debt - Senior Notes (Details) | 12 Months Ended |
Dec. 31, 2016Rate | |
SPLNG [Member] | 2020 SPLNG Senior Notes [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Redemption Price, Percentage | 103.25% |
SPL [Member] | SPL Senior Notes [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument Fixed Charge Coverage Ratio Period | 12 months |
Debt Instrument, Fixed Charge, Coverage Ratio | 1.25 |
Debt Instrument, Redemption Price, Percentage | 100.00% |
SPL [Member] | SPL Senior Notes - Excluding 2026 SPL Senior Notes and 2027 SPL 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 |
SPL [Member] | 2026 SPL 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 Instrument Registration Period | 360 days |
SPL [Member] | 2027 SPL 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 Instrument Registration Period | 360 days |
Debt - Credit Facilities Table
Debt - Credit Facilities Table (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Line of Credit Facility [Line Items] | |||
Outstanding balance | $ 14,209,229 | $ 10,018,325 | |
Outstanding balance, current | 223,500 | 1,673,379 | |
2015 SPL Credit Facilities [Member] | |||
Line of Credit Facility [Line Items] | |||
Original facility size | 4,600,000 | ||
Outstanding balance | 314,000 | 845,000 | |
Commitments prepaid or terminated | 2,643,867 | ||
Letters of credit issued | 0 | ||
Available commitment | $ 1,642,133 | ||
Debt Instrument, Description of Variable Rate Basis | LIBOR or base rate | ||
Debt Instrument, Maturity Date, Description | Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date | ||
2015 SPL Credit Facilities [Member] | Base Rate [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | ||
2015 SPL Credit Facilities [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | 1.30% | ||
2015 SPL Credit Facilities [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | ||
SPL Working Capital Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Original facility size | $ 1,200,000 | ||
Outstanding balance, current | 223,500 | 15,000 | |
Commitments prepaid or terminated | 0 | ||
Letters of credit issued | 323,677 | ||
Available commitment | $ 652,823 | ||
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 | ||
SPL 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% | ||
SPL Working Capital Facility [Member] | Base Rate [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | 0.75% | ||
2016 CQP Credit Facilities [Member] | |||
Line of Credit Facility [Line Items] | |||
Original facility size | $ 2,800,000 | ||
Outstanding balance | 2,560,000 | $ 0 | |
Commitments prepaid or terminated | 0 | ||
Letters of credit issued | 45,000 | ||
Available commitment | $ 195,000 | ||
Debt Instrument, Description of Variable Rate Basis | [1] | LIBOR or base rate | |
Debt Instrument, Maturity Date, Description | February 25, 2020, with principals due quarterly commencing on February 19, 2019 | ||
2016 CQP Credit Facilities [Member] | February 25, 2019 [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Interest Rate, Increase | 0.50% | ||
2016 CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | [1] | 2.25% | |
2016 CQP Credit Facilities [Member] | Base Rate [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | [1] | 1.25% | |
[1] | There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019. |
Debt - 2015 SPL Credit Faciliti
Debt - 2015 SPL Credit Facilities (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016USD ($)Rate | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Jun. 30, 2015USD ($) | |
Line of Credit Facility [Line Items] | ||||
Loss on early extinguishment of debt | $ 71,824 | $ 96,273 | $ 114,335 | |
2015 SPL Credit Facilities [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Line Of Credit Facility, Original Borrowing Capacity | 4,600,000 | |||
Commitments prepaid or terminated | $ 2,643,867 | |||
Debt Instrument, Description of Variable Rate Basis | LIBOR or base rate | |||
2015 SPL Credit Facilities [Member] | Base Rate [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | |||
2015 SPL Credit Facilities [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.30% | |||
2015 SPL Credit Facilities [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | |||
SPL [Member] | 2015 SPL Credit Facilities [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Line Of Credit Facility, Original Borrowing Capacity | $ 4,600,000 | |||
Commitments prepaid or terminated | $ 2,643,867 | |||
Loss on early extinguishment of debt | $ 52,200 | |||
Debt Instrument, Description of Variable Rate Basis | LIBOR or the base rate | |||
Line Of Credit Facility, Insurance Premium, Percentage Of Drawn Amount | 0.45% | |||
Line Of Credit Facility, Unused Capacity Commitment Fee, Percentage Of Margin On Undrawn Commitment | 40.00% | |||
Line of Credit Facility, Unused Capacity Commitment Fee, Percentage of Undrawn Commitment | 0.70% | |||
Line Of Credit Facility, Amortization Period | 18 years | |||
Debt Instrument, Fixed Charge, Coverage Ratio | Rate | 1.25 | |||
SPL [Member] | 2015 SPL Credit Facilities [Member] | Base Rate [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | |||
SPL [Member] | 2015 SPL Credit Facilities [Member] | Minimum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Percentage of Debt Hedged by Interest Rate Derivatives | 65.00% | |||
SPL [Member] | 2015 SPL Credit Facilities [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.30% | |||
SPL [Member] | 2015 SPL Credit Facilities [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.75% |
Debt - SPL Working Capital Faci
Debt - SPL Working Capital Facility (Details) | 12 Months Ended |
Dec. 31, 2016USD ($) | |
SPL Working Capital Facility [Member] | |
Line of Credit Facility [Line Items] | |
Debt Instrument, Description of Variable Rate Basis | LIBOR or base rate |
SPL 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% |
SPL Working Capital Facility [Member] | Base Rate [Member] | |
Line of Credit Facility [Line Items] | |
Debt Instrument, Basis Spread on Variable Rate | 0.75% |
SPL [Member] | SPL Working Capital Facility [Member] | |
Line of Credit Facility [Line Items] | |
Debt Instrument, Description of Variable Rate Basis | LIBOR or the base rate |
Letter 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 |
SPL [Member] | SPL 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 of Undrawn Commitment | 1.75% |
SPL [Member] | SPL 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% |
SPL [Member] | SPL Working Capital Facility [Member] | Base Rate [Member] | |
Line of Credit Facility [Line Items] | |
Debt Instrument, Basis Spread on Variable Rate | 0.75% |
SPL [Member] | SPL 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% |
SPL [Member] | SPL 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% |
SPL [Member] | SPL Working Capital Facility [Member] | Maximum [Member] | |
Line of Credit Facility [Line Items] | |
Line of Credit Facility, Permitted Increase | $ 760,000,000 |
SPL [Member] | SPL 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 |
SPL [Member] | Letter of Credit [Member] | Drawn Portion [Member] | |
Line of Credit Facility [Line Items] | |
Long-term Line of Credit | $ 0 |
SPL [Member] | 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% |
SPL [Member] | 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 |
SPL [Member] | 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 |
SPL [Member] | Swing Line Loan [Member] | Maximum [Member] | |
Line of Credit Facility [Line Items] | |
Debt Instrument, Term | 15 days |
SPL [Member] | LC Loan [Member] | Maximum [Member] | |
Line of Credit Facility [Line Items] | |
Debt Instrument, Term | 1 year |
Debt - 2016 CQP Credit Faciliti
Debt - 2016 CQP Credit Facilities (Details) | 1 Months Ended | 12 Months Ended | ||||
Nov. 30, 2016USD ($) | Feb. 29, 2016USD ($) | Dec. 31, 2016USD ($)Rate | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Line of Credit Facility [Line Items] | ||||||
Loss on early extinguishment of debt | $ 71,824,000 | $ 96,273,000 | $ 114,335,000 | |||
2016 CQP Credit Facilities [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,800,000,000 | |||||
Debt Instrument, Balance Required in Reserve Account, Period of Debt Service | 6 months | |||||
Debt Instrument, Description of Variable Rate Basis | [1] | LIBOR or base rate | ||||
Debt Issuance Costs, Line of Credit Arrangements, Gross | $ 73,100,000 | |||||
Loss on early extinguishment of debt | $ 19,600,000 | |||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 40.00% | |||||
2016 CQP Credit Facilities [Member] | February 25, 2019 [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Interest Rate, Increase | 0.50% | |||||
2016 CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | [1] | 2.25% | ||||
Line Of Credit Facility, Number of Months Period Within LIBOR Period Interest Due | 3 months | |||||
2016 CQP Credit Facilities [Member] | Base Rate [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | [1] | 1.25% | ||||
2016 CQP Credit Facilities [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% | |||||
2016 CQP Credit Facilities [Member] | Base Rate Determination LIBOR [Member] | Base Rate [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | |||||
2016 CQP Credit Facilities [Member] | Minimum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Percentage of Debt Hedged by Interest Rate Derivatives | 50.00% | |||||
Debt Instrument, Fixed Charge, Coverage Ratio | Rate | 1.15 | |||||
Debt Instrument, Fixed Charge, Coverage Ratio, Projected | Rate | 1.55 | |||||
2016 CQP Credit Facilities - CTPL Tranche Term Loan [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 450,000,000 | |||||
2016 CQP Credit Facilities - SPLNG Tranche Term Loan [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | 2,100,000,000 | |||||
2016 CQP Credit Facilities - Debt Service Reserve Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | 125,000,000 | |||||
2016 CQP Credit Facilities - Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 115,000,000 | |||||
2016 CQP Credit Facilities Letter of Credit [Member] | Undrawn portion [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Commitment Fee Percentage | 2.25% | |||||
2016 CQP Credit Facilities Letter of Credit [Member] | Undrawn portion [Member] | February 25, 2019 [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Interest Rate, Increase | 0.50% | |||||
CTPL Term Loan [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400,000,000 | |||||
Repayments of Long-term Debt | $ 400,000,000 | |||||
SPLNG Senior Notes [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Repayments of Long-term Debt | $ 2,100,000,000 | |||||
[1] | There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019. |
Debt - Interest Expense (Detail
Debt - Interest Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Disclosure [Abstract] | |||
Total interest cost | $ 841,022 | $ 707,724 | $ 580,236 |
Capitalized interest | (484,122) | (523,124) | (403,204) |
Total interest expense, net | $ 356,900 | $ 184,600 | $ 177,032 |
Debt - Schedule of Carrying Val
Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount, Debt | $ 14,432,729 | $ 11,691,704 | |
Senior Notes, net of premium or discount [Member] | Carrying Amount [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount, Debt | [1] | 11,512,838 | 10,596,307 |
Senior Notes, net of premium or discount [Member] | Estimated Fair Value [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes, Estimated Fair Value | [1] | 12,308,736 | 9,525,809 |
CTPL Term Loan, net of discount [Member] | Carrying Amount [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount, Debt | [2] | 0 | 398,571 |
CTPL Term Loan, net of discount [Member] | Estimated Fair Value [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
CTPL Term Loan, Estimated Fair Value | [2] | 0 | 400,000 |
Credit facilities [Member] | Carrying Amount [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount, Debt | [2],[3] | 3,097,500 | 860,000 |
Credit facilities [Member] | Estimated Fair Value [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Credit Facilities, Estimated Fair Value | [2],[3] | $ 3,097,500 | $ 860,000 |
[1] | Includes 2016 SPLNG Senior Notes, 2020 SPLNG Senior Notes and SPL Senior Notes (collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the Senior Notes and other similar instruments. | ||
[2] | The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. | ||
[3] | Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities. |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
LNG revenues—affiliate | $ 293,957 | $ 0 | $ 0 |
Regasification revenues—affiliate | 3,785 | 4,391 | 2,958 |
Cost of sales—affiliate | 1,490 | 0 | 0 |
Operating and maintenance expense—affiliate | 52,137 | 29,379 | 21,115 |
Development expense—affiliate | 396 | 722 | 1,153 |
General and administrative expense—affiliate | 89,523 | 122,312 | 101,369 |
Cheniere Marketing SPA and Cheniere Marketing Master SPA [Member] | |||
Related Party Transaction [Line Items] | |||
LNG revenues—affiliate | 293,957 | 0 | 0 |
Contracts for Sale and Purchase of Natural Gas and LNG [Member] | |||
Related Party Transaction [Line Items] | |||
Regasification revenues—affiliate | 918 | 672 | 3 |
Operating and maintenance expense—affiliate | 607 | 1,121 | 0 |
Tug Boat Lease Sharing Agreement [Member] | |||
Related Party Transaction [Line Items] | |||
Regasification revenues—affiliate | 2,867 | 2,792 | 2,800 |
Other Agreements [Member] | |||
Related Party Transaction [Line Items] | |||
Regasification revenues—affiliate | 0 | 927 | 155 |
Operating and maintenance expense—affiliate | (49) | (9) | (49) |
Fees under Pre-commercial LNG Marketing Agreement [Member] | |||
Related Party Transaction [Line Items] | |||
Cost of sales—affiliate | 1,490 | 0 | 0 |
Service Agreements [Member] | |||
Related Party Transaction [Line Items] | |||
Operating and maintenance expense—affiliate | 51,579 | 28,267 | 21,164 |
Development expense—affiliate | 396 | 722 | 1,153 |
General and administrative expense—affiliate | $ 89,523 | $ 122,312 | $ 101,369 |
Related Party Transactions - LN
Related Party Transactions - LNG Terminal Capacity Agreements (Details) | 12 Months Ended | ||
Dec. 31, 2016USD ($)bcf / dtrains$ / MMBTU | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Related Party Transaction [Line Items] | |||
Revenues—affiliate | $ 293,957,000 | $ 0 | $ 0 |
Terminal Use Agreement [Member] | SPLNG [Member] | SPL [Member] | |||
Related Party Transaction [Line Items] | |||
Regasification Capacity | bcf / d | 2 | ||
Related Party Transaction, Committed Annual Fee | $ 250,000,000 | ||
Related Party Agreement Term | 20 years | ||
Amended and Restated Variable Capacity Rights Agreement [Member] | Cheniere Investments [Member] | Cheniere Marketing [Member] | |||
Related Party Transaction [Line Items] | |||
Proceeds (Payments) of Gross Margin Earned, Percentage | 80.00% | ||
Revenues—affiliate | $ 0 | $ 0 | $ 0 |
LNG Sale and Purchase Agreement [Member] | SPL [Member] | Cheniere Marketing [Member] | |||
Related Party Transaction [Line Items] | |||
Incremental LNG Volume, Purchase Price Percentage of Henry Hub | 115.00% | ||
Incremental LNG Volume, Purchase Price Per MMBtu | $ / MMBTU | 3 | ||
Commissioning Agreement [Member] | Cheniere Marketing [Member] | SPL [Member] | |||
Related Party Transaction [Line Items] | |||
Number of Liquefaction LNG Trains Subject To In Agreement | trains | 4 |
Related Party Transactions - Se
Related Party Transactions - Service Agreements (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | ||
Advances to Affiliate Current | $ 37,697,000 | $ 39,836,000 |
Service Agreements [Member] | ||
Related Party Transaction [Line Items] | ||
Advances to Affiliate Current | 37,700,000 | $ 39,800,000 |
Cheniere Partners Services Agreement [Member] | Cheniere Terminals [Member] | ||
Related Party Transaction [Line Items] | ||
Quarterly non-accountable overhead reimbursement charge | 2,800,000 | |
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | SPLNG [Member] | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Committed Monthly Fee | $ 130,000 | |
Related Party Transaction, Bonus Percentage of Salary Entitled Upon Meeting Certain Criteria | 50.00% | |
Operation and Maintenance Agreement [Member] | Cheniere Investments [Member] | SPL [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] | SPLNG [Member] | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Committed Monthly Fee | $ 520,000 | |
Management Services Agreement [Member] | Cheniere Terminals [Member] | SPL [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 | |
Management Services Agreement [Member] | Cheniere Terminals [Member] | CTPL [Member] | ||
Related Party Transaction [Line Items] | ||
Monthly fee as a percentage of capital expenditures incurred in the previous month | 3.00% |
Related Party Transactions - Ot
Related Party Transactions - Other Agreements (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Revenues—affiliate | $ 293,957,000 | $ 0 | $ 0 |
Cooperative Endeavor Agreements [Member] | SPLNG [Member] | |||
Related Party Transaction [Line Items] | |||
Tax Initiative Agreement Term | 10 years | ||
Aggregate commitment under the Agreement | $ 24,500,000 | ||
Cooperative Endeavor Agreements [Member] | Cheniere Marketing [Member] | SPLNG [Member] | |||
Related Party Transaction [Line Items] | |||
Advance ad valorem tax payments | 24,500,000 | 22,100,000 | |
LNG Terminal Export Agreement [Member] | Cheniere Marketing [Member] | SPLNG [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues—affiliate | 0 | $ 0 | $ 0 |
Tax Sharing Agreement [Member] | Cheniere [Member] | SPLNG [Member] | |||
Related Party Transaction [Line Items] | |||
Income Taxes Paid, Net | 0 | ||
Tax Sharing Agreement [Member] | Cheniere [Member] | SPL [Member] | |||
Related Party Transaction [Line Items] | |||
Income Taxes Paid, Net | 0 | ||
Tax Sharing Agreement [Member] | Cheniere [Member] | CTPL [Member] | |||
Related Party Transaction [Line Items] | |||
Income Taxes Paid, Net | $ 0 |
Leases (Details)
Leases (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Operating Leased Assets [Line Items] | ||||
Operating Leases, Rent Expense | $ 11,100 | $ 10,500 | $ 10,500 | |
2017, Minimum Payment | [1] | 2,308 | ||
2018, Minimum Payment | [1] | 2,262 | ||
2019, Minimum Payment | [1] | 2,262 | ||
2020, Minimum Payment | [1] | 2,262 | ||
2021, Minimum Payment | [1] | 2,239 | ||
Thereafter, Minimum Payment | [1] | 45,372 | ||
Total, Minimum Payment | [1] | $ 56,705 | ||
Land [Member] | Maximum [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Initial Term of Lease | 30 years | |||
Term of Available Extension | 60 years | |||
[1] | Includes certain lease option renewals that are reasonably assured. |
Commitments and Contingencies76
Commitments and Contingencies (Details) MMBTU / yr in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)MMBTU / yrMMBTUitem | |
Commitments and Contingencies [Line Items] | |
Amount of Restricted Net Assets for Consolidated Subsidiaries | $ 2,600 |
Loss Contingency, Pending Claims, Number | item | 0 |
SPL [Member] | |
Commitments and Contingencies [Line Items] | |
Energy Units Secured Through Long-Term Supply Contracts | MMBTU | 1,993.9 |
SPA Commitment, Trains 1 and 2 [Member] | SPL [Member] | |
Commitments and Contingencies [Line Items] | |
Contract Volumes | MMBTU / yr | 401.5 |
SPA Commitment, Trains 3 Through 5 [Member] | SPL [Member] | |
Commitments and Contingencies [Line Items] | |
Contract Volumes | MMBTU / yr | 628.5 |
SPL Bechtel EPC Contracts [Member] | SPL [Member] | Maximum [Member] | |
Commitments and Contingencies [Line Items] | |
Contract Termination Convenience Penalty | $ 30 |
EPC Contract, Trains 3 And 4 [Member] | SPL [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Amount | 3,900 |
EPC Contract, Train 5 [Member] | SPL [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Amount | $ 3,000 |
Natural Gas Supply Agreement [Member] | Minimum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 1 year |
Natural Gas Supply Agreement [Member] | Maximum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 6 years |
Transportation Agreement [Member] | Minimum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 10 years |
Transportation Agreement [Member] | Maximum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 20 years |
Storage Service Agreement [Member] | SPL [Member] | Minimum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 3 years |
Storage Service Agreement [Member] | SPL [Member] | Maximum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 10 years |
Commitments and Contingencies -
Commitments and Contingencies - Purchase Obligations Table (Details) - SPL [Member] - Natural Gas Supply Transportation And Storage Service Agreements [Member] $ in Thousands | Dec. 31, 2016USD ($) | [1] |
Long-term Purchase Commitment [Line Items] | ||
2,017 | $ 1,611,296 | |
2,018 | 1,192,791 | |
2,019 | 1,019,309 | |
2,020 | 1,055,497 | |
2,021 | 903,425 | |
Thereafter | 2,169,912 | |
Total | $ 7,952,230 | |
[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, 2016. |
Net Loss per Common Unit - Narr
Net Loss per Common Unit - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | Jan. 20, 2017 | Dec. 31, 2016 |
Class B Units [Member] | ||
Distribution Made to Limited Partner [Line Items] | ||
Discount upon issuance of Class B units representing beneficial conversion feature | $ 2,130 | |
Cheniere Holdings [Member] | Class B Units [Member] | Effective Yield Method [Member] | ||
Distribution Made to Limited Partner [Line Items] | ||
Amortization of Beneficial Conversion Feature of Class B Units | 888.70% | |
Blackstone [Member] | Class B Units [Member] | Effective Yield Method [Member] | ||
Distribution Made to Limited Partner [Line Items] | ||
Amortization of Beneficial Conversion Feature of Class B Units | 966.10% | |
Subsequent Event [Member] | Common Units [Member] | ||
Distribution Made to Limited Partner [Line Items] | ||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 0.425 |
Net Loss per Common Unit - Sche
Net Loss per Common Unit - Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Common Units [Member] | |
Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts [Line Items] | |
2,017 | $ (594,470) |
Class B Units [Member] | |
Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts [Line Items] | |
2,017 | 2,004,209 |
Subordinated Units [Member] | |
Schedule of Anticipated Beneficial Conversion Feature impact to Capital Accounts [Line Items] | |
2,017 | $ (1,409,739) |
Net Loss per Common Unit - Sc80
Net Loss per Common Unit - Schedule of Net Loss per Unit and Allocation of Distribution (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Net loss | $ 85,345 | $ (81,509) | $ (100,125) | $ (74,906) | $ (56,040) | $ (24,132) | $ (60,043) | $ (178,676) | $ (171,195) | $ (318,891) | $ (410,036) |
Declared distributions | 99,028 | 99,018 | 99,015 | ||||||||
Amortization of beneficial conversion feature of Class B units | 0 | ||||||||||
Assumed allocation of undistributed net loss | $ (270,223) | $ (417,909) | $ (509,051) | ||||||||
Weighted average units outstanding | 57,086 | 57,081 | 57,079 | ||||||||
Net loss per unit | $ (0.20) | $ (0.43) | $ (0.89) | ||||||||
Common Units [Member] | |||||||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Net loss | $ (49,763) | $ (92,688) | $ (119,175) | ||||||||
Declared distributions | 97,047 | 97,038 | 97,036 | ||||||||
Amortization of beneficial conversion feature of Class B units | (29,801) | ||||||||||
Assumed allocation of undistributed net loss | (78,547) | (121,468) | (147,952) | ||||||||
Assumed allocation of net income (loss) | $ (11,301) | $ (24,430) | $ (50,916) | ||||||||
Weighted average units outstanding | 57,086 | 57,081 | 57,079 | ||||||||
Net loss per unit | $ (0.20) | $ (0.43) | $ (0.89) | ||||||||
Class B Units [Member] | |||||||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Net loss | $ 0 | $ 0 | $ 0 | ||||||||
Declared distributions | 0 | 0 | 0 | ||||||||
Amortization of beneficial conversion feature of Class B units | 100,472 | ||||||||||
Assumed allocation of undistributed net loss | 0 | 0 | 0 | ||||||||
Assumed allocation of net income (loss) | $ 100,472 | $ 0 | $ 0 | ||||||||
Weighted average units outstanding | 145,333 | 145,333 | 145,333 | ||||||||
Net loss per unit | |||||||||||
Subordinated Units [Member] | |||||||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Net loss | $ (118,008) | $ (219,825) | $ (282,660) | ||||||||
Declared distributions | 0 | 0 | 0 | ||||||||
Amortization of beneficial conversion feature of Class B units | (70,671) | ||||||||||
Assumed allocation of undistributed net loss | (186,271) | (288,083) | (350,918) | ||||||||
Assumed allocation of net income (loss) | $ (256,942) | $ (288,083) | $ (350,918) | ||||||||
Weighted average units outstanding | 135,384 | 135,384 | 135,384 | ||||||||
Net loss per unit | $ (1.90) | $ (2.13) | $ (2.59) | ||||||||
General Partner [Member] | |||||||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Net loss | $ (3,424) | $ (6,378) | $ (8,201) | ||||||||
Declared distributions | 1,981 | 1,980 | 1,979 | ||||||||
Amortization of beneficial conversion feature of Class B units | 0 | ||||||||||
Assumed allocation of undistributed net loss | (5,404) | (8,358) | (10,181) | ||||||||
Assumed allocation of net income (loss) | $ (3,423) | $ (6,378) | $ (8,202) |
Supplemental Cash Flow Inform81
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid during the period for interest, net of amounts capitalized | $ 242,005 | $ 135,836 | $ 130,578 |
Non-cash conveyance of assets | 0 | 13,169 | 0 |
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) | $ 267,100 | $ 230,700 | $ 124,700 |
Subsequent Events (Details)
Subsequent Events (Details) - Subsequent Event [Member] - SPL [Member] - 2037 SPL Notes [Member] | Feb. 24, 2017USD ($) |
Subsequent Event [Line Items] | |
Aggregate principal amount | $ 800,000,000 |
Debt Instrument, Interest Rate, Stated Percentage | 5.00% |
Summarized Quarterly Financia83
Summarized Quarterly Financial Information (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||
Revenues | $ 550,613 | $ 331,409 | $ 151,171 | $ 67,047 | $ 67,272 | $ 67,537 | $ 67,689 | $ 67,530 | $ 1,100,240 | $ 270,028 | $ 268,698 | |
Income (loss) from operations | 199,407 | 47,898 | 12,594 | (9,463) | (18,739) | 35,921 | (4,318) | (9,822) | 250,436 | 3,042 | 515 | |
Net income (loss) | $ 85,345 | $ (81,509) | $ (100,125) | $ (74,906) | $ (56,040) | $ (24,132) | $ (60,043) | $ (178,676) | $ (171,195) | $ (318,891) | $ (410,036) | |
Basic net income (loss) per common unit | [1] | $ 0.07 | $ (0.27) | $ (0.21) | $ (0.08) | $ 0.01 | $ 0.18 | $ (0.01) | $ (0.61) | |||
Diluted net income (loss) per common unit | [1] | $ 0.07 | $ (0.27) | $ (0.21) | $ (0.08) | $ (0.09) | $ (0.03) | $ (0.01) | $ (0.61) | |||
[1] | The sum of the quarterly net income (loss) per common unit may not equal the full year amount as the undistributed income and loss allocations and computations of the weighted average common units outstanding for basic and diluted common units outstanding for each quarter and the full year are performed independently. |
Schedule I_Condensed Financia84
Schedule I—Condensed Financial Information of Registrant - Condensed Balance Sheets (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Current assets | ||||
Cash and cash equivalents | $ 0 | $ 146,221 | $ 248,830 | |
Restricted cash | 604,944 | 274,557 | 195,702 | |
Total current assets | 958,260 | 493,475 | ||
Property, plant and equipment, net | 14,158,187 | 11,931,602 | ||
Debt issuance and deferred financing costs, net | 120,704 | 132,091 | ||
Non-current derivative assets | 82,861 | 30,304 | ||
Total assets | 15,542,340 | 12,833,153 | ||
Current liabilities | ||||
Derivative liabilities | 14,446 | 6,430 | ||
Other current liabilities | 224 | 0 | ||
Total current liabilities | 855,711 | 2,063,017 | ||
Long-term debt | 14,209,229 | 10,018,325 | ||
Partners’ equity | 443,054 | 712,931 | 1,130,729 | $ 1,639,744 |
Total liabilities and partners’ equity | 15,542,340 | 12,833,153 | ||
Parent Company [Member] | ||||
Current assets | ||||
Cash and cash equivalents | 0 | 109,950 | 222,130 | |
Restricted cash | 234,407 | 0 | $ 0 | |
Prepaid expenses and other | 447 | 187 | ||
Total current assets | 234,854 | 110,137 | ||
Property, plant and equipment, net | 78,789 | 58,410 | ||
Debt issuance and deferred financing costs, net | 62,048 | 0 | ||
Investment in affiliates | 2,616,985 | 544,589 | ||
Non-current derivative assets | 16,073 | 0 | ||
Other non-current assets | 45 | 953 | ||
Total assets | 3,008,794 | 714,089 | ||
Current liabilities | ||||
Derivative liabilities | 2,965 | 0 | ||
Other current liabilities | 2,775 | 1,158 | ||
Total current liabilities | 5,740 | 1,158 | ||
Long-term debt | 2,560,000 | 0 | ||
Partners’ equity | 443,054 | 712,931 | ||
Total liabilities and partners’ equity | $ 3,008,794 | $ 714,089 |
Schedule I_Condensed Financia85
Schedule I—Condensed Financial Information of Registrant - Condensed Statements of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating costs and expenses | |||||||||||
Operating and maintenance expense | $ 126,878 | $ 62,406 | $ 63,161 | ||||||||
General and administrative expense | 13,200 | 15,079 | 13,807 | ||||||||
General and administrative expense—affiliate | 89,523 | 122,312 | 101,369 | ||||||||
Depreciation and amortization expense | 155,621 | 65,704 | 58,601 | ||||||||
Total operating costs and expenses | 849,804 | 266,986 | 268,183 | ||||||||
Other income (expense) | |||||||||||
Interest expense, net of capitalized interest | (356,900) | (184,600) | (177,032) | ||||||||
Derivative gain, net | 5,544 | (41,722) | (119,401) | ||||||||
Other income | 1,549 | 662 | 217 | ||||||||
Total other expense | (421,631) | (321,933) | (410,551) | ||||||||
Net loss | $ 85,345 | $ (81,509) | $ (100,125) | $ (74,906) | $ (56,040) | $ (24,132) | $ (60,043) | $ (178,676) | (171,195) | (318,891) | (410,036) |
Parent Company [Member] | |||||||||||
Operating costs and expenses | |||||||||||
Operating and maintenance expense | 5,326 | 2,905 | 0 | ||||||||
General and administrative expense | 3,927 | 2,760 | 3,383 | ||||||||
General and administrative expense—affiliate | 11,704 | 11,546 | 11,556 | ||||||||
Depreciation and amortization expense | 632 | 72 | 0 | ||||||||
Total operating costs and expenses | 21,589 | 17,283 | 14,939 | ||||||||
Other income (expense) | |||||||||||
Interest expense, net of capitalized interest | (22,858) | 0 | 0 | ||||||||
Derivative gain, net | 11,478 | 0 | 0 | ||||||||
Other income | 351 | 173 | 162 | ||||||||
Equity loss of affiliates | (138,577) | (301,781) | (395,259) | ||||||||
Total other expense | (149,606) | (301,608) | (395,097) | ||||||||
Net loss | $ (171,195) | $ (318,891) | $ (410,036) |
Schedule I_Condensed Financia86
Schedule I—Condensed Financial Information of Registrant - Condensed Statements of Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Condensed Financial Statements, Captions [Line Items] | |||
Net cash used in operating activities | $ (249) | $ (171,099) | $ (137,044) |
Cash flows from investing activities | |||
Property, plant and equipment, net | (2,315,081) | (2,912,080) | (2,645,553) |
Net cash provided by (used in) investing activities | (2,353,399) | (2,974,528) | (2,684,433) |
Cash flows from financing activities | |||
Debt issuance and deferred financing costs | (114,724) | (169,924) | (101,787) |
Distributions to owners | (99,025) | (99,018) | (98,979) |
Net cash provided by (used in) financing activities | 2,524,164 | 2,591,058 | 2,206,734 |
Net increase (decrease) in cash, cash equivalents and restricted cash | 170,516 | (554,569) | (614,743) |
Cash, cash equivalents and restricted cash—beginning of period | 434,428 | 988,997 | 1,603,740 |
Cash, cash equivalents and restricted cash—end of period | 604,944 | 434,428 | 988,997 |
Balances per Condensed Balance Sheets: | |||
Cash and cash equivalents | 0 | 146,221 | 248,830 |
Restricted cash | 604,944 | 274,557 | 195,702 |
Total cash, cash equivalents and restricted cash | 604,944 | 434,428 | 988,997 |
Parent Company [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
Net cash used in operating activities | (52,488) | (43,723) | (40,948) |
Cash flows from investing activities | |||
Property, plant and equipment, net | 0 | (671) | 0 |
Investments in subsidiaries | (2,428,967) | 12,832 | (61,350) |
Distributions received from affiliates, net | 217,994 | 18,400 | 108,625 |
Net cash provided by (used in) investing activities | (2,210,973) | 30,561 | 47,275 |
Cash flows from financing activities | |||
Proceeds from issuance of debt | 2,560,000 | 0 | 0 |
Debt issuance and deferred financing costs | (73,060) | 0 | 0 |
Distributions to owners | (99,025) | (99,018) | (98,979) |
Other | 3 | 0 | 0 |
Net cash provided by (used in) financing activities | 2,387,918 | (99,018) | (98,979) |
Net increase (decrease) in cash, cash equivalents and restricted cash | 124,457 | (112,180) | (92,652) |
Cash, cash equivalents and restricted cash—beginning of period | 109,950 | 222,130 | 314,782 |
Cash, cash equivalents and restricted cash—end of period | 234,407 | 109,950 | 222,130 |
Balances per Condensed Balance Sheets: | |||
Cash and cash equivalents | 0 | 109,950 | 222,130 |
Restricted cash | 234,407 | 0 | 0 |
Total cash, cash equivalents and restricted cash | $ 234,407 | $ 109,950 | $ 222,130 |
Schedule I_Condensed Financia87
Schedule I—Condensed Financial Information of Registrant - Footnotes - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Parent Company [Member] | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Non-cash capital contributions | [1] | $ 138,577 | $ 301,781 | $ 395,259 |
[1] | Amounts represent equity loss of affiliates not funded by Cheniere Partners. |