Exhibit 99.1

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

CHENIERE ENERGY PARTNERS, L.P.

Report of Independent Registered Public Accounting Firm	2
Consolidated Balance Sheets	3
Consolidated Statements of Operations	4
Consolidated Statements of Partners’ Equity	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7

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Report of Independent Registered Public Accounting Firm

To the Unitholders of Cheniere Energy Partners, L.P. and

Board of Directors of Cheniere Energy Partners GP, LLC:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Cheniere Energy Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2017 and 2016, the related consolidated statements of operations, partners’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 2018 (not included herein) expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Change in Accounting Principle

As discussed in Note 3 to the consolidated financial statements, the Partnership has changed its method of accounting for revenue recognition in 2017, 2016 and 2015 due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Partnership’s auditor since 2014.

Houston, Texas

February 20, 2018, except as to Notes 12 and 20 which are as of June 15, 2018

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

		December 31,
		2017				2016
ASSETS
Current assets
Cash and cash equivalents		$	—			$	—
Restricted cash		1,589				605
Accounts and other receivables		191				90
Accounts receivable—affiliate		163				99
Advances to affiliate		36				38
Inventory		95				97
Other current assets		65				29
Total current assets		2,139				958
Property, plant and equipment, net		15,139				14,158
Debt issuance costs, net		38				121
Non-current derivative assets		31				83
Other non-current assets, net		206				222
Total assets		$	17,553			$	15,542
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable		$	12			$	27
Accrued liabilities		637				418
Current debt		—				224
Due to affiliates		68				99
Deferred revenue		111				73
Deferred revenue—affiliate		1				1
Derivative liabilities		—				14
Total current liabilities		829				856
Long-term debt, net		16,046				14,209
Non-current deferred revenue		1				5
Non-current derivative liabilities		3				2
Other non-current liabilities		10				—
Other non-current liabilities—affiliate		25				27
Commitments and contingencies (see Note 16)
Partners’ equity
Common unitholders’ interest (348.6 million units and 57.1 million units issued and outstanding at December 31, 2017 and 2016, respectively)		1,670				130
Class B unitholders’ interest (zero and 145.3 million units issued and outstanding at December 31, 2017 and 2016, respectively)		—				62
Subordinated unitholders’ interest (135.4 million units issued and outstanding at December 31, 2017 and 2016)		(1,043		)		240
General partner’s interest (2% interest with 9.9 million units and 6.9 million units issued and outstanding at December 31, 2017 and 2016, respectively)		12				11
Total partners’ equity		639				443
Total liabilities and partners’ equity		$	17,553			$	15,542

The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

	Year Ended December 31,
	2017				2016				2015
Revenues
LNG revenues	$	2,635			$	539			$	—
LNG revenues—affiliate	1,389				294				—
Regasification revenues	260				259				259
Other revenues	20				4				7
Other revenues—affiliate	—				4				4
Total revenues	4,304				1,100				270
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	2,320				410				(31		)
Cost of sales—affiliate	—				2				—
Operating and maintenance expense	292				127				62
Operating and maintenance expense—affiliate	100				52				29
Development expense	3				—				3
Development expense—affiliate	—				—				1
General and administrative expense	12				13				15
General and administrative expense—affiliate	80				90				122
Depreciation and amortization expense	339				156				66
Other	2				—				—
Total operating costs and expenses	3,148				850				267
Income from operations	1,156				250				3
Other income (expense)
Interest expense, net of capitalized interest	(614		)		(357		)		(185		)
Loss on early extinguishment of debt	(67		)		(72		)		(96		)
Derivative gain (loss), net	4				6				(42		)
Other income	11				2				1
Total other expense	(666		)		(421		)		(322		)
Net income (loss)	$	490			$	(171	)		$	(319	)
Basic and diluted net loss per common unit	$	(1.32	)		$	(0.20	)		$	(0.43	)
Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	178.5				57.1				57.1

The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(in millions)

	Common Unitholders’ Interest							Class B Unitholders’ Interest							Subordinated Unitholder’s Interest							General Partner’s Interest							Total Partners’ Equity
	Units			Amount				Units			Amount				Units			Amount				Units			Amount
Balance at December 31, 2014	57.1			$	496			145.3			$	(38	)		135.4			$	648			6.9			$	25			$	1,131
Net loss	—			(93		)		—			—				—			(220		)		—			(6		)		(319		)
Distributions	—			(97		)		—			—				—			—				—			(2		)		(99		)
Amortization of beneficial conversion feature of Class B units	—			—				—			1				—			(1		)		—			—				—
Balance at December 31, 2015	57.1			306				145.3			(37		)		135.4			427				6.9			17				713
Net loss	—			(50		)		—			—				—			(117		)		—			(4		)		(171		)
Distributions	—			(97		)		—			—				—			—				—			(2		)		(99		)
Amortization of beneficial conversion feature of Class B units	—			(29		)		—			99				—			(70		)		—			—				—
Balance at December 31, 2016	57.1			130				145.3			62				135.4			240				6.9			11				443
Net income	—			294				—			—				—			186				—			10				490
Distributions	—			(226		)		—			—				—			(59		)		—			(9		)		(294		)
Conversion of Class B units into common units	291.5			2,066				(145.3	)		(2,066		)		—			—				3.0			—				—
Amortization of beneficial conversion feature of Class B units	—			(594		)		—			2,004				—			(1,410		)		—			—				—
Balance at December 31, 2017	348.6			$	1,670			—			$	—			135.4			$	(1,043	)		9.9			$	12			$	639

The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2017				2016				2015
Cash flows from operating activities
Net income (loss)	$	490			$	(171	)		$	(319	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Non-cash LNG inventory write-downs	—				—				18
Depreciation and amortization expense	339				156				66
Amortization of debt issuance costs, deferred commitment fees, premium and discount	36				30				12
Loss on early extinguishment of debt	67				72				96
Total losses (gains) on derivatives, net	20				(48		)		7
Net cash used for settlement of derivative instruments	(16		)		(8		)		(41		)
Other	8				1				—
Changes in operating assets and liabilities:
Accounts and other receivables	(101		)		(90		)		—
Accounts receivable—affiliate	(62		)		(98		)		1
Advances to affiliate	(12		)		—				(13		)
Inventory	13				(58		)		(25		)
Accounts payable and accrued liabilities	210				167				(1		)
Due to affiliates	(42		)		11				15
Deferred revenue	34				42				(4		)
Other, net	(5		)		(7		)		(11		)
Other, net—affiliate	(2		)		1				28
Net cash provided by (used in) operating activities	977				—				(171		)
Cash flows from investing activities
Property, plant and equipment, net	(1,290		)		(2,315		)		(2,913		)
Other	—				(38		)		(62		)
Net cash used in investing activities	(1,290		)		(2,353		)		(2,975		)
Cash flows from financing activities
Proceeds from issuances of debt	3,814				8,003				2,860
Repayments of debt	(2,173		)		(5,251		)		—
Debt issuance and deferred financing costs	(50		)		(115		)		(170		)
Debt extinguishment costs	—				(14		)		—
Distributions to owners	(294		)		(99		)		(99		)
Net cash provided by financing activities	1,297				2,524				2,591
Net increase (decrease) in cash, cash equivalents and restricted cash	984				171				(555		)
Cash, cash equivalents and restricted cash—beginning of period	605				434				989
Cash, cash equivalents and restricted cash—end of period	$	1,589			$	605			$	434

Balances per Consolidated Balance Sheets:

	December 31,
	2017				2016
Cash and cash equivalents	$	—			$	—
Restricted cash	1,589				605
Total cash, cash equivalents and restricted cash	$	1,589			$	605

The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a publicly traded Delaware limited partnership (NYSE American: CQP) formed by Cheniere. Through 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 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. Through our wholly owned subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We 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 CTPL.

As of December 31, 2017, Cheniere owned 100% of our general partner interest and 82.7% of Cheniere Holdings, which owned 104.5 million of our common units and 135.4 million of our subordinated units.

NOTE 2—UNITHOLDERS’ EQUITY

 

The common 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, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

 

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 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 Trains of the Liquefaction Project. In May 2013, Cheniere purchased an additional 12.0 million Class B units for consideration of $180 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. 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 increased at a compounded rate of 3.5% per quarter.

On August 2, 2017, the 45.3 million Class B units held by Cheniere Holdings and 100.0 million Class B units held by Blackstone CQP Holdco mandatorily converted into our common units in accordance with the terms of our partnership agreement. Upon conversion of the Class B units, Cheniere Holdings, Blackstone CQP Holdco and the public owned a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere Holdings’ ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 3—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 Partners 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 did not have a material effect on our consolidated financial position, results of operations or cash flows.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying consolidated financial statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings.

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, derivative instruments, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 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

 

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. LNG regasification capacity payments are recognized as regasification revenues. We also recognize tug services fees, which were historically included in regasification revenues but are now included within other revenues on our Consolidated Statements of Operations, that are received by Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of SPLNG. See Note 12—Revenues from Contracts with Customers for further discussion of revenues.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. During the year ended December 31, 2015, we recognized $18 million as operating and maintenance expense as a result of write-down for LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. We did not recognize any operating and maintenance expense related to inventory write-downs during the years ended December 31, 2017 and 2016.

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 (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed 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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.  We did not record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015, 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 for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. 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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded 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 SPAs with terms of at least 20 years with six unaffiliated third parties. SPL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 17—Customer Concentration for additional details about our customer concentration.

 

SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. SPLNG is dependent on the respective customers’ 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 A.

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 immaterial.

We have not 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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2017, the tax basis of our assets and liabilities was $3.1 billion less than the reported amounts of our assets and liabilities. See Note 13—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.

NOTE 4—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, 2017 and 2016, restricted cash consisted of the following (in millions):

		December 31,
		2017				2016
Current restricted cash
Liquefaction Project		$	544			$	358
CQP and cash held by guarantor subsidiaries		1,045				247
Total current restricted cash		$	1,589			$	605

NOTE 5—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2017 and 2016, accounts and other receivables consisted of the following (in millions):

		December 31,
		2017				2016
SPL trade receivable		$	185			$	88
Other accounts receivable		6				2
Total accounts and other receivables		$	191			$	90

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.

NOTE 6—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in millions):

		December 31,
		2017				2016
Natural gas		$	17			$	15
LNG		26				45
Materials and other		52				37
Total inventory		$	95			$	97

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 7—PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in millions):

		December 31,
		2017				2016
LNG terminal costs
LNG terminal		$	12,703			$	7,976
LNG terminal construction-in-process		3,310				6,728
Accumulated depreciation		(880		)		(553		)
Total LNG terminal costs, net		15,133				14,151
Fixed assets
Fixed assets		23				20
Accumulated depreciation		(17		)		(13		)
Total fixed assets, net		6				7
Property, plant and equipment, net		$	15,139			$	14,158

 

Depreciation expense was $331 million, $148 million and $65 million in the years ended December 31, 2017, 2016 and 2015, respectively.

We realized offsets to LNG terminal costs of $301 million and $201 million in the years ended December 31, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction.

LNG Terminal Costs

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.

NOTE 8—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 credit facilities (“Interest Rate Derivatives”) and

•	commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”).

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2017 and 2016, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	December 31, 2017																December 31, 2016
	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	)		$	—			$	(6	)
CQP Interest Rate Derivatives asset	—				21				—				21				—				13				—				13
Liquefaction Supply Derivatives asset (liability)	2				10				43				55				(4		)		(2		)		79				73

We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data.

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2017:

		Net Fair Value Asset (in millions)		Valuation Approach		Significant Unobservable Input		Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives		$43		Market approach incorporating present value techniques		Basis Spread		$(0.503) - $0.432

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
Balance, beginning of period		$	79			$	32			$	—
Realized and mark-to-market gains (losses):
Included in cost of sales (1)		(37		)		48				32
Purchases and settlements:
Purchases		14				1				—
Settlements (1)		(12		)		(2		)		—
Transfers out of Level 3		(1		)		—				—
Balance, end of period		$	43			$	79			$	32
Change in unrealized gains relating to instruments still held at end of period		$	(37	)		$	49			$	32

    

(1)	Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position.  Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

SPL had 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”), based on a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities. In March 2017, SPL settled the SPL Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 11—Debt.

We have 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 our $2.8 billion credit facilities (the “2016 CQP Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities.

As of December 31, 2017, 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

CQP Interest Rate Derivatives

$225 million

$1.3 billion

March 22, 2016

February 29, 2020

1.19%

One-month LIBOR

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets (in millions):

		December 31, 2017												December 31, 2016
		SPL Interest Rate Derivatives				CQP Interest Rate Derivatives				Total				SPL Interest Rate Derivatives				CQP Interest Rate Derivatives				Total
Balance Sheet Location
Other current assets		$	—			$	7			$	7			$	—			$	—			$	—
Non-current derivative assets		—				14				14				—				16				16
Total derivative assets		—				21				21				—				16				16
Derivative liabilities		—				—				—				(4		)		(3		)		(7		)
Non-current derivative liabilities		—				—				—				(2		)		—				(2		)
Total derivative liabilities		—				—				—				(6		)		(3		)		(9		)
Derivative asset (liability), net		$	—			$	21			$	21			$	(6	)		$	13			$	7

The following table 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, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
SPL Interest Rate Derivatives loss		$	(2	)		$	(6	)		$	(42	)
CQP Interest Rate Derivatives gain		6				12				—

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges, if applicable, to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the noncurrent physical natural gas supply contracts range from approximately one to seven years, most of which commence upon the satisfaction of certain conditions precedent, if not already met, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

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.

SPL had secured up to approximately 2,214 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2017 and 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,520 TBtu and 1,117 TBtu as of December 31, 2017 and 2016, respectively.

The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):

			Fair Value Measurements as of (1)
	Balance Sheet Location		December 31, 2017				December 31, 2016
Liquefaction Supply Derivatives	Other current assets		$	41			$	13
Liquefaction Supply Derivatives	Non-current derivative assets		17				67
Liquefaction Supply Derivatives	Derivative liabilities		—				(7		)
Liquefaction Supply Derivatives	Non-current derivative liabilities		(3		)		—

(1)	Does not include a collateral call of $1 million and a collateral deposit of $6 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):

			Year Ended December 31,
	Statement of Operations Location (1)		2017				2016				2015
Liquefaction Supply Derivatives loss (gain) (2)	Cost of sales		$	24			$	(42	)		$	(33	)

(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.

Consolidated Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):

		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, 2017
CQP Interest Rate Derivatives		$	21			$	—			$	21
Liquefaction Supply Derivatives		64				(6		)		58
Liquefaction Supply Derivatives		(3		)		—				(3		)
As of December 31, 2016
SPL Interest Rate Derivatives		$	(6	)		$	—			$	(6	)
CQP Interest Rate Derivatives		16				—				16
CQP Interest Rate Derivatives		(3		)		—				(3		)
Liquefaction Supply Derivatives		82				(2		)		80
Liquefaction Supply Derivatives		(11		)		4				(7		)

NOTE 9—OTHER NON-CURRENT ASSETS

As of December 31, 2017 and 2016, other non-current assets, net consisted of the following (in millions):

		December 31,
		2017				2016
Advances made under EPC and non-EPC contracts		$	26			$	23
Advances made to municipalities for water system enhancements		93				95
Advances and other asset conveyances to third parties to support LNG terminals		30				31
Tax-related payments and receivables		25				28
Information technology service assets		24				27
Other		8				18
Total other non-current assets, net		$	206			$	222

NOTE 10—ACCRUED LIABILITIES

 

As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in millions):

		December 31,
		2017				2016
Interest costs and related debt fees		$	253			$	205
Sabine Pass LNG terminal and related pipeline costs		384				211
Other accrued liabilities		—				2
Total accrued liabilities		$	637			$	418

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 11—DEBT

 

As of December 31, 2017 and 2016, our debt consisted of the following (in millions):

		December 31,
		2017				2016
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7		$	2,006			$	2,007
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)		1,000				1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $6		1,505				1,506
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)		2,000				2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)		2,000				2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)		1,500				1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)		1,500				1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero		1,349				—
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)		800				—
2015 SPL Credit Facilities		—				314
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)		1,500				—
2016 CQP Credit Facilities		1,090				2,560
Unamortized debt issuance costs		(204		)		(178		)
Total long-term debt, net		16,046				14,209
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)		—				224
Total debt, net		$	16,046			$	14,433

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, 2017 (in millions): 

Years Ending December 31,		Principal Payments
2018		$	—
2019		55
2020		1,035
2021		2,000
2022		1,000
Thereafter		12,150
Total		$	16,240

Senior Notes

SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.

  

In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the year ended December 31, 2017.

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, 2027 SPL Senior Notes and 2028 SPL Senior Notes (collectively with the 2037 SPL Senior Notes, the “SPL Senior Notes”) are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain 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 or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. 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 test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. Interest on the SPL Senior Notes is payable semi-annually in arrears.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 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 (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, 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, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the 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.

2025 CQP Senior Notes

In September 2017, we issued an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (collectively, the “CQP Guarantors”). Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2016 CQP Credit Facilities of $25 million during the year ended December 31, 2017.

Borrowings under the 2025 CQP Senior Notes accrue interest at a fixed rate of 5.250%, and interest on the 2025 CQP Senior Notes is payable semi-annually in arrears. The 2025 CQP Senior Notes are governed by an indenture (the “CQP Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2020, we may redeem all or a part of the 2025 CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the 2025 CQP Senior Notes redeemed, plus the “applicable premium” set forth in the CQP Indenture, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020, we may redeem up to 35% of the aggregate principal amount of the 2025 CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. We also may

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

at any time on or after October 1, 2020 through the maturity date of October 1, 2025, redeem the 2025 CQP Senior Notes, in whole or in part, at the redemption prices set forth in the CQP Indenture.

The 2025 CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. The 2025 CQP Senior Notes will be secured alongside the 2016 CQP Credit Facilities on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2016 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 2016 CQP Credit Facilities). The liens securing the 2025 CQP Senior Notes would be released if (1) the aggregate principal amount of all indebtedness then outstanding under the term loans under the 2016 CQP Credit Facilities secured by such liens does not exceed $1.0 billion and (2) the aggregate amount of our secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the 2025 CQP Senior Notes or any other series of notes issued under the CQP Indenture) outstanding at any one time, together with all Attributable Indebtedness (as defined in the CQP Indenture) from sale-leaseback transactions (subject to certain exceptions), does not exceed the greater of (1) $1.5 billion and (2) 10% of net tangible assets. Upon the release of the liens securing the 2025 CQP Senior Notes, the limitation on liens covenant under the CQP Indenture will continue to govern the incurrence of liens by us and the CQP Guarantors.

In connection with the closing of the sale of the 2025 CQP Senior Notes, we and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, we and the CQP Guarantors have agreed to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2025 CQP Senior Notes for a like aggregate principal amount of our debt securities with terms identical in all material respects to the 2025 CQP 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 September 18, 2017. Under specified circumstances, we and the CQP Guarantors have also agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2025 CQP Senior Notes. We will be obligated to pay additional interest on the 2025 CQP Senior Notes if we fail to comply with our obligation to register the 2025 CQP Senior Notes within the specified time period.

Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2017 (in millions):

		SPL Working Capital Facility				2016 CQP Credit Facilities
Original facility size		$	1,200			$	2,800
Less:
Outstanding balance		—				1,090
Commitments prepaid or terminated		—				1,470
Letters of credit issued		730				20
Available commitment		$	470			$	220
Interest rate		LIBOR plus 1.75% or base rate plus 0.75%				LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date		December 31, 2020, with various terms for underlying loans				February 25, 2020, with principal payments due quarterly commencing on March 31, 2019

(1)	There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

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.

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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, 2017, no LC Draws 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.

2016 CQP Credit Facilities

In February 2016, we entered into the 2016 CQP Credit Facilities. The 2016 CQP Credit Facilities consist of: (1) a $450 million CTPL tranche term loan that was used to prepay the $400 million term loan facility (the “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 senior notes previously issued by SPLNG in November 2016, (3) a $125 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 million revolving credit facility that may be used for general business purposes. In September 2017, we issued the 2025 CQP Senior Notes and the net proceeds of the issuance were used to prepay $1.5 billion of the outstanding indebtedness under the 2016 CQP Credit Facilities.

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 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, with principal payments due quarterly commencing on March 31, 2019. 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,

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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 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 1.15x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55x 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 (1) SPL and (2) certain of our subsidiaries owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Restrictive Debt Covenants

As of December 31, 2017, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

Total interest expense consisted of the following (in millions):

		Year Ended December 31,
		2017				2016				2015
Total interest cost		$	902			$	841			$	708
Capitalized interest		(288		)		(484		)		(523		)
Total interest expense, net		$	614			$	357			$	185

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):

		December 31, 2017								December 31, 2016
		Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
Senior notes, net of premium or discount (1)		$	14,360			$	15,485			$	11,513			$	12,309
2037 SPL Senior Notes (2)		800				871				—				—
Credit facilities (3)		1,090				1,090				3,098				3,098

(1)	Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2025 CQP Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

(2)	The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

(3)	Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 12—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
LNG revenues		$	2,615			$	535			$	—
LNG revenues—affiliate		1,389				294				—
Regasification revenues		260				259				259
Other revenues		20				4				7
Other revenues—affiliate		—				4				4
Total revenues from customers		4,284				1,096				270
Revenues from derivative instruments (1)		20				4				—
Total revenues		$	4,304			$	1,100			$	270

(1)	Relates to the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a Free on Board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the optional exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the optional exception, variable consideration related to the sale of LNG is also not included in the transaction price.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6.

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During the year ended December 31, 2017, SPL recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in millions):

		Year Ended December 31,
		2017				2016				2015
Deferred revenues, beginning of period		$	78			$	36			$	40
Cash received but not yet recognized		110				71				25
Revenue recognized from prior period deferral		(76		)		(29		)		(29		)
Deferred revenues, end of period		$	112			$	78			$	36

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2017 and 2016 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. Changes in deferred revenue during the years ended December 31, 2017, 2016 and 2015 are also attributable to differences between the timing of revenue recognition and the receipt of advance payments under our TUAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:

		Unsatisfied Transaction Price (in billions)				Weighted Average Recognition Timing (years) (1)
LNG revenues		$	55.7			10.2
Regasification revenues		2.9				5.7
Total revenues		$	58.6

    

(1)	The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

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We have elected the following optional exemptions which omit certain potential future sources of revenue from the table above:

(1)	We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During the year ended December 31, 2017, approximately 58% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 2% of our Regasification revenues were related to variable consideration received from customers.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 13—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, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA		$	1,389			$	294			$	—
Other revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG		—				1				1
Terminal Marine Services Agreement		—				3				3
Total other revenues—affiliate		—				4				4
Cost of sales—affiliate
Fees under the Pre-commercial LNG Marketing Agreement		—				2				—
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG		—				1				1
Services Agreements		94				51				28
Other agreements		6				—				—
Total operating and maintenance expense—affiliate		100				52				29
Development expense—affiliate
Services Agreements		—				—				1
General and administrative expense—affiliate
Services Agreements		80				90				122

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 May 2016.

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 Consolidated 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, 2017, 2016 and 2015, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

Cheniere Marketing has 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

SPL has 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

Under the Cheniere Marketing Master SPA, SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

SPL has 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, 2017 and 2016, we had $36 million and $38 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.

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Cheniere Partners Services Agreement

We have 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 $3 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 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 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 pays 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 is required 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 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 pays a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

SPL O&M Agreement

SPL has 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 each Train of 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 each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, 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 Train 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 the 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 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. Prior to the substantial completion of each Train of the Liquefaction Project, SPL pays

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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 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.

 

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 $25 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 both December 31, 2017 and 2016, we had $25 million 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.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an 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

SPLNG and Cheniere Marketing have an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the years ended December 31, 2017, 2016 and 2015.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which 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

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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.

SPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which 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.

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which 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.

NOTE 14—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 Statement of Partners’ Equity. On January 23, 2018, we declared a $0.50 distribution per common unit and subordinated unit and the related distribution to our general partner and IDRs, which was paid on February 14, 2018 to unitholders of record as of February 2, 2018 for the period from October 1, 2017 to December 31, 2017.

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. 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, which were mandatorily converted into our common units in accordance with the terms of our partnership agreement on August 2, 2017, were issued at a discount to the market price of the common units into which they were convertible.  This discount, totaling $2,130 million, represented a beneficial conversion feature and was 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 Statement of Partners’ Equity.  The beneficial conversion feature was considered a dividend that was distributed ratably with respect to any Class B unit from its issuance date through its conversion date, which resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortized the beneficial conversion feature through the mandatory conversion date of August 2, 2017 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 was also included in earnings per unit for the years ended December 31, 2017, 2016 and 2015.

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The following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units, the subordinated units, the general partner units and IDRs for purposes of computing net loss per unit (in millions, except per unit data).

						Limited Partner Units
		Total				Common Units				Class B Units				Subordinated Units				General Partner Units				IDR
Year Ended December 31, 2017
Net income		$	490
Declared distributions		514				376				—				127				10				1
Amortization of beneficial conversion feature of Class B units		—				(594		)		2,004				(1,410		)		—				—
Assumed allocation of undistributed net loss (1)		$	(24	)		(17		)		—				(7		)		—				—
Assumed allocation of net income						$	(235	)		$	2,004			$	(1,290	)		$	10			$	1
Weighted average units outstanding						178.5				84.8				135.4
Net loss per unit (2)						$	(1.32	)						$	(9.52	)
Year Ended December 31, 2016
Net loss		$	(171	)
Declared distributions		99				97				—				—				2				—
Amortization of beneficial conversion feature of Class B units		—				(29		)		100				(71		)		—				—
Assumed allocation of undistributed net loss		$	(270	)		(79		)		—				(186		)		(5		)		—
Assumed allocation of net loss						$	(11	)		$	100			$	(257	)		$	(3	)		$	—
Weighted average units outstanding						57.1				145.3				135.4
Net loss per unit (2)						$	(0.20	)						$	(1.90	)
Year Ended December 31, 2015
Net loss		$	(319	)
Declared distributions		99				97				—				—				2				—
Assumed allocation of undistributed net loss		$	(418	)		(121		)		—				(288		)		(8		)		—
Assumed allocation of net loss						$	(24	)		$	—			$	(288	)		$	(6	)		$	—
Weighted average units outstanding						57.1				145.3				135.4
Net loss per unit (2)						$	(0.43	)						$	(2.13	)

 

(1)	Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss).

(2)	Earnings per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

NOTE 15—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $13 million, $11 million and $10 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.

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Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in millions): 

Years Ending December 31,	Operating Leases (1)
2018	$	2
2019	2
2020	2
2021	2
2022	2
Thereafter	45
Total	$	55

(1)	Includes certain lease option renewals that are reasonably assured.

NOTE 16—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, 2017, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contract

SPL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 5 of the Liquefaction Project. The EPC contract for Train 5 provides that SPL will pay Bechtel a contract price of $3.1 billion, subject to adjustment by change order.  SPL has the right to terminate the 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 million depending on the termination date.

Obligations under SPAs

SPL has third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project.

Obligations under LNG TUAs

 

SPLNG has 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 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, 2017, SPL has secured up to approximately 2,214 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent were met.

Additionally, SPL has transportation and storage service agreements for the Liquefaction Project. The initial terms of the transportation agreements range from one to 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The terms of the SPL storage service agreements range from three to ten years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

As of December 31, 2017, SPL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions): 

Years Ending December 31,	Payments Due (1)
2018	$	2,274
2019	1,527
2020	1,397
2021	981
2022	336
Thereafter	1,169
Total	$	7,684

(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, 2017.

Services Agreements

 

We have certain services agreements with affiliates. See Note 13—Related Party Transactions for information regarding such agreements.

 

Restricted Net Assets

 

At December 31, 2017, our restricted net assets of consolidated subsidiaries were approximately $2.1 billion.

Other Commitments

 

State Tax Sharing Agreements

 

SPLNG, SPL and CTPL have state tax sharing agreements with Cheniere. See Note 13—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 15—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, 2017, 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.

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NOTE 17—CUSTOMER CONCENTRATION

  

The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:

		Percentage of Total Third-Party Revenues						Percentage of Accounts Receivable from Third Parties
		Year Ended December 31,						December 31,
		2017		2016		2015		2017		2016
Customer A		39%		52%		—%		39%		47%
Customer B		27%		*		—%		32%		50%
Customer C		23%		—%		—%		26%		—%

* Less than 10%

During the year ended December 31, 2017, revenues from external customers that were derived from domestic customers was $1.4 billion and from customers outside of the United States was $1.5 billion, of which $787 million and $666 million were from customers in Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $677 million and from customers outside of the United States was $125 million. We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION

 

The following table provides supplemental disclosure of cash flow information (in millions):

	Year Ended December 31,
	2017				2016				2015
Cash paid during the period for interest, net of amounts capitalized	$	510			$	242			$	136
Non-cash conveyance of assets	—				—				13

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $273 million, $267 million and $231 million as of December 31, 2017, 2016 and 2015, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 19—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:

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 will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 12—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto		This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and 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. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
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.

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Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:

Standard		Description		Date of Adoption		Effect on our Consolidated Financial Statements or Other Significant Matters
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 did not have a material impact on our Consolidated Financial Statements or related disclosures.

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NOTE 20—SUPPLEMENTAL GUARANTOR INFORMATION

Our 2025 CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (the “CQP Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the CQP Indenture. See Note 11—Debt for additional information regarding the 2025 CQP Senior Notes.

The following is condensed consolidating financial information for CQP (“Parent Issuer”), the CQP Guarantors on a combined basis and SPL (“Non-Guarantor”). We have accounted for investments in subsidiaries using the equity method.

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Condensed Consolidating Balance Sheet
December 31, 2017
(in millions)
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—			$	—			$	—			$	—			$	—
Restricted cash	1,033				12				544				—				1,589
Accounts and other receivables	—				2				189				—				191
Accounts receivable—affiliate	—				36				163				(36		)		163
Advances to affiliate	—				20				26				(10		)		36
Inventory	—				10				85				—				95
Other current assets	8				3				54				—				65
Other current assets—affiliate	—				—				21				(21		)		—
Total current assets	1,041				83				1,082				(67		)		2,139
Property, plant and equipment, net	80				2,164				12,920				(25		)		15,139
Debt issuance costs, net	20				—				18				—				38
Non-current derivative assets	14				—				17				—				31
Investments in subsidiaries	2,076				(63		)		—				(2,013		)		—
Other non-current assets, net	—				37				169				—				206
Total assets	$	3,231			$	2,221			$	14,206			$	(2,105	)		$	17,553
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—			$	4			$	8			$	—			$	12
Accrued liabilities	23				8				606				—				637
Due to affiliates	—				47				66				(45		)		68
Deferred revenue	—				27				84				—				111
Deferred revenue—affiliate	—				22				—				(21		)		1
Other current liabilities—affiliate	—				1				—				(1		)		—
Total current liabilities	23				109				764				(67		)		829
Long-term debt, net	2,569				—				13,477				—				16,046
Non-current deferred revenue	—				1				—				—				1
Non-current derivative liabilities	—				—				3				—				3
Other non-current liabilities	—				10				—				—				10
Other non-current liabilities—affiliate	—				25				—				—				25
Partners’ equity (deficit)	639				2,076				(38		)		(2,038		)		639
Total liabilities and partners’ equity (deficit)	$	3,231			$	2,221			$	14,206			$	(2,105	)		$	17,553

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Balance Sheet
December 31, 2016
(in millions)
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—			$	—			$	—			$	—			$	—
Restricted cash	234				13				358				—				605
Accounts and other receivables	—				—				90				—				90
Accounts receivable—affiliate	—				24				100				(25		)		99
Advances to affiliate	—				12				26				—				38
Inventory	—				8				89				—				97
Other current assets	—				4				25				—				29
Other current assets—affiliate	—				—				10				(10		)		—
Total current assets	234				61				698				(35		)		958
Property, plant and equipment, net	79				2,219				11,875				(15		)		14,158
Debt issuance costs, net	63				—				58				—				121
Non-current derivative assets	16				—				67				—				83
Investments in subsidiaries	2,617				471				—				(3,088		)		—
Other non-current assets, net	—				37				185				—				222
Total assets	$	3,009			$	2,788			$	12,883			$	(3,138	)		$	15,542
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	1			$	3			$	23			$	—			$	27
Accrued liabilities	2				9				407				—				418
Current debt	—				—				224				—				224
Due to affiliates	—				89				33				(23		)		99
Deferred revenue	—				27				46				—				73
Deferred revenue—affiliate	—				11				—				(10		)		1
Derivative liabilities	3				—				11				—				14
Total current liabilities	6				139				744				(33		)		856
Long-term debt, net	2,560				—				11,649				—				14,209
Non-current deferred revenue	—				5				—				—				5
Non-current derivative liabilities	—				—				2				—				2
Other non-current liabilities—affiliate	—				27				2				(2		)		27
Partners’ equity	443				2,617				486				(3,103		)		443
Total liabilities and partners’ equity	$	3,009			$	2,788			$	12,883			$	(3,138	)		$	15,542

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Condensed Consolidating Statement of Operations
Year Ended December 31, 2017
(in millions)
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
Revenues
LNG revenues	$	—			$	—			$	2,635			$	—			$	2,635
LNG revenues—affiliate	—				—				1,389				—				1,389
Regasification revenues	—				260				—				—				260
Regasification revenues—affiliate	—				190				—				(190		)		—
Other revenues	—				20				—				—				20
Other revenues—affiliate	—				218				—				(218		)		—
Total revenues	—				688				4,024				(408		)		4,304
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—				1				2,317				2				2,320
Cost of sales—affiliate	—				—				23				(23		)		—
Operating and maintenance expense	4				45				243				—				292
Operating and maintenance expense—affiliate	6				137				329				(372		)		100
Development expense	—				1				2				—				3
General and administrative expense	4				1				7				—				12
General and administrative expense—affiliate	11				15				58				(4		)		80
Depreciation and amortization expense	2				74				264				(1		)		339
Other	—				2				—				—				2
Total operating costs and expenses	27				276				3,243				(398		)		3,148
Income (loss) from operations	(27		)		412				781				(10		)		1,156
Other income (expense)
Interest expense, net of capitalized interest	(111		)		(9		)		(494		)		—				(614		)
Loss on early extinguishment of debt	(25		)		—				(42		)		—				(67		)
Derivative gain (loss), net	6				—				(2		)		—				4
Equity earnings of subsidiaries	643				250				—				(893		)		—
Other income	4				—				7				—				11
Total other income (expense)	517				241				(531		)		(893		)		(666		)
Net income	$	490			$	653			$	250			$	(903	)		$	490

39

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Operations
Year Ended December 31, 2016
(in millions)
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
Revenues
LNG revenues	$	—			$	—			$	539			$	—			$	539
LNG revenues—affiliate	—				—				294				—				294
Regasification revenues	—				259				—				—				259
Regasification revenues—affiliate	—				61				—				(61		)		—
Other revenues	—				4				—				—				4
Other revenues—affiliate	—				163				—				(159		)		4
Total revenues	—				487				833				(220		)		1,100
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—				—				416				(6		)		410
Cost of sales—affiliate	—				—				7				(5		)		2
Operating and maintenance expense	5				48				72				2				127
Operating and maintenance expense—affiliate	—				113				129				(190		)		52
Development expense—affiliate	—				—				1				(1		)		—
General and administrative expense	4				2				7				—				13
General and administrative expense—affiliate	12				15				68				(5		)		90
Depreciation and amortization expense	1				72				83				—				156
Total operating costs and expenses	22				250				783				(205		)		850
Income (loss) from operations	(22		)		237				50				(15		)		250
Other income (expense)
Interest expense, net of capitalized interest	(23		)		(148		)		(186		)		—				(357		)
Loss on early extinguishment of debt	—				(20		)		(52		)		—				(72		)
Derivative gain (loss), net	12				—				(6		)		—				6
Equity losses of subsidiaries	(138		)		(193		)		—				331				—
Other income	—				1				1				—				2
Total other expense	(149		)		(360		)		(243		)		331				(421		)
Net loss	$	(171	)		$	(123	)		$	(193	)		$	316			$	(171	)

40

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Operations
Year Ended December 31, 2015
(in millions)
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
Revenues
Regasification revenues	$	—			$	259			$	—			$	—			$	259
Other revenues	—				7				—				—				7
Other revenues—affiliate	—				108				—				(104		)		4
Total revenues	—				374				—				(104		)		270
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	—				1				(32		)		—				(31		)
Operating and maintenance expense	3				36				23				—				62
Operating and maintenance expense—affiliate	—				94				1				(66		)		29
Development expense	—				—				3				—				3
Development expense—affiliate	—				1				1				(1		)		1
General and administrative expense	3				6				6				—				15
General and administrative expense—affiliate	11				60				88				(37		)		122
Depreciation and amortization expense	—				64				2				—				66
Total operating costs and expenses	17				262				92				(104		)		267
Income (loss) from operations	(17		)		112				(92		)		—				3
Other income (expense)
Interest expense, net of capitalized interest	—				(175		)		(36		)		26				(185		)
Loss on early extinguishment of debt	—				—				(96		)		—				(96		)
Derivative loss, net	—				—				(42		)		—				(42		)
Equity losses of subsidiaries	(302		)		(266		)		—				568				—
Other income	—				1				—				—				1
Total other expense	(302		)		(440		)		(174		)		594				(322		)
Net loss	$	(319	)		$	(328	)		$	(266	)		$	594			$	(319	)

41

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
(in millions)
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
Cash flows provided by (used in) operating activities	$	(101	)		$	431			$	657			$	(10	)		$	977
Cash flows from investing activities
Property, plant and equipment, net	—				(21		)		(1,279		)		10				(1,290		)
Investments in subsidiaries	(245		)		(7		)		—				252				—
Distributions received from affiliates, net	1,431				782				—				(2,213		)		—
Net cash provided by (used in) investing activities	1,186				754				(1,279		)		(1,951		)		(1,290		)
Cash flows from financing activities
Proceeds from issuances of debt	1,500				—				2,314				—				3,814
Repayments of debt	(1,470		)		—				(703		)		—				(2,173		)
Debt issuance and deferred financing costs	(22		)		—				(28		)		—				(50		)
Distributions to parent	—				(1,431		)		(782		)		2,213				—
Contributions from parent	—				245				7				(252		)		—
Distributions to owners	(294		)		—				—				—				(294		)
Net cash provided by (used in) financing activities	(286		)		(1,186		)		808				1,961				1,297
Net increase (decrease) in cash, cash equivalents and restricted cash	799				(1		)		186				—				984
Cash, cash equivalents and restricted cash—beginning of period	234				13				358				—				605
Cash, cash equivalents and restricted cash—end of period	$	1,033			$	12			$	544			$	—			$	1,589

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2017
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
Cash and cash equivalents	$	—			$	—			$	—			$	—			$	—
Restricted cash	1,033				12				544				—				1,589
Total cash, cash equivalents and restricted cash	$	1,033			$	12			$	544			$	—			$	1,589

42

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2016
(in millions)
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
Cash flows provided by (used in) operating activities	$	(53	)		$	181			$	(130	)		$	2			$	—
Cash flows from investing activities
Property, plant and equipment, net	—				(7		)		(2,306		)		(2		)		(2,315		)
Investments in subsidiaries	(2,429		)		(1		)		—				2,430				—
Distributions received from affiliates, net	218				—				—				(218		)		—
Other	—				(6		)		(32		)		—				(38		)
Net cash used in investing activities	(2,211		)		(14		)		(2,338		)		2,210				(2,353		)
Cash flows from financing activities
Proceeds from issuances of debt	2,560				—				5,443				—				8,003
Repayments of debt	—				(2,486		)		(2,765		)		—				(5,251		)
Debt issuance and deferred financing costs	(73		)		—				(42		)		—				(115		)
Debt extinguishment costs	—				(14		)		—				—				(14		)
Distributions to parent	—				(218		)		—				218				—
Contributions from parent	—				2,429				1				(2,430		)		—
Distributions to owners	(99		)		—				—				—				(99		)
Net cash provided by (used in) financing activities	2,388				(289		)		2,637				(2,212		)		2,524
Net increase (decrease) in cash, cash equivalents and restricted cash	124				(122		)		169				—				171
Cash, cash equivalents and restricted cash—beginning of period	110				135				189				—				434
Cash, cash equivalents and restricted cash—end of period	$	234			$	13			$	358			$	—			$	605

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2016
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
Cash and cash equivalents	$	—			$	—			$	—			$	—			$	—
Restricted cash	234				13				358				—				605
Total cash, cash equivalents and restricted cash	$	234			$	13			$	358			$	—			$	605

43

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2015
(in millions)
	Parent Issuer				Guarantors				Non-Guarantor				Eliminations				Consolidated
Cash flows provided by (used in) operating activities	$	(43	)		$	53			$	(207	)		$	26			$	(171	)
Cash flows from investing activities
Property, plant and equipment, net	(1		)		(25		)		(2,861		)		(26		)		(2,913		)
Investments in subsidiaries	(53		)		(15		)		—				68				—
Distributions received from affiliates, net	84				—				—				(84		)		—
Other	—				—				(62		)		—				(62		)
Net cash provided by (used in) investing activities	30				(40		)		(2,923		)		(42		)		(2,975		)
Cash flows from financing activities
Proceeds from issuances of debt	—				—				2,860				—				2,860
Debt issuance and deferred financing costs	—				(1		)		(169		)		—				(170		)
Distributions to parent	—				(84		)		—				84				—
Contributions from parent	—				53				15				(68		)		—
Distributions to owners	(99		)		—				—				—				(99		)
Net cash provided by (used in) financing activities	(99		)		(32		)		2,706				16				2,591
Net decrease in cash, cash equivalents and restricted cash	(112		)		(19		)		(424		)		—				(555		)
Cash, cash equivalents and restricted cash—beginning of period	222				154				613				—				989
Cash, cash equivalents and restricted cash—end of period	$	110			$	135			$	189			$	—			$	434

44

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PART IV

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(c) Financial statements of affiliates whose securities are pledged as collateral — See Index to Financial Statements on page S-1.

The accompanying financial statements of our subsidiaries, Cheniere Energy Investments, LLC, Sabine Pass LNG-LP, LLC, Sabine Pass LNG, L.P. and Cheniere Creole Trail Pipeline, L.P., are being provided pursuant to Rule 3-16 of Regulation S-X, which requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS OF SUBSIDIARIES INCLUDED

PURSUANT TO RULE 3-16 OF REGULATION S-X

AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF CHENIERE ENERGY INVESTMENTS, LLC	S-2
Independent Auditors’ Report	S-5
Consolidated Balance Sheets	S-7
Consolidated Statements of Operations	S-8
Consolidated Statements of Member’s Equity	S-9
Consolidated Statements of Cash Flows	S-10
Notes to Consolidated Financial Statements	S-11
Schedule I—Condensed Financial Information of Registrant	S-35
AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF SABINE PASS LNG-LP, LLC	S-40
Independent Auditors’ Report	S-43
Consolidated Balance Sheets	S-45
Consolidated Statements of Operations	S-46
Consolidated Statements of Member’s Equity	S-47
Consolidated Statements of Cash Flows	S-48
Notes to Consolidated Financial Statements	S-49
Schedule I—Condensed Financial Information of Registrant	S-73
AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF SABINE PASS LNG, L.P.	S-77
Independent Auditors’ Report	S-80
Consolidated Balance Sheets	S-81
Consolidated Statements of Income	S-82
Consolidated Statements of Partners’ Equity (Deficit)	S-83
Consolidated Statements of Cash Flows	S-84
Notes to Consolidated Financial Statements	S-85
AUDITED FINANCIAL STATEMENTS OF CHENIERE CREOLE TRAIL PIPELINE, L.P.	S-99
Independent Auditors’ Report	S-100
Balance Sheets	S-101
Statements of Operations	S-102
Statements of Partners’ Equity	S-103
Statements of Cash Flows	S-104
Notes to Financial Statements	S-105

S-1

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Cheniere Energy Investments, LLC

Consolidated Financial Statements

As of December 31, 2017 and 2016

and for the years ended December 31, 2017, 2016 and 2015

S-2

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

DEFINITIONS

As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

Bcf/d		billion cubic feet per day
Bcfe		billion cubic feet equivalent
EPC		engineering, procurement and construction
FERC		Federal Energy Regulatory Commission
GAAP		generally accepted accounting principles in the United States
Henry Hub		the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR		London Interbank Offered Rate
LNG		liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu		million British thermal units, an energy unit
mtpa		million tonnes per annum
SPA		LNG sale and purchase agreement
TBtu		trillion British thermal units, an energy unit
Train		an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA		terminal use agreement

S-3

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2017, including our ownership of certain subsidiaries, and the references to these entities used in these Consolidated Financial Statements:

Unless the context requires otherwise, references to “Cheniere Investments,” “the Company,” “we,” “us” and “our” refer to Cheniere Energy Investments, LLC and its consolidated subsidiaries, including SPLNG, SPL and CTPL. 

S-4

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Independent Auditors’ Report

To the Member of Cheniere Energy Investments, LLC:

We have audited the accompanying consolidated financial statements of Cheniere Energy Investments, LLC and its subsidiaries (the Company), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, and the related consolidated statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cheniere Energy Investments, LLC and its subsidiaries as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the consolidated financial statements, in 2017, 2016 and 2015, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

S-5

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Other Matter

Our audit was conducted for the purpose of forming an opinion on the consolidated financial statements as a whole. The financial statement schedule I is presented for purposes of additional analysis and is not a required part of the consolidated financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the consolidated financial statements. The information has been subjected to the auditing procedures applied in the audit of the consolidated financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the consolidated financial statements or to the consolidated financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States of America. In our opinion, the information is fairly stated in all material respects in relation to the consolidated financial statements as a whole.

/s/ KPMG LLP

Houston, Texas

June 15, 2018

S-6

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions)

		December 31,
		2017				2016
ASSETS
Current assets
Cash and cash equivalents		$	—			$	—
Restricted cash		557				371
Accounts and other receivables		190				90
Accounts receivable—affiliate		163				99
Advances to affiliate		36				38
Inventory		95				97
Other current assets		56				27
Other current assets—affiliate		1				1
Total current assets		1,098				723
Property, plant and equipment, net		15,059				14,079
Debt issuance costs, net		18				59
Non-current derivative assets		17				67
Other non-current assets, net		206				222
Total assets		$	16,398			$	15,150
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable		$	12			$	27
Accrued liabilities		614				415
Current debt		—				224
Due to affiliates		68				73
Deferred revenue		111				73
Derivative liabilities		—				11
Other current liabilities—affiliate		1				1
Total current liabilities		806				824
Long-term debt, net		13,477				11,649
Non-current deferred revenue		1				5
Non-current derivative liabilities		3				2
Other non-current liabilities		10				—
Other non-current liabilities—affiliate		25				27
Commitments and contingencies (see Note 14)
Member’s equity		2,076				2,643
Total liabilities and member’s equity		$	16,398			$	15,150

The accompanying notes are an integral part of these consolidated financial statements.

S-7

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

	Year Ended December 31,
	2017				2016				2015
Revenues
LNG revenues	$	2,635			$	539			$	—
LNG revenues—affiliate	1,389				294				—
Regasification revenues	260				259				259
Other revenues	20				4				7
Other revenues—affiliate	—				4				4
Total revenues	4,304				1,100				270
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	2,320				410				(31		)
Cost of sales—affiliate	—				2				—
Operating and maintenance expense	287				122				60
Operating and maintenance expense—affiliate	93				52				29
Development expense	3				—				3
Development expense—affiliate	—				—				1
General and administrative expense	8				9				13
General and administrative expense—affiliate	68				78				110
Depreciation and amortization expense	338				155				65
Other	2				—				—
Total operating costs and expenses	3,119				828				250
Income from operations	1,185				272				20
Other income (expense)
Interest expense, net of capitalized interest	(503		)		(334		)		(211		)
Loss on early extinguishment of debt	(42		)		(72		)		(96		)
Derivative loss, net	(2		)		(6		)		(42		)
Other income	7				1				1
Total other expense	(540		)		(411		)		(348		)
Net income (loss)	$	645			$	(139	)		$	(328	)

The accompanying notes are an integral part of these consolidated financial statements.

S-8

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

(in millions)

	Cheniere Energy Partners, L.P.				Total Member’s Equity
Balance at December 31, 2014	$	880			$	880
Net loss	(328		)		(328		)
Contributions	91				91
Distributions	(84		)		(84		)
Balance at December 31, 2015	559				559
Net loss	(139		)		(139		)
Contributions	2,439				2,439
Distributions	(216		)		(216		)
Balance at December 31, 2016	2,643				2,643
Net income	645				645
Contributions	219				219
Distributions	(1,431		)		(1,431		)
Balance at December 31, 2017	$	2,076			$	2,076

The accompanying notes are an integral part of these consolidated financial statements.

S-9

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2017				2016				2015
Cash flows from operating activities
Net income (loss)	$	645			$	(139	)		$	(328	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Non-cash LNG inventory write-downs	—				—				18
Depreciation and amortization expense	338				155				65
Amortization of debt issuance costs, deferred commitment fees, premium and discount	19				20				12
Loss on early extinguishment of debt	42				72				96
Total losses (gains) on derivatives, net	26				(36		)		7
Net cash used for settlement of derivative instruments	(14		)		(7		)		(41		)
Other	11				—				1
Changes in operating assets and liabilities:
Accounts and other receivables	(100		)		(90		)		—
Accounts receivable—affiliate	(62		)		(98		)		1
Advances to affiliate	(12		)		—				(13		)
Inventory	13				(58		)		(25		)
Accounts payable and accrued liabilities	190				167				(3		)
Due to affiliates	(16		)		—				18
Deferred revenue	34				42				(4		)
Other, net	(6		)		(5		)		(10		)
Other, net—affiliate	(2		)		1				14
Net cash provided by (used in) operating activities	1,106				24				(192		)
Cash flows from investing activities
Property, plant and equipment, net	(1,290		)		(2,298		)		(2,885		)
Other	—				(38		)		(63		)
Net cash used in investing activities	(1,290		)		(2,336		)		(2,948		)
Cash flows from financing activities
Proceeds from issuances of debt	2,314				5,443				2,860
Repayments of debt	(703		)		(5,251		)		—
Debt issuance and deferred financing costs	(29		)		(42		)		(170		)
Debt extinguishment costs	—				(14		)		—
Capital contributions	219				2,439				91
Distributions	(1,431		)		(216		)		(84		)
Net cash provided by financing activities	370				2,359				2,697
Net increase (decrease) in cash, cash equivalents and restricted cash	186				47				(443		)
Cash, cash equivalents and restricted cash—beginning of period	371				324				767
Cash, cash equivalents and restricted cash—end of period	$	557			$	371			$	324

Balances per Consolidated Balance Sheets:

	December 31,
	2017				2016
Cash and cash equivalents	$	—			$	—
Restricted cash	557				371
Total cash, cash equivalents and restricted cash	$	557			$	371

The accompanying notes are an integral part of these consolidated financial statements.

S-10

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a Delaware limited liability company formed in 2006 by our sole member, Cheniere Partners, a publicly traded limited partnership. Through 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 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. Through SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We 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 CTPL.

NOTE 2—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 Investments and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto using the full retrospective method. We have elected to adopt the new accounting standard retrospectively for all periods presented.

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

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, derivative instruments, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.

 

Revenue Recognition

 

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. LNG regasification capacity payments are recognized as regasification revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents

 

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

 

Restricted Cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our 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 not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. During the year ended December 31, 2015, we recognized $18 million as operating and maintenance expense as a result of write-down for LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. We did not recognize any operating and maintenance expense related to inventory write-downs during the years ended December 31, 2017 and 2016.

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.

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Property, Plant and Equipment 

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. 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 did not record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015.

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 for and we elect the normal purchases

S-13

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

 

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded 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 SPAs with terms of at least 20 years with six unaffiliated third parties. SPL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration.

 

SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. SPLNG is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective TUAs.

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 Sheets. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on 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.

S-14

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

 

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 immaterial.

We have not 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 a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which directly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

At December 31, 2017, the tax basis of our assets and liabilities was $3.1 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our subsidiaries’ 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 Investments in total when evaluating financial performance and for purposes of allocating resources.

NOTE 3—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, 2017 and 2016, restricted cash consisted of the following (in millions):

		December 31,
		2017				2016
Current restricted cash
Liquefaction Project		$	544			$	358
Cash held by Cheniere Partners’ guarantor subsidiaries, including us		13				13
Total current restricted cash		$	557			$	371

Under the terms of the credit and guaranty agreement aggregating $2.8 billion that Cheniere Partners entered into in February 2016 (the “2016 CQP Credit Facilities”), Cheniere Partners’ guarantor subsidiaries are required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities. See Note 17—Guarantees for information regarding Cheniere Partners’ guarantor subsidiaries.

S-15

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2017 and 2016, accounts and other receivables consisted of the following (in millions):

		December 31,
		2017				2016
SPL trade receivable		$	185			$	88
Other accounts receivable		5				2
Total accounts and other receivables		$	190			$	90

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.

NOTE 5—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in millions):

		December 31,
		2017				2016
Natural gas		$	17			$	15
LNG		26				45
Materials and other		52				37
Total inventory		$	95			$	97

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in millions):

		December 31,
		2017				2016
LNG terminal costs
LNG terminal		$	12,663			$	7,956
LNG terminal construction-in-process		3,269				6,670
Accumulated depreciation		(879		)		(553		)
Total LNG terminal costs, net		15,053				14,073
Fixed assets
Fixed assets		23				19
Accumulated depreciation		(17		)		(13		)
Total fixed assets, net		6				6
Property, plant and equipment, net		$	15,059			$	14,079

 

Depreciation expense was $329 million, $147 million and $64 million in the years ended December 31, 2017, 2016 and 2015, respectively.

We realized offsets to LNG terminal costs of $301 million and $201 million in the years ended December 31, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction.

S-16

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

LNG Terminal Costs

The Sabine Pass LNG terminal and pipeline are 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

Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”). SPL had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of its credit facilities (“Interest Rate Derivatives”), which were settled in March 2017.

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2017 and 2016, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	December 31, 2017																December 31, 2016
	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
Interest Rate Derivatives liability	$	—			$	—			$	—			$	—			$	—			$	(6	)		$	—			$	(6	)
Liquefaction Supply Derivatives asset (liability)	2				10				43				55				(4		)		(2		)		79				73

We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data.

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2017:

		Net Fair Value Asset (in millions)		Valuation Approach		Significant Unobservable Input		Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives		$43		Market approach incorporating present value techniques		Basis Spread		$(0.503) - $0.432

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
Balance, beginning of period		$	79			$	32			$	—
Realized and mark-to-market gains (losses):
Included in cost of sales (1)		(37		)		48				32
Purchases and settlements:
Purchases		14				1				—
Settlements (1)		(12		)		(2		)		—
Transfers out of Level 3		(1		)		—				—
Balance, end of period		$	43			$	79			$	32
Change in unrealized gains relating to instruments still held at end of period		$	(37	)		$	49			$	32

    

(1)	Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position.  Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

SPL had entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “2015 SPL Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities. In March 2017, SPL settled the Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 10—Debt.

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets (in millions):

				Fair Value Measurements as of
		Consolidated Balance Sheet Location		December 31, 2017				December 31, 2016
Interest Rate Derivatives		Derivative liabilities		$	—			$	(4	)
Interest Rate Derivatives		Non-current derivative liabilities		—				(2		)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
Interest Rate Derivatives loss		$	(2	)		$	(6	)		$	(42	)

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges, if applicable, to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the noncurrent physical natural gas supply contracts range from approximately one to seven years, most of which commence upon the satisfaction of certain conditions precedent, if not already met, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

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.

SPL had secured up to approximately 2,214 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2017 and 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,520 TBtu and 1,117 TBtu as of December 31, 2017 and 2016, respectively.

The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):

		Fair Value Measurements as of (1)
Consolidated Balance Sheet Location		December 31, 2017				December 31, 2016
Other current assets		$	41			$	13
Non-current derivative assets		17				67
Total derivative assets		58				80
Derivative liabilities		—				(7		)
Non-current derivative liabilities		(3		)		—
Total derivative liabilities		(3		)		(7		)
Derivative asset, net		$	55			$	73

(1)	Does not include a collateral call of $1 million and a collateral deposit of $6 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively.

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):

			Year Ended December 31,
	Consolidated Statement of Operations Location (1)		2017				2016				2015
Liquefaction Supply Derivatives loss (gain) (2)	Cost (cost recovery) of sales		$	24			$	(42	)		$	(33	)

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(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.

Consolidated Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):

		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, 2017
Liquefaction Supply Derivatives		$	64			$	(6	)		$	58
Liquefaction Supply Derivatives		(3		)		—				(3		)
As of December 31, 2016
Interest Rate Derivatives		$	(6	)		$	—			$	(6	)
Liquefaction Supply Derivatives		82				(2		)		80
Liquefaction Supply Derivatives		(11		)		4				(7		)

NOTE 8—OTHER NON-CURRENT ASSETS

As of December 31, 2017 and 2016, other non-current assets, net consisted of the following (in millions):

		December 31,
		2017				2016
Advances made under EPC and non-EPC contracts		$	26			$	23
Advances made to municipalities for water system enhancements		93				95
Advances and other asset conveyances to third parties to support LNG terminals		30				31
Tax-related payments and receivables		25				28
Information technology service assets		24				27
Other		8				18
Total other non-current assets, net		$	206			$	222

NOTE 9—ACCRUED LIABILITIES

 

As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in millions):

		December 31,
		2017				2016
Interest costs and related debt fees		$	229			$	204
Sabine Pass LNG terminal and related pipeline costs		384				211
Other accrued liabilities		1				—
Total accrued liabilities		$	614			$	415

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 10—DEBT

 

As of December 31, 2017 and 2016, our debt consisted of the following (in millions):

		December 31,
		2017				2016
Long-term debt:
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7		$	2,006			$	2,007
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)		1,000				1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $6		1,505				1,506
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)		2,000				2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)		2,000				2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)		1,500				1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)		1,500				1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero		1,349				—
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)		800				—
2015 SPL Credit Facilities		—				314
Unamortized debt issuance costs		(183		)		(178		)
Total long-term debt, net		13,477				11,649
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)		—				224
Total debt, net		$	13,477			$	11,873

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, 2017 (in millions): 

Years Ending December 31,		Principal Payments
2018		$	—
2019		—
2020		—
2021		2,000
2022		1,000
Thereafter		10,650
Total		$	13,650

SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.

  

In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the year ended December 31, 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2027 SPL Senior Notes and 2028 SPL Senior Notes (collectively with the 2037 SPL Senior Notes, the “SPL Senior Notes”) are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain 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 or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. 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 test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. As of December 31, 2017, SPL was in compliance with all covenants related to the SPL Senior Notes. Interest on the SPL Senior Notes is payable semi-annually in arrears.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 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 (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, 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, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the 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.

SPL Working Capital Facility

Below is a summary of the SPL Working Capital Facility as of December 31, 2017 (in millions):

		SPL Working Capital Facility
Original facility size		$	1,200
Less:
Outstanding balance		—
Letters of credit issued		730
Available commitment		$	470
Interest rate		LIBOR plus 1.75% or base rate plus 0.75%
Maturity date		December 31, 2020, with various terms for underlying loans

In September 2015, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2017, no LC Draws 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. As of December 31, 2017, SPL was in compliance with all covenants related to the SPL Working Capital Facility. 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.

Interest Expense

Total interest expense consisted of the following (in millions):

		Year Ended December 31,
		2017				2016				2015
Total interest cost		$	788			$	797			$	704
Capitalized interest		(285		)		(463		)		(493		)
Total interest expense, net		$	503			$	334			$	211

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):

		December 31, 2017								December 31, 2016
		Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
Senior notes, net of premium or discount (1)		$	12,860			$	13,955			$	11,513			$	12,309
2037 SPL Senior Notes (2)		800				871				—				—
Credit facilities (3)		—				—				538				538

(1)	Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes and 2028 SPL Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

(2)	The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

(3)	Includes 2015 SPL Credit Facilities and SPL Working Capital Facility. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
LNG revenues		$	2,615			$	535			$	—
LNG revenues—affiliate		1,389				294				—
Regasification revenues		260				259				259
Other revenues		20				4				7
Other revenues—affiliate		—				4				4
Total revenues from customers		4,284				1,096				270
Revenues from derivative instruments (1)		20				4				—
Total revenues		$	4,304			$	1,100			$	270

(1)	Relates to the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a Free on Board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the optional exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the optional exception, variable consideration related to the sale of LNG is also not included in the transaction price.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6.

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During the year ended December 31, 2017, SPL recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in millions):

		Year Ended December 31,
		2017				2016				2015
Deferred revenues, beginning of period		$	78			$	36			$	40
Cash received but not yet recognized		110				71				25
Revenue recognized from prior period deferral		(76		)		(29		)		(29		)
Deferred revenues, end of period		$	112			$	78			$	36

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2017 and 2016 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. Changes in deferred revenue during the years ended December 31, 2017, 2016 and 2015 are also attributable to differences between the timing of revenue recognition and the receipt of advance payments under our TUAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:

		Unsatisfied Transaction Price (in billions)				Weighted Average Recognition Timing (years) (1)
LNG revenues		$	55.7			10.2
Regasification revenues		2.9				5.7
Total revenues		$	58.6

    

(1)	The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We have elected the following optional exemptions which omit certain potential future sources of revenue from the table above:

(1)	We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During the year ended December 31, 2017, approximately 58% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 2% of our Regasification revenues were related to variable consideration received from customers.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 12—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, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA		$	1,389			$	294			$	—
Other revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG		—				1				1
Terminal Marine Services Agreement		—				3				3
Total other revenues—affiliate		—				4				4
Cost of sales—affiliate
Fees under the Pre-commercial LNG Marketing Agreement		—				2				—
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG		—				1				1
Services Agreements		93				51				28
Total operating and maintenance expense—affiliate		93				52				29
Development expense—affiliate
Services Agreements		—				—				1
General and administrative expense—affiliate
Services Agreements		68				78				111

LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0 Bcf/d of regasification capacity and other liquefaction support services 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

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 May 2016.

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 had the right to use SPL’s reserved capacity under the TUA and had 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 Consolidated Financial Statements. Cheniere Partners has 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, LLC (“Cheniere Marketing US”) has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing US is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing US arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing US during the years ended December 31, 2017, 2016 and 2015 related to the Amended and Restated VCRA.

Cheniere Marketing SPA

Cheniere Marketing has 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

SPL has 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

Under the Cheniere Marketing Master SPA, SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

SPL has 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, 2017 and 2016, we had $36 million and $38 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere. On a quarterly basis, our subsidiaries 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

SPLNG O&M Agreement

SPLNG has 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 pays 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 is required 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 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 pays a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

SPL O&M Agreement

SPL has 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 each Train of 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 each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, 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 Train 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 the 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 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. Prior to the substantial completion of each Train of the Liquefaction Project, 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 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 Cheniere Investments 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.

 

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

 

SPLNG has executed Cooperative Endeavor Agreements (“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-

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

year initiative represented an aggregate commitment of $25 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 both December 31, 2017 and 2016, we had $25 million of both other non-current assets resulting from SPLNG’s ad valorem tax payments and other 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 US. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing US at a sales price equal to the actual purchase price paid by Cheniere Marketing US to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing US with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an 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

SPLNG and Cheniere Marketing US have an LNG Terminal Export Agreement that provides Cheniere Marketing US the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the years ended December 31, 2017, 2016 and 2015.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which 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.

SPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which 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.

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which 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

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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.

NOTE 13—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $13 million, $11 million and $10 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 millions): 

Years Ending December 31,	Operating Leases (1)
2018	$	2
2019	2
2020	2
2021	2
2022	2
Thereafter	45
Total	$	55

(1)	Includes certain lease option renewals that are reasonably assured.

NOTE 14—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, 2017, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contract

SPL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 5 of the Liquefaction Project. The EPC contract for Train 5 provides that SPL will pay Bechtel a contract price of $3.1 billion, subject to adjustment by change order.  SPL has the right to terminate the 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 million depending on the termination date.

Obligations under SPAs

SPL has third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project.

Obligations under LNG TUAs

 

SPLNG has third-party TUAs with Total 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 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 seven 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, 2017, SPL has secured up to approximately 2,214 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent were met.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Additionally, SPL has transportation and storage service agreements for the Liquefaction Project. The initial terms of the transportation agreements range from one to 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The terms of the SPL storage service agreements range from three to ten years.

As of December 31, 2017, SPL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions): 

Years Ending December 31,	Payments Due (1)
2018	$	2,274
2019	1,527
2020	1,397
2021	981
2022	336
Thereafter	1,169
Total	$	7,684

(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, 2017.

Obligations under LNG TUA

SPL has a partial TUA assignment agreement with Total, another TUA customer, whereby upon substantial completion of Train 3 in March 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.

Services Agreements

 

We have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements.

 

Restricted Net Assets

 

At December 31, 2017, our restricted net assets of consolidated subsidiaries were approximately $2.0 billion.

Other Commitments

 

State Tax Sharing Agreements

 

SPLNG, SPL and CTPL have state tax sharing agreements with Cheniere. See Note 12—Related Party Transactions for information regarding such agreements.

Other Agreements

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 13—Leases.

 

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2017, 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.

NOTE 15—CUSTOMER CONCENTRATION

  

The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:

		Percentage of Total Third-Party Revenues						Percentage of Accounts Receivable from Third Parties
		Year Ended December 31,						December 31,
		2017		2016		2015		2017		2016
Customer A		39%		52%		—%		39%		47%
Customer B		27%		*		—%		32%		50%
Customer C		23%		—%		—%		26%		—%

* Less than 10%

During the year ended December 31, 2017, revenues from external customers that were derived from domestic customers was $1.4 billion and from customers outside of the United States was $1.5 billion, of which $787 million and $666 million were from customers in Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $677 million and from customers outside of the United States was $125 million. During the year ended December 31, 2015, all revenues from external customers were derived from domestic customers. We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

 

The following table provides supplemental disclosure of cash flow information (in millions):

	Year Ended December 31,
	2017				2016				2015
Cash paid during the period for interest, net of amounts capitalized	$	438			$	231			$	135
Non-cash conveyance of assets	—				—				13

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $271 million, $265 million and $231 million as of December 31, 2017, 2016 and 2015, respectively.

NOTE 17—GUARANTEES

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities, which included an approximately $2.1 billion SPLNG tranche term loan and a $450.0 million CTPL tranche term loan that were used to satisfy our subsidiaries’ outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LP subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2017, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us but not including our non-guarantor subsidiary’s assets and rights, and our real property (except for certain excluded properties). As of December 31, 2017, the collateralized net assets of the CQP Guarantors was $2.1 billion.

NOTE 18—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:

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 will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 11—Revenues from Contracts with Customers.

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Standard		Description		Expected Date of Adoption		Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto		This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and 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 on 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. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
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 a recent accounting standard that was adopted by us during the reporting period:

Standard		Description		Date of Adoption		Effect on our Consolidated Financial Statements or Other Significant Matters
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 did not have a material impact on our Consolidated Financial Statements or related disclosures.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY INVESTMENTS, LLC

CONDENSED BALANCE SHEETS

(in millions) 

		December 31,
		2017				2016
ASSETS
Current assets
Cash and cash equivalents		$	—			$	—
Restricted cash		1				12
Accounts receivable—affiliate		31				21
Other current assets—affiliate		—				10
Total current assets		32				43
Investment in affiliates		2,011				2,591
Total assets		$	2,043			$	2,634
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Due to affiliates		$	31			$	63
Other non-current liabilities—affiliate		—				2
Member’s equity		2,012				2,569
Total liabilities and member’s equity		$	2,043			$	2,634

The accompanying notes are an integral part of these condensed financial statements.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY INVESTMENTS, LLC

CONDENSED STATEMENTS OF OPERATIONS

(in millions) 

		Year Ended December 31,
		2017				2016				2015
Revenues—affiliate		$	155			$	135			$	167
Operating and maintenance expense—affiliate		219				328				421
Loss from operations		(64		)		(193		)		(254		)
Equity income (loss) of affiliates		718				70				(74		)
Net income (loss)		$	654			$	(123	)		$	(328	)

The accompanying notes are an integral part of these condensed financial statements.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY INVESTMENTS, LLC

CONDENSED STATEMENTS OF CASH FLOWS

(in millions) 

	Year Ended December 31,
	2017				2016				2015
Cash provided by (used in) operating activities	$	475			$	(178	)		$	(245	)
Cash flows from investing activities
Investments in subsidiaries	(130		)		(2,422		)		(91		)
Distributions received from affiliates, net	856				360				337
Net cash provided by (used in) investing activities	726				(2,062		)		246
Cash flows from financing activities
Capital contributions	219				2,439				91
Distributions	(1,431		)		(216		)		(84		)
Net cash provided by (used in) financing activities	(1,212		)		2,223				7
Net increase (decrease) in cash, cash equivalents and restricted cash	(11		)		(17		)		8
Cash, cash equivalents and restricted cash—beginning of period	12				29				21
Cash, cash equivalents and restricted cash—end of period	$	1			$	12			$	29

Balances per Condensed Balance Sheets:

	December 31
	2017				2016
Cash and cash equivalents	$	—			$	—
Restricted cash	1				12
Total cash, cash equivalents and restricted cash	$	1			$	12

The accompanying notes are an integral part of these condensed financial statements.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY INVESTMENTS, LLC

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 Investments.

 

A substantial amount of Cheniere Investments’ operating, investing and financing activities are conducted by its affiliates. In the Condensed Financial Statements, Cheniere Investments’ 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.

We use the cumulative earnings approach for classifying distributions received from our equity method investees on the Condensed Statements of Cash Flows. The cumulative earnings approach dictates that distributions received by an investor are viewed as a return on investment and classified as cash flows from operating activities unless the cumulative distributions received exceed the cumulative equity in earnings recognized by the investor. Distributions received in excess of cumulative earnings are viewed as a return of investment and classified as cash flows from investing activities.

The Condensed Financial Statements should be read in conjunction with Cheniere Investments’ Consolidated Financial Statements.

NOTE 2—REVENUES FROM CONTRACTS WITH CUSTOMERS

Revenues—affiliate

Cheniere Investments has operation and maintenance agreements with SPLNG, SPL and CTPL whereby Cheniere Investments provides the services required to operate and maintain the regasification facilities at the Sabine Pass LNG terminal, the natural gas liquefaction facilities at the Sabine Pass LNG terminal (the “Liquefaction Project”) and the pipeline owned and operated by CTPL, respectively.

SPLNG pays a fixed monthly fee of $130,000 (indexed for inflation) under its operation and maintenance 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 is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses.

Under the operation and maintenance agreement with SPL, before each Train of 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 staffing reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, 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 Train 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 the Train.

CTPL is required to only reimburse Cheniere Investments for its operating expenses under its operation and maintenance agreement, which consist primarily of labor expenses.

Cheniere Investments provides the services required under each of the operation and maintenance agreements pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. Cheniere Investments is generally required to remit all fees received from its customers to such subsidiary. We have determined that Cheniere Investments is acting as a principal in each of these transactions given its control of the services prior to the transfer to the customers. Because Cheniere Investments is acting

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as a principal to the transactions, it recognizes consideration earned from customers within revenues—affiliate while it records operating and maintenance expense—affiliate when such fees are due to the subsidiary under the secondment agreement.

Because Cheniere Investments is providing operation and maintenance services to SPLNG and CTPL on a daily basis with the same pattern of transfer, we have concluded that Cheniere Investments provides a single performance obligation to each of these customers on a continuous basis over time. However, as the service Cheniere Investment provides SPL increases over time as Trains are constructed and enter service, we have determined that Cheniere Investments provides a separate performance obligation to SPL for each Train during both the construction and operational phases, each of which is also transferred to SPL on a continuous basis over time with the same pattern of transfer. For each customer, we have determined that an output method of recognition based on elapsed time best reflects the benefits of each of the services to the customers. We have concluded that the variable consideration within each contract, including inflation, the SPLNG bonus, the SPL fee based on capital expenditures and the operating expense reimbursements from each customer, meet the optional exception to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:

		Unsatisfied Transaction Price (in millions)				Weighted Average Recognition Timing (years) (1)
Revenues—affiliate		$	124			10.1

    

(1)	The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We have elected omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

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Sabine Pass LNG-LP, LLC

Consolidated Financial Statements

As of December 31, 2017 and 2016

and for the years ended December 31, 2017, 2016 and 2015

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

DEFINITIONS

As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

Bcf/d		billion cubic feet per day
Bcfe		billion cubic feet equivalent
EPC		engineering, procurement and construction
GAAP		generally accepted accounting principles in the United States
Henry Hub		the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR		London Interbank Offered Rate
LNG		liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu		million British thermal units, an energy unit
mtpa		million tonnes per annum
SPA		LNG sale and purchase agreement
TBtu		trillion British thermal units, an energy unit
Train		an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA		terminal use agreement

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2017, including our ownership of certain subsidiaries, and the references to these entities used in these Consolidated Financial Statements:

Unless the context requires otherwise, references to “Sabine Pass LP,” “the Company,” “we,” “us” and “our” refer to Sabine Pass LNG-LP, LLC and its consolidated subsidiaries, including SPL, SPLNG and Tug Services.

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Independent Auditors’ Report

To the Member of Sabine Pass LNG-LP, LLC:

We have audited the accompanying consolidated financial statements of Sabine Pass LNG-LP, LLC and its subsidiaries (the Company), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, and the related consolidated statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sabine Pass LNG-LP, LLC and its subsidiaries as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the consolidated financial statements, in 2017, 2016 and 2015, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

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Other Matter

Our audit was conducted for the purpose of forming an opinion on the consolidated financial statements as a whole. The financial statement schedule I is presented for purposes of additional analysis and is not a required part of the consolidated financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the consolidated financial statements. The information has been subjected to the auditing procedures applied in the audit of the consolidated financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the consolidated financial statements or to the consolidated financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States of America. In our opinion, the information is fairly stated in all material respects in relation to the consolidated financial statements as a whole.

/s/ KPMG LLP

Houston, Texas

June 15, 2018

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions)

		December 31,
		2017				2016
ASSETS
Current assets
Cash and cash equivalents		$	—			$	—
Restricted cash		556				359
Accounts and other receivables		190				90
Accounts receivable—affiliate		163				100
Advances to affiliate		32				32
Inventory		94				96
Other current assets		55				26
Other current assets—affiliate		1				1
Total current assets		1,091				704
Property, plant and equipment, net		14,518				13,512
Debt issuance costs, net		18				59
Non-current derivative assets		17				67
Other non-current assets, net		197				214
Total assets		$	15,841			$	14,556
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable		$	11			$	26
Accrued liabilities		613				415
Current debt		—				224
Due to affiliates		72				35
Deferred revenue		111				73
Deferred revenue—affiliate		1				11
Derivative liabilities		—				11
Total current liabilities		808				795
Long-term debt, net		13,477				11,649
Non-current deferred revenue		1				5
Non-current derivative liabilities		3				2
Other non-current liabilities		10				—
Other non-current liabilities—affiliate		25				26
Commitments and contingencies (see Note 14)
Member’s equity		1,517				2,079
Total liabilities and member’s equity		$	15,841			$	14,556

The accompanying notes are an integral part of these consolidated financial statements.

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

	Year Ended December 31,
	2017				2016				2015
Revenues
LNG revenues	$	2,635			$	539			$	—
LNG revenues—affiliate	1,389				294				—
Regasification revenues	260				259				259
Regasification revenues—affiliate	64				193				254
Other revenues	20				4				7
Other revenues—affiliate	—				4				3
Total revenues	4,368				1,293				523
Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	2,317				410				(31		)
Cost of sales—affiliate	—				2				—
Operating and maintenance expense	279				116				57
Operating and maintenance expense—affiliate	157				86				24
Development expense	3				—				3
Development expense—affiliate	—				—				1
General and administrative expense	7				8				9
General and administrative expense—affiliate	67				77				102
Depreciation and amortization expense	319				136				47
Other	2				—				—
Total operating costs and expenses	3,151				835				212
Income from operations	1,217				458				311
Other income (expense)
Interest expense, net of capitalized interest	(503		)		(333		)		(197		)
Loss on early extinguishment of debt	(42		)		(70		)		(96		)
Derivative loss, net	(2		)		(6		)		(42		)
Other income	7				1				—
Total other expense	(540		)		(408		)		(335		)
Net income (loss)	$	677			$	50			$	(24	)

The accompanying notes are an integral part of these consolidated financial statements.

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

(in millions)

	Cheniere Energy Investments, LLC				Total Member’s Equity
Balance at December 31, 2014	$	626			$	626
Contributions	74				74
Distributions	(347		)		(347		)
Net loss	(24		)		(24		)
Balance at December 31, 2015	329				329
Contributions	2,011				2,011
Distributions	(311		)		(311		)
Net income	50				50
Balance at December 31, 2016	2,079				2,079
Contributions	111				111
Distributions	(1,350		)		(1,350		)
Net income	677				677
Balance at December 31, 2017	$	1,517			$	1,517

The accompanying notes are an integral part of these consolidated financial statements.

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2017				2016				2015
Cash flows from operating activities
Net income (loss)	$	677			$	50			$	(24	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash LNG inventory write-downs	—				—				18
Depreciation and amortization expense	319				136				47
Amortization of debt issuance costs, deferred commitment fees, premium and discount	19				20				11
Loss on early extinguishment of debt	42				70				96
Total losses (gains) on derivatives, net	26				(36		)		7
Net cash used for settlement of derivative instruments	(14		)		(7		)		(41		)
Other	13				9				8
Changes in operating assets and liabilities:
Accounts and other receivables	(100		)		(90		)		—
Accounts receivable—affiliate	(62		)		(98		)		1
Advances to affiliate	(14		)		2				(10		)
Inventory	12				(58		)		(24		)
Accounts payable and accrued liabilities	190				168				(3		)
Due to affiliates	26				(6		)		11
Deferred revenue	34				42				(4		)
Other, net	(2		)		(5		)		(10		)
Other, net—affiliate	(12		)		(9		)		3
Net cash provided by operating activities	1,154				188				86
Cash flows from investing activities
Property, plant and equipment, net	(1,298		)		(2,307		)		(2,866		)
Other	—				(37		)		(62		)
Net cash used in investing activities	(1,298		)		(2,344		)		(2,928		)
Cash flows from financing activities
Proceeds from issuances of debt	2,314				5,443				2,860
Repayments of debt	(703		)		(4,851		)		—
Debt issuance and deferred financing costs	(29		)		(42		)		(169		)
Debt extinguishment costs	—				(14		)		—
Capital contributions	109				2,002				67
Distributions	(1,350		)		(311		)		(337		)
Net cash provided by financing activities	341				2,227				2,421
Net increase (decrease) in cash, cash equivalents and restricted cash	197				71				(421		)
Cash, cash equivalents and restricted cash—beginning of period	359				288				709
Cash, cash equivalents and restricted cash—end of period	$	556			$	359			$	288

Balances per Consolidated Balance Sheets:

	December 31,
	2017				2016
Cash and cash equivalents	$	—			$	—
Restricted cash	556				359
Total cash, cash equivalents and restricted cash	$	556			$	359

The accompanying notes are an integral part of these consolidated financial statements.

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a Delaware limited liability company formed in 2005 with one member, Cheniere Investments. Through 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 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. Through SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d.

NOTE 2—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 Sabine Pass LP and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto using the full retrospective method. We have elected to adopt the new accounting standard retrospectively for all periods presented.

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

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, derivative instruments, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.

 

Revenue Recognition

 

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. LNG regasification capacity payments are recognized as regasification revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents

 

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

 

Restricted Cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our 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 not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. During the year ended December 31, 2015, we recognized $18 million as operating and maintenance expense as a result of write-down for LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. We did not recognize any operating and maintenance expense related to inventory write-downs during the years ended December 31, 2017 and 2016.

Accounting for LNG Activities

 

Generally, we begin capitalizing the costs of our LNG terminals 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.

 

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. 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 (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

generally expensed 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 did not record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

 

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded 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 SPAs with terms of at least 20 years with six unaffiliated third parties. SPL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration.

 

SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. SPLNG is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective TUAs.

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.  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 Sheets. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on 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 immaterial.

Income Taxes 

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

At December 31, 2017, the tax basis of our assets and liabilities was $3.0 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our subsidiaries’ 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 Sabine Pass LP in total when evaluating financial performance and for purposes of allocating resources.

NOTE 3—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, 2017 and 2016, restricted cash consisted of the following (in millions):

		December 31,
		2017				2016
Current restricted cash
Liquefaction Project		$	544			$	358
Cash held by Cheniere Partners’ guarantor subsidiaries, including us		12				1
Total current restricted cash		$	556			$	359

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SABINE PASS LNG-LP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Under the terms of the credit and guaranty agreement aggregating $2.8 billion that Cheniere Partners entered into in February 2016 (the “2016 CQP Credit Facilities”), Cheniere Partners’ guarantor subsidiaries are required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities. See Note 17—Guarantees for information regarding Cheniere Partners’ guarantor subsidiaries.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2017 and 2016, accounts and other receivables consisted of the following (in millions):

		December 31,
		2017				2016
SPL trade receivable		$	185			$	88
Other accounts receivable		5				2
Total accounts and other receivables		$	190			$	90

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.

NOTE 5—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in millions):

		December 31,
		2017				2016
Natural gas		$	17			$	15
LNG		26				45
Materials and other		51				36
Total inventory		$	94			$	96

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in millions):

		December 31,
		2017				2016
LNG terminal costs
LNG terminal		$	11,956			$	7,250
LNG terminal construction-in-process		3,289				6,680
Accumulated depreciation		(732		)		(424		)
Total LNG terminal costs, net		14,513				13,506
Fixed assets
Fixed assets		14				12
Accumulated depreciation		(9		)		(6		)
Total fixed assets, net		5				6
Property, plant and equipment, net		$	14,518			$	13,512

Depreciation expense was and $311 million, $129 million and $47 million in the years ended December 31, 2017, 2016 and 2015, respectively.

We realized offsets to LNG terminal costs of $301 million and $201 million in the years ended December 31, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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
Marine berth, electrical, facility and roads		35
Regasification processing equipment		30
Sendout pumps		20
Liquefaction processing equipment		6-50
Other		15-30

Fixed Assets

Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”). SPL had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of its credit facilities (“Interest Rate Derivatives”), which were settled in March 2017.

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2017 and 2016, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	December 31, 2017																December 31, 2016
	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
Interest Rate Derivatives liability	$	—			$	—			$	—			$	—			$	—			$	(6	)		$	—			$	(6	)
Liquefaction Supply Derivatives asset (liability)	2				10				43				55				(4		)		(2		)		79				73

We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

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We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data.

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2017:

		Net Fair Value Asset (in millions)		Valuation Approach		Significant Unobservable Input		Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives		$43		Market approach incorporating present value techniques		Basis Spread		$(0.503) - $0.432

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
Balance, beginning of period		$	79			$	32			$	—
Realized and mark-to-market gains (losses):
Included in cost of sales (1)		(37		)		48				32
Purchases and settlements:
Purchases		14				1				—
Settlements (1)		(12		)		(2		)		—
Transfers out of Level 3		(1		)		—				—
Balance, end of period		$	43			$	79			$	32
Change in unrealized gains relating to instruments still held at end of period		$	(37	)		$	49			$	32

    

(1)	Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

 

Interest Rate Derivatives

SPL had entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “2015 SPL Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities. In March 2017, SPL settled the Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 10—Debt.

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The following table shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets (in millions):

				Fair Value Measurements as of
		Consolidated Balance Sheet Location		December 31, 2017				December 31, 2016
Interest Rate Derivatives		Derivative liabilities		$	—			$	(4	)
Interest Rate Derivatives		Non-current derivative liabilities		—				(2		)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
Interest Rate Derivatives loss		$	(2	)		$	(6	)		$	(42	)

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges, if applicable, to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the noncurrent physical natural gas supply contracts range from approximately one to seven years, most of which commence upon the satisfaction of certain conditions precedent, if not already met, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

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.

SPL had secured up to approximately 2,214 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2017 and 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,520 TBtu and 1,117 TBtu as of December 31, 2017 and 2016, respectively.

The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):

		Fair Value Measurements as of (1)
Consolidated Balance Sheet Location		December 31, 2017				December 31, 2016
Other current assets		$	41			$	13
Non-current derivative assets		17				67
Total derivative assets		58				80
Derivative liabilities		—				(7		)
Non-current derivative liabilities		(3		)		—
Total derivative liabilities		(3		)		(7		)
Derivative asset, net		$	55			$	73

(1)	Does not include a collateral call of $1 million and a collateral deposit of $6 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively.

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The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):

			Year Ended December 31,
	Consolidated Statement of Operations Location (1)		2017				2016				2015
Liquefaction Supply Derivatives loss (gain) (2)	Cost (cost recovery) of sales		$	24			$	(42	)		$	(33	)

(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.

Consolidated Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):

		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, 2017
Liquefaction Supply Derivatives		$	64			$	(6	)		$	58
Liquefaction Supply Derivatives		(3		)		—				(3		)
As of December 31, 2016
Interest Rate Derivatives		$	(6	)		$	—			$	(6	)
Liquefaction Supply Derivatives		82				(2		)		80
Liquefaction Supply Derivatives		(11		)		4				(7		)

NOTE 8—OTHER NON-CURRENT ASSETS

As of December 31, 2017 and 2016, other non-current assets, net consisted of the following (in millions):

		December 31,
		2017				2016
Advances made under EPC and non-EPC contracts		$	26			$	23
Advances made to municipalities for water system enhancements		93				95
Advances and other asset conveyances to third parties to support LNG terminals		30				31
Tax-related payments and receivables		25				28
Information technology service assets		22				26
Other		1				11
Total other non-current assets, net		$	197			$	214

NOTE 9—ACCRUED LIABILITIES

 

As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in millions):

		December 31,
		2017				2016
Interest costs and related debt fees		$	229			$	204
Sabine Pass LNG terminal costs		384				211
Total accrued liabilities		$	613			$	415

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NOTE 10—DEBT

 

As of December 31, 2017 and 2016, our debt consisted of the following (in millions):

		December 31,
		2017				2016
Long-term debt:
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7		$	2,006			$	2,007
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)		1,000				1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $6		1,505				1,506
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)		2,000				2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)		2,000				2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)		1,500				1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)		1,500				1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero		1,349				—
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)		800				—
2015 SPL Credit Facilities		—				314
Unamortized debt issuance costs		(183		)		(178		)
Total long-term debt, net		13,477				11,649
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)		—				224
Total debt, net		$	13,477			$	11,873

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, 2017 (in millions): 

Years Ending December 31,		Principal Payments
2018		$	—
2019		—
2020		—
2021		2,000
2022		1,000
Thereafter		10,650
Total		$	13,650

SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.

  

In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the year ended December 31, 2017.

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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, 2027 SPL Senior Notes and 2028 SPL Senior Notes (collectively with the 2037 SPL Senior Notes, the “SPL Senior Notes”) are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain 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 or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. 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 test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. As of December 31, 2017, SPL was in compliance with all covenants related to the SPL Senior Notes. Interest on the SPL Senior Notes is payable semi-annually in arrears.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 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 (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, 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, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the 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.

SPL Working Capital Facility

Below is a summary of the SPL Working Capital Facility as of December 31, 2017 (in millions):

		SPL Working Capital Facility
Original facility size		$	1,200
Less:
Outstanding balance		—
Letters of credit issued		730
Available commitment		$	470
Interest rate		LIBOR plus 1.75% or base rate plus 0.75%
Maturity date		December 31, 2020, with various terms for underlying loans

In September 2015, 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

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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, 2017, no LC Draws 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. As of December 31, 2017, SPL was in compliance with all covenants related to the SPL Working Capital Facility. 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.

Interest Expense

Total interest expense consisted of the following (in millions):

		Year Ended December 31,
		2017				2016				2015
Total interest cost		$	788			$	796			$	689
Capitalized interest		(285		)		(463		)		(492		)
Total interest expense, net		$	503			$	333			$	197

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):

		December 31, 2017								December 31, 2016
		Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
Senior notes, net of premium or discount (1)		$	12,860			$	13,955			$	11,513			$	12,309
2037 SPL Senior Notes (2)		800				871				—				—
Credit facilities (3)		—				—				538				538

(1)	Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes and 2028 SPL Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

(2)	The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

(3)	Includes 2015 SPL Credit Facilities and SPL Working Capital Facility. 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.

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NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
LNG revenues		$	2,615			$	535			$	—
LNG revenues—affiliate		1,389				294				—
Regasification revenues		260				259				259
Regasification revenues—affiliate		64				193				254
Other revenues		20				4				7
Other revenues—affiliate		—				4				3
Total revenues from customers		4,348				1,289				523
Revenues from derivative instruments (1)		20				4				—
Total revenues		$	4,368			$	1,293			$	523

(1)	Relates to the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a Free on Board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the optional exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the optional exception, variable consideration related to the sale of LNG is also not included in the transaction price.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

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Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6.

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During the year ended December 31, 2017, SPL recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

Regasification Revenues—Affiliate

SPLNG has a terminal use rights assignment and agreement (the “TURA”) with SPL and Cheniere Investments pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay a portion of the fees required by the TUA to SPLNG, of approximately $250 million per year (the “TUA Fees”). Cheniere Investments’ right to use capacity at SPLNG’s LNG terminal and its respective percentage of TUA fees payable was reduced from 100% to zero as each of Trains 1 through 4 of SPL’s Liquefaction Project reached commercial operations. Train 4 reached commercial operations in October 2017 at which time Cheniere Investments’ right to capacity and obligation to pay future fees were substantially eliminated. SPL’s portion of the TUA Fees and SPLNG’s related revenues are eliminated in consolidation.

The following table shows the percentage of all TUA Fees receivable from Cheniere Investments and SPL in accordance with the TURA:

Period		Percentage of TUA Fees Receivable from Cheniere Investments		Percentage of TUA Fees Receivable from SPL
Prior to May 2016 (substantial completion of Train 1)		100%		0%
May 2016 - September 2016 (substantial completion of Train 2)		75%		25%
September 2016 - March 2017 (substantial completion of Train 3)		50%		50%
March 2017 - October 2017 (substantial completion of Train 4)		25%		75%
Thereafter		0%		100%

Cheniere Investments’ obligation to pay their percentage share of the approximately $250 million annual payments to us regardless of their use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. SPLNG provides access to an integrated regasification service to Cheniere Investments. Because SPLNG reduces Cheniere Investment’s access to the terminal as each Train reaches substantial completion, we have concluded that each of the periods in the table above must be accounted for as separate performance obligations. We have allocated the transaction price to each performance obligation using estimated stand-alone selling prices corresponding with the customer’s access to capacity in that period. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer. We have concluded that the variable consideration within the contract meets the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

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Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in millions):

		Year Ended December 31,
		2017				2016				2015
Deferred revenues, beginning of period		$	78			$	36			$	40
Cash received but not yet recognized		110				71				25
Revenue recognized from prior period deferral		(76		)		(29		)		(29		)
Deferred revenues, end of period		$	112			$	78			$	36

The following table reflects the changes in our contract liabilities to affiliate, which we classify as “Deferred revenue—affiliate” on our Consolidated Balance Sheets (in millions):

		Year Ended December 31,
		2017				2016				2015
Deferred revenues—affiliate, beginning of period		$	11			$	22			$	22
Cash received but not yet recognized		—				10				21
Revenue recognized from prior period deferral		(10		)		(21		)		(21		)
Deferred revenues—affiliate, end of period		$	1			$	11			$	22

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2017 and 2016 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. Changes in deferred revenue during the years ended December 31, 2017, 2016 and 2015 are also attributable to differences between the timing of revenue recognition and the receipt of advance payments under our TUAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:

		Unsatisfied Transaction Price (in billions)				Weighted Average Recognition Timing (years) (1)
LNG revenues		$	55.7			10.2
Regasification revenues		2.9				5.7
Total revenues		$	58.6

    

(1)	The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We have elected the following optional exemptions which omit certain potential future sources of revenue from the table above:

(1)	We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During the year ended December 31, 2017,

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approximately 58% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 2% of our Regasification revenues were related to variable consideration received from customers.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 12—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, 2017, 2016 and 2015 (in millions):

		Year Ended December 31,
		2017				2016				2015
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA		$	1,389			$	294			$	—
Regasification revenues—affiliate
TUA fees from Cheniere Investments		64				193				254
Other revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG		—				1				1
Terminal Marine Services Agreement		—				3				2
Total other revenues—affiliate		—				4				3
Cost of sales—affiliate
Fees under the Pre-commercial LNG Marketing Agreement		—				2				—
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG		—				1				1
Natural Gas Transportation Agreement		73				40				—
Services Agreements		84				45				23
Total operating and maintenance expense—affiliate		157				86				24
Development expense—affiliate
Services Agreements		—				—				1
General and administrative expense—affiliate
Services Agreements		67				77				102

LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0 Bcf/d of regasification capacity and other liquefaction support services 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 pay the TUA Fees until at least May 2036.

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.

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Pursuant to the TURA, Cheniere Investments had the right to use SPL’s reserved capacity under SPL’s TUA with SPLNG and had the obligation to pay the TUA Fees required by the TUA to SPLNG. See Note 11—Revenues from Contracts with Customers for information regarding these agreements.

Cheniere Marketing SPA

Cheniere Marketing has 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

SPL has 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

Under the Cheniere Marketing Master SPA, SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

SPL has 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.

Natural Gas Transportation Agreements

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, SPL has a transportation precedent agreement and a negotiated rate agreement to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. These agreements have a primary term through 2036 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, SPL has the right to elect to extend the term of the agreements for up to two consecutive ten-year terms. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised SPL that it has agreed otherwise.

Services Agreements

As of both December 31, 2017 and 2016, we had $32 million of advances to affiliates under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

SPLNG O&M Agreement

SPLNG has 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 pays 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 the parties at the beginning of each operating year. In addition, SPLNG is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses.

 

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SPLNG MSA

SPLNG has 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 pays a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

SPL O&M Agreement

SPL has 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 each Train of 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 each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, 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 Train 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 the Train.

SPL MSA

SPL has 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. Prior to the substantial completion of each Train of the Liquefaction Project, 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.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including SPL and SPLNG, 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.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

 

SPLNG has executed Cooperative Endeavor Agreements (“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 $25 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 both December 31, 2017 and 2016, we had $25 million of both other non-current assets resulting from SPLNG’s ad valorem tax payments and other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.

 

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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, LLC (“Cheniere Marketing US”). Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing US at a sales price equal to the actual purchase price paid by Cheniere Marketing US to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing US with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an 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

SPLNG and Cheniere Marketing US have an LNG Terminal Export Agreement that provides Cheniere Marketing US the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the years ended December 31, 2017, 2016 and 2015.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which 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.

SPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which 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.

NOTE 13—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $12 million, $11 million and $10 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 millions): 

Years Ending December 31,	Operating Leases (1)
2018	$	2
2019	2
2020	2
2021	2
2022	2
Thereafter	38
Total	$	48

(1)	Includes certain lease option renewals that are reasonably assured.

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NOTE 14—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, 2017, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

 

Obligations under EPC Contract

SPL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 5 of the Liquefaction Project. The EPC contract for Train 5 provides that SPL will pay Bechtel a contract price of $3.1 billion, subject to adjustment by change order.  SPL has the right to terminate the 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 million depending on the termination date.

Obligations under SPAs

SPL has third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project.

Obligations under LNG TUAs

 

SPLNG has third-party TUAs with Total 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 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 seven 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, 2017, SPL has secured up to approximately 2,214 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent were met.

Additionally, SPL has transportation and storage service agreements for the Liquefaction Project. The initial terms of the transportation agreements range from one to 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The terms of the SPL storage service agreements range from three to ten years.

As of December 31, 2017, SPL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions): 

Years Ending December 31,	Payments Due (1)
2018	$	2,274
2019	1,527
2020	1,397
2021	981
2022	336
Thereafter	1,169
Total	$	7,684

(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, 2017.

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Obligations under LNG TUA

SPL has a partial TUA assignment agreement with Total, another TUA customer, whereby upon substantial completion of Train 3 in March 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.

Services Agreements

 

We have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements.

Restricted Net Assets

 

At December 31, 2017, our restricted net assets of consolidated subsidiaries were approximately $1.5 billion.

Other Commitments

 

State Tax Sharing Agreements

 

SPLNG and SPL have state tax sharing agreements with Cheniere. See Note 12—Related Party Transactions for information regarding such agreements.

Other Agreements

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. 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, 2017, 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.

NOTE 15—CUSTOMER CONCENTRATION

  

The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:

		Percentage of Total Third-Party Revenues						Percentage of Accounts Receivable from Third Parties
		Year Ended December 31,						December 31,
		2017		2016		2015		2017		2016
Customer A		39%		52%		—%		39%		47%
Customer B		27%		*		—%		32%		50%
Customer C		23%		—%		—%		26%		—%

* Less than 10%

During the year ended December 31, 2017, revenues from external customers that were derived from domestic customers was $1.4 billion and from customers outside of the United States was $1.5 billion, of which $787 million and $666 million were

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from customers in Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $677 million and from customers outside of the United States was $125 million. During the year ended December 31, 2015, all revenues from external customers were derived from domestic customers. We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of cash flow information (in millions):

		Year Ended December 31,
		2017				2016				2015
Cash paid during the period for interest, net of amounts capitalized		$	438			$	229			$	123
Non-cash contributions from member for certain operating activities		2				9				7
Non-cash distributions to affiliates for conveyance of assets		—				—				10
Non-cash conveyance of assets to non-affiliate		—				—				13

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $270 million, $264 million and $230 million, as of December 31, 2017, 2016 and 2015, respectively.

NOTE 17—GUARANTEES

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities, which included an approximately $2.1 billion SPLNG tranche term loan that was used to satisfy SPLNG’s outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with us subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2017, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us but not including our non-guarantor subsidiary’s assets and rights, and our real property (except for certain excluded properties). As of December 31, 2017, the collateralized net assets of the CQP Guarantors was $2.1 billion.

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NOTE 18—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:

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 will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 11—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto		This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and 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 on 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. We have not yet determined whether we will elect any other practical expedients upon transition.
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.

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Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:

Standard		Description		Date of Adoption		Effect on our Consolidated Financial Statements or Other Significant Matters
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 did not have a material impact on our Consolidated Financial Statements or related disclosures.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SABINE PASS LNG-LP, LLC

CONDENSED BALANCE SHEETS

(in millions) 

		December 31,
		2017				2016
ASSETS
Investment in affiliates		$	1,522			$	2,083
Total assets		$	1,522			$	2,083
LIABILITIES AND MEMBER’S EQUITY
Liabilities		$	—			$	—
Member’s equity		1,522				2,083
Total liabilities and member’s equity		$	1,522			$	2,083

The accompanying notes are an integral part of these condensed financial statements.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SABINE PASS LNG-LP, LLC

CONDENSED STATEMENTS OF OPERATIONS

(in millions) 

		Year Ended December 31,
		2017				2016				2015
Revenues		$	—			$	—			$	—
Equity income (loss) of affiliates		679				53				(24		)
Net income (loss)		$	679			$	53			$	(24	)

The accompanying notes are an integral part of these condensed financial statements.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SABINE PASS LNG-LP, LLC

CONDENSED STATEMENTS OF CASH FLOWS

(in millions) 

	Year Ended December 31,
	2017				2016				2015
Cash provided by (used in) operating activities	$	428			$	247			$	242
Cash flows from investing activities
Investments in subsidiaries	(108		)		(2,002		)		(67		)
Distributions received from affiliates, net	921				64				95
Net cash provided by (used in) investing activities	813				(1,938		)		28
Cash flows from financing activities
Capital contributions	109				2,002				67
Distributions	(1,350		)		(311		)		(337		)
Net cash provided by (used in) financing activities	(1,241		)		1,691				(270		)
Net increase (decrease) in cash and cash equivalents	—				—				—
Cash and cash equivalents—beginning of period	—				—				—
Cash and cash equivalents—end of period	$	—			$	—			$	—

The accompanying notes are an integral part of these condensed financial statements.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SABINE PASS LNG-LP, LLC

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 Sabine Pass LP.

 

A substantial amount of Cheniere Investments’ operating, investing and financing activities are conducted by its affiliates. In the Condensed Financial Statements, Sabine Pass LP’s 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.

We use the cumulative earnings approach for classifying distributions received from our equity method investees on the Condensed Statements of Cash Flows. The cumulative earnings approach dictates that distributions received by an investor are viewed as a return on investment and classified as cash flows from operating activities unless the cumulative distributions received exceed the cumulative equity in earnings recognized by the investor. Distributions received in excess of cumulative earnings are viewed as a return of investment and classified as cash flows from investing activities.

The Condensed Financial Statements should be read in conjunction with Sabine Pass LP’s Consolidated Financial Statements.

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Sabine Pass LNG, L.P.

Consolidated Financial Statements

As of December 31, 2017 and 2016

and for the years ended December 31, 2017, 2016 and 2015

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SABINE PASS LNG, L.P. AND SUBSIDIARY

DEFINITIONS

As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

Bcf/d		billion cubic feet per day
Bcfe		billion cubic feet equivalent
GAAP		generally accepted accounting principles in the United States
LNG		liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
Train		an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA		terminal use agreement

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SABINE PASS LNG, L.P. AND SUBSIDIARY

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2017 and the references to these entities used in these Consolidated Financial Statements:

Unless the context requires otherwise, references to “SPLNG,” “the Partnership,” “we,” “us” and “our” refer to Sabine Pass LNG, L.P. and its wholly owned subsidiary, Tug Services.

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Independent Auditors’ Report

To the Managers of Sabine Pass LNG-GP, LLC and

Partners of Sabine Pass LNG, L.P.:

We have audited the accompanying consolidated financial statements of Sabine Pass LNG, L.P., and its subsidiary (the Partnership), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, and the related consolidated statements of income, partners’ equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sabine Pass LNG, L.P and its subsidiary as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the consolidated financial statements, in 2017, 2016 and 2015, the Partnership adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

/s/ KPMG LLP

Houston, Texas

June 15, 2018

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SABINE PASS LNG, L.P. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2017				2016
ASSETS
Current assets
Cash and cash equivalents	$	—			$	—
Restricted cash	11,389				739
Accounts and other receivables	924				396
Accounts receivable—affiliate	3,069				1,353
Advances to affiliate	6,676				6,018
Inventory	8,974				7,259
Other current assets	2,295				2,973
Total current assets	33,327				18,738
Property, plant and equipment, net	1,603,054				1,641,133
Other non-current assets, net	27,630				29,081
Total assets	$	1,664,011			$	1,688,952
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	3,639			$	3,675
Accrued liabilities	6,996				7,247
Due to affiliates	8,377				2,322
Deferred revenue	26,817				26,709
Deferred revenue—affiliate	21,974				21,884
Total current liabilities	67,803				61,837
Non-current deferred revenue	1,500				5,500
Non-current deferred revenue—affiliate	24,533				24,533
Other non-current liabilities	9,918				166
Other non-current liabilities—affiliate	66				147
Commitments and contingencies (see Note 9)
Partners’ equity	1,560,191				1,596,769
Total liabilities and partners’ equity	$	1,664,011			$	1,688,952

The accompanying notes are an integral part of these consolidated financial statements.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME

(in thousands)

	Year Ended December 31,
	2017				2016				2015
Revenues
Regasification revenues	$	260,201			$	259,314			$	258,833
Regasification revenues—affiliate	254,891				254,013				253,538
Other revenues	19,351				3,716				6,804
Other revenues—affiliate	24,676				17,688				3,864
Total revenues	559,119				534,731				523,039
Operating costs and expenses
Operating and maintenance expense	37,458				41,436				35,004
Operating and maintenance expense—affiliate	18,036				18,029				22,792
Development expense	356				—				—
Development expense—affiliate	1				—				—
General and administrative expense	318				924				3,276
General and administrative expense—affiliate	9,005				9,056				14,182
Depreciation and amortization expense	54,843				53,201				44,985
Loss (gain) on disposal of assets	1,659				(8		)		(22		)
Total operating costs and expenses	121,676				122,638				120,217
Income from operations	437,443				412,093				402,822
Other income (expense)
Interest expense	(9,113		)		(147,635		)		(161,134		)
Loss on early extinguishment of debt	—				(18,188		)		—
Other income	27				526				89
Total other expense	(9,086		)		(165,297		)		(161,045		)
Net income	$	428,357			$	246,796			$	241,777

The accompanying notes are an integral part of these consolidated financial statements.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY (DEFICIT)

(in thousands)

		General Partner Sabine Pass LNG-GP, LLC				Limited Partner Sabine Pass LNG-LP, LLC				Total Partners’ Equity (Deficit)
Balance at December 31, 2014		$	—			$	(646,471	)		$	(646,471	)
Net income		—				241,777				241,777
Contributions		—				140,130				140,130
Distributions		—				(337,320		)		(337,320		)
Balance at December 31, 2015		—				(601,884		)		(601,884		)
Net income		—				246,796				246,796
Contributions		—				2,262,510				2,262,510
Distributions		—				(310,653		)		(310,653		)
Balance at December 31, 2016		—				1,596,769				1,596,769
Net income		—				428,357				428,357
Contributions		—				102,618				102,618
Distributions		—				(567,553		)		(567,553		)
Balance at December 31, 2017		$	—			$	1,560,191			$	1,560,191

The accompanying notes are an integral part of these consolidated financial statements.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2017				2016				2015
Cash flows from operating activities
Net income	$	428,357			$	246,796			$	241,777
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	54,843				53,201				44,985
Non-cash interest expense	9,113				—				—
Amortization of debt issuance costs and discount	—				8,183				8,922
Loss on early extinguishment of debt	—				18,188				—
Other	1,659				10				887
Other—affiliate	2,183				8,714				7,216
Changes in operating assets and liabilities:
Accounts receivable—affiliate	(1,716		)		(738		)		307
Advances to affiliate	(658		)		1,136				(5,286		)
Inventory	1,423				2,387				(5,972		)
Accounts payable and accrued liabilities	(482		)		(10,835		)		2,360
Due to affiliates	5,921				(6,570		)		4,671
Deferred revenue	(3,893		)		(3,960		)		(3,986		)
Other, net	1,284				3,714				(6,005		)
Other—affiliate	8				539				2,617
Net cash provided by operating activities	498,042				320,765				292,493
Cash flows from investing activities
Property, plant and equipment, net	(20,274		)		(5,386		)		(5,391		)
Other	—				(4,537		)		—
Net cash used in investing activities	(20,274		)		(9,923		)		(5,391		)
Cash flows from financing activities
Repayments of debt	—				(2,085,500		)		—
Debt extinguishment costs	—				(13,651		)		—
Capital contributions	100,435				2,000,994				52,400
Distributions	(567,553		)		(310,653		)		(337,320		)
Net cash used in financing activities	(467,118		)		(408,810		)		(284,920		)
Net increase (decrease) in cash, cash equivalents and restricted cash	10,650				(97,968		)		2,182
Cash, cash equivalents and restricted cash—beginning of period	739				98,707				96,525
Cash, cash equivalents and restricted cash—end of period	$	11,389			$	739			$	98,707

Balances per Consolidated Balance Sheets:

	December 31,
	2017				2016
Cash and cash equivalents	$	—			$	—
Restricted cash	11,389				739
Total cash, cash equivalents and restricted cash	$	11,389			$	739

The accompanying notes are an integral part of these consolidated financial statements.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a Houston-based Delaware limited partnership formed by Cheniere to own, develop and operate an LNG receiving and regasification terminal in western Cameron Parish, Louisiana, less than four miles from the Gulf Coast on the Sabine-Neches Waterway (our “LNG terminal”). Our LNG terminal includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d.

NOTE 2—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 SPLNG and its wholly owned subsidiary. 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 did not have a material effect on our consolidated financial position, results of operations or cash flows.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto using the full retrospective method. We have elected to adopt the new accounting standard retrospectively for all periods presented.

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

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 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

 

The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value.

Revenue Recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. LNG regasification capacity payments are recognized as regasification revenues and liquefaction support services are recognized as regasification revenues—affiliate. We recognize tug services fees that are received by Tug Services, which were historically included in regasification revenues but are now included within other revenues on our Consolidated Statements of Income. We also recognize cargo loading fees from SPL for the loading of LNG vessels at our LNG terminal, which are included within other revenues—affiliate on our Consolidated Statements of Income. See Note 6—Revenues from Contracts with Customers for further discussion of revenues.

 

Cash and Cash Equivalents

We did not have any cash and cash equivalents as of December 31, 2017 and 2016, since our operations are funded through contributions from Cheniere Partners or contractually restricted as to usage or withdrawal.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Restricted Cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and has been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of both December 31, 2017 and 2016, the balance of restricted cash consisted of funds reserved for the payment of short-term operating expenses and capital expenditures.

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 not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

LNG inventory is recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We 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 loss (gain) on disposal of assets.

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We have recorded no impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 or 2015.

Concentration of Credit Risk

 

We have entered into two long-term TUAs with unaffiliated third parties for regasification capacity at our LNG terminal. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective TUAs.

Asset Retirement Obligations

 

We recognize asset retirement obligations (“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 our LNG terminal. Based on the real property lease agreements at our 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 our LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender our LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Income Taxes

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Income, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

At December 31, 2017, the tax basis of our assets and liabilities was $605 million less than the reported amounts of our assets and liabilities.

Business Segment

Our regasification operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of SPLNG in total when evaluating financial performance and for purposes of allocating resources. All of our revenues and long-lived assets are attributed to the United States.

NOTE 3—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in thousands):

		December 31,
		2017				2016
LNG		$	539			$	402
Materials and other		8,435				6,857
Total inventory		$	8,974			$	7,259

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in thousands): 

		December 31,
		2017				2016
LNG terminal costs
LNG terminal		$	1,993,215			$	1,980,019
LNG terminal construction-in-process		11,148				8,840
LNG site and related costs		120				128
Accumulated depreciation		(401,512		)		(347,987		)
Total LNG terminal costs, net		1,602,971				1,641,000
Fixed assets
Fixed assets		2,255				2,617
Accumulated depreciation		(2,172		)		(2,484		)
Total fixed assets, net		83				133
Property, plant and equipment, net		$	1,603,054			$	1,641,133

Depreciation expense was $53.9 million, $52.3 million and $45.0 million in the years ended December 31, 2017, 2016 and 2015, respectively.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

LNG Terminal Costs

Our 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 our LNG terminal with similar estimated useful lives have a depreciable range between 15 and 50 years, as follows:

Components		Useful life (yrs)
LNG storage tanks		50
Marine berth, electrical, facility and roads		35
Regasification processing equipment		30
Sendout pumps		20
Other		15-30

Fixed Assets

Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 5—OTHER NON-CURRENT LIABILITIES

We, through Tug Services, entered into an agreement in 2009 which required the contingent payment of a portion of our future tug service revenues to third party counterparties over the life of the agreement in exchange for an initial cash payment of $6.0 million. We classified the cash received in 2009 as other non-current liabilities on our Consolidated Balance Sheets and impute interest expense on the non-current liability using the effective interest method. We had other non-current liabilities of $9.8 million as of December 31, 2017 resulting from this agreement. The effective interest rate is computed based on estimated payments of tug service revenues to third party counterparties over the life of the agreement, which concludes in January 2028. Changes in estimated payments to be paid to the counterparties to the agreement are reflected prospectively in interest expense on our Consolidated Statements of Income. The interest rate on the liability may vary during the term of the agreement depending primarily on the aggregate total revenue earned by Tug Services. Payments made to counterparties pursuant to the agreement reduce the other non-current liability balance.

NOTE 6—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in thousands):

		Year Ended December 31,
		2017				2016				2015
Regasification revenues		$	260,201			$	259,314			$	258,833
Regasification revenues—affiliate		254,891				254,013				253,538
Other revenues		19,351				3,716				6,804
Other revenues—affiliate		24,676				17,688				3,864
Total revenues		$	559,119			$	534,731			$	523,039

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to us aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, a wholly owned subsidiary of Cheniere Partners. See “Regasification revenues—affiliate” below for information on revenue from SPL.

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SABINE PASS LNG, L.P. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Because we are continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to our customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with us. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of additional Trains.

Upon substantial completion of Train 3, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with us. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to us will continue to be made by Total to us in accordance with its TUA and we continue to recognize the payments received from Total as third-party revenue.

Regasification Revenues—Affiliate

SPL obtained 2.0 Bcf/d of regasification capacity and other liquefaction support services as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with us. SPL is obligated to make monthly capacity payments to us aggregating approximately $250 million per year (the “TUA Fees”), continuing until May 2036. In addition, SPL is required to pay us $120,000 in cargo loading fees for each LNG vessel that they load at our LNG terminal.

We have a terminal use rights assignment and agreement (the “TURA”) with SPL and Cheniere Investments pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay a portion of the TUA Fees required by the TUA to us. Cheniere Investments’ right to use capacity at our LNG terminal and its respective percentage of TUA fees payable was reduced from 100% to zero as each of Trains 1 through 4 of SPL’s liquefaction project reached commercial operations. Train 4 reached commercial operations in October 2017 at which time Cheniere Investments’ right to capacity and obligation to pay future fees were substantially eliminated.

The following table shows the percentage of all TUA Fees receivable from Cheniere Investments and SPL in accordance with the TURA:

Period		Percentage of TUA Fees Receivable from Cheniere Investments		Percentage of TUA Fees Receivable from SPL
Prior to May 2016 (substantial completion of Train 1)		100%		0%
May 2016 - September 2016 (substantial completion of Train 2)		75%		25%
September 2016 - March 2017 (substantial completion of Train 3)		50%		50%
March 2017 - October 2017 (substantial completion of Train 4)		25%		75%
Thereafter		0%		100%

Cheniere Partners has guaranteed SPL’s obligations under the TUA and the obligations of Cheniere Investments under the TURA.

SPL’s obligation to pay their percentage share of the approximately $250 million annual payments to us regardless of their use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. Cargo loading fees are also considered variable consideration because their receipt depends upon SPL’s use of liquefaction support services. Because we provide recurring firm liquefaction support service throughout the course of the agreement, and because SPL immediately receives the benefit of such performance, we have concluded that we have a single performance obligation for which the related revenues shall be recognized over time. We have determined that an output method of recognition based on the quantity of firm liquefaction support services used best reflects the benefits of this service to the customer. Because we expect that SPL shall use the full amount of firm liquefaction support services on a periodic basis, this methodology results in the recognition of such fixed fees on a substantially straight-line basis. We have

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concluded that both the inflation element within the contract and cargo loading fees meet the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Cheniere Investments’ obligation to pay their percentage share of the approximately $250 million annual payments to us regardless of their use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. SPLNG provides access to an integrated regasification service to Cheniere Investments. Because SPLNG reduces Cheniere Investments’ access to the terminal as each Train reaches substantial completion, we have concluded that each of the periods in the table above must be accounted for as separate performance obligations. We have allocated the transaction price to each performance obligation using estimated stand-alone selling prices corresponding with the customer’s access to capacity in that period. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer. We have concluded that the variable consideration within the contract meets the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Other Revenues

Tug Services has entered into arrangements to provide tug related services to each vessel that docks at the Sabine Pass LNG terminal. These customers pay tug services fees of $125,000 for each vessel that docks at our LNG terminal, which is included in other revenues. Because we are continuously available to provide tug services on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to our customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer. Tug services fees are considered variable consideration because their receipt depends entirely upon the customer’s need to dock at the facility. We have concluded that the tug service fees meet the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in thousands):

		Year Ended December 31,
		2017				2016				2015
Deferred revenues, beginning of period		$	32,209			$	36,169			$	40,155
Cash received but not yet recognized		25,384				25,276				25,253
Revenue recognized from prior period deferral		(29,276		)		(29,236		)		(29,239		)
Deferred revenues, end of period		$	28,317			$	32,209			$	36,169

The following table reflects the changes in our contract liabilities to affiliate, which we classify as “Deferred revenue—affiliate” and “Non-current deferred revenue—affiliate” on our Consolidated Balance Sheets (in thousands):

		Year Ended December 31,
		2017				2016				2015
Deferred revenues—affiliate, beginning of period		$	46,417			$	43,925			$	41,465
Cash received but not yet recognized		21,258				23,620				23,591
Revenue recognized from prior period deferral		(21,168		)		(21,128		)		(21,131		)
Deferred revenues—affiliate, end of period		$	46,507			$	46,417			$	43,925

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. We recognize deferred revenue related to our TUAs because our customers are required to pay a month in advance of the associated service period. We have recorded non-current deferred revenue—affiliate representing a prepayment of SPL’s future obligations under the TUA.

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Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:

		Unsatisfied Transaction Price (in billions)				Weighted Average Recognition Timing (years) (1)
Regasification revenues		$	2.9			5.7
Regasification revenues—affiliate		4.6				9.2
Total revenues		$	7.5

    

(1)	The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the number of LNG vessels loaded and adjustments to the consumer price index. During the year ended December 31, 2017, approximately 2% of our Regasification revenues and approximately 2% of our Regasification revenues—affiliate were related to variable consideration received from customers.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

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NOTE 7—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015 (in thousands):

		Year Ended December 31,
		2017				2016				2015
Regasification revenues—affiliate
TUA fees from Cheniere Investments		$	64,408			$	193,497			$	253,538
TUA fees from SPL		190,483				60,516				—
Total regasification revenues—affiliate		254,891				254,013				253,538
Other revenues—affiliate
Sale of natural gas under TUA		—				1,349				—
Cargo loading fees under TUA		24,676				8,425				—
Contracts for Sale of Natural Gas and LNG		—				5,047				1,072
Other agreements		—				2,867				2,792
Total other revenues—affiliate		24,676				17,688				3,864
Operating and maintenance expense—affiliate
Contracts for Purchase of Natural Gas and LNG		—				607				1,121
Services Agreements		19,040				18,563				22,315
LNG Site Sublease Agreement		(960		)		(942		)		(712		)
Other agreements		(44		)		(199		)		68
Total operating and maintenance expense—affiliate		18,036				18,029				22,792
Development expense—affiliate
Services Agreements		1				—				—
General and administrative expense—affiliate
Services Agreements		9,005				9,056				14,182

Terminal Use Agreements

Pursuant to the TURA, Cheniere Investments had the right to use SPL’s reserved capacity under SPL’s TUA with us and had the obligation to pay the TUA Fees required by the TUA to us. See Note 6—Revenues from Contracts with Customers for information regarding these agreements.

Services Agreements

As of December 31, 2017 and 2016, we had $6.7 million and $6.0 million, respectively, of advances to affiliates under the services agreements described below. The non-reimbursable amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Operation and Maintenance Agreement

We have a long-term operation and maintenance agreement (the “O&M Agreement”) with Cheniere Investments pursuant to which we receive all necessary services required to operate and maintain our LNG receiving terminal. We pay a fixed monthly fee of $130,000 (indexed for inflation) under the 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 the parties at the beginning of each operating year. In addition, we are required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses.

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Management Services Agreement

 

We have a long-term management services agreement (the “MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of our LNG receiving terminal, excluding those matters provided for under the O&M Agreement. We pay a monthly fixed fee of $520,000 (indexed for inflation) under the MSA.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere 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.

Agreement to Fund Our Cooperative Endeavor Agreements

We have executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments 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 we fulfilled in the first quarter of 2016. In exchange for our advance payments of annual ad valorem taxes, Cameron Parish will grant us a dollar-for-dollar credit against future ad valorem taxes to be levied against our LNG terminal starting in 2019. Beginning in September 2007, we entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay us additional TUA revenues equal to any and all amounts payable by us to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, we 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.

These advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that we utilized to make the ad valorem tax payments were recorded as non-current deferred revenue—affiliate. As of both December 31, 2017 and 2016, we had $24.5 million of both other non-current assets resulting from ad valorem tax payments and non-current deferred revenue—affiliate resulting from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

We are able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing, LLC (“Cheniere Marketing US”). Under these agreements, we purchase natural gas or LNG from Cheniere Marketing US at a sales price equal to the actual purchase price paid by Cheniere Marketing US to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing US with respect to the receipt, purchase and delivery of the natural gas or LNG to our LNG terminal. We are also able to sell and purchase natural gas and LNG under an agreement with SPL.

Terminal Marine Services Agreement

In connection with our tug boat lease, Tug Services has an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at our LNG terminal. The agreement also provides that Tug Services shall contingently pay the wholly owned subsidiary of Cheniere a portion of its future revenues. Accordingly, Tug Services distributed $2.7 million to the wholly owned subsidiary of Cheniere during the year ended December 31, 2017. No amounts were distributed during the years ended December 31, 2016 and 2015.

LNG Site Sublease Agreement

We have agreements with SPL to sublease a portion of the LNG terminal site for its liquefaction project. The aggregate annual sublease payment is $0.9 million. The initial term of the sublease expires on December 31, 2034, with options to renew for multiple 10-year extensions with similar terms as the initial term. The annual sublease payment will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreement.

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LNG Terminal Export Agreement

We have an LNG Terminal Export Agreement with Cheniere Marketing US that provides Cheniere Marketing US with the ability to export LNG from our LNG terminal.  We did not record any revenues associated with this agreement during the years ended December 31, 2017, 2016 and 2015.

Cooperation Agreement

We have an agreement (the “Cooperation Agreement”) with SPL to allow SPL to retain and acquire certain rights to access the property and facilities that we own for the purpose of constructing, modifying and operating SPL’s facilities under construction. In consideration for the access we have given, SPL has agreed to transfer title to us of certain facilities, equipment and modifications, which we are obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. Under this agreement, SPL conveyed to us zero, $252.8 million and $80.5 million of assets during the years ended December 31, 2017, 2016 and 2015, respectively.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after January 1, 2008.

NOTE 8—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $9.3 million, $8.9 million and $8.9 million, respectively, related primarily to tug boat leases and land site leases, net of sublease income of $1.0 million, $0.9 million and $0.7 million, respectively. Our land site leases for the 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): 

Year ending December 31,	Operating Leases (1)
2018	$	1,536
2019	1,536
2020	1,536
2021	1,536
2022	1,536
Thereafter (2)	33,696
Total minimum payments required	$	41,376

(1)	Lease payments for our land leases do not take into account the $26.4 million sublease payments we will receive from SPL, as discussed in Note 7—Related Party Transactions.

(2)	Includes certain lease option renewals that are reasonably assured for our land site leases.

NOTE 9—COMMITMENTS AND CONTINGENCIES

LNG TUA Commitments

We have TUAs with Total, Chevron U.S.A. Inc. and SPL to provide berthing for LNG vessels and for the unloading and loading, storage and regasification of LNG at our LNG terminal. See Note 7—Related Party Transactions for information regarding the agreement with SPL.

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Services Agreements

We have certain services agreements with affiliates. See Note 7—Related Party Transactions for information regarding such agreements.

 

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere.  See Note 7—Related Party Transactions for information regarding this agreement.

Cooperative Endeavor Agreements

We have executed CEAs with various Cameron Parish, Louisiana taxing authorities. See Note 7—Related Party Transactions for information regarding such agreements.

Guarantees

Certain subsidiaries of Cheniere Partners, including us, have unconditionally guaranteed the debt obligations of Cheniere Partners. See Note 11—Guarantees for information regarding these guarantees.

Other Commitments

 

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 8—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, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our consolidated operating results, financial position or cash flows.

NOTE 10—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of cash flow information (in thousands):

		Year Ended December 31,
		2017				2016				2015
Cash paid during the period for interest		$	—			$	154,412			$	152,213
Non-cash contributions for conveyance of assets under Cooperation Agreement		—				252,802				80,515
Non-cash contributions from limited partner for certain operating activities		2,183				8,714				7,215

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $2.2 million, $1.8 million and $1.6 million as of December 31, 2017, 2016 and 2015, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 11—GUARANTEES

In February 2016, Cheniere Partners entered into a credit and guaranty agreement aggregating $2.8 billion (the “2016 CQP Credit Facilities”), which included an approximately $2.1 billion SPLNG tranche term loan that was used to satisfy our outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LP subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2017, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us, and our real property (except for certain excluded properties).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 12—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:

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 will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 6—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto		This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and 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 on 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. We have not yet determined whether we will elect any other practical expedients upon transition.
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.

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Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:

Standard		Description		Date of Adoption		Effect on our Consolidated Financial Statements or Other Significant Matters
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 did not have a material impact on our Consolidated Financial Statements or related disclosures.

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Cheniere Creole Trail Pipeline, L.P.

Financial Statements

As of December 31, 2017 and 2016

and for the years ended December 31, 2017, 2016 and 2015

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Independent Auditors’ Report

To the Managing Member of Cheniere Pipeline GP Interests, LLC:

We have audited the accompanying financial statements of Cheniere Creole Trail Pipeline, L.P. (the Partnership) which comprise the balance sheets as of December 31, 2017 and 2016, and the related statements of operations, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cheniere Creole Trail Pipeline, L.P. as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the financial statements, in 2017, 2016 and 2015, the Partnership adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

/s/ KPMG LLP

Houston, Texas

June 15, 2018

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CHENIERE CREOLE TRAIL PIPELINE, L.P.

BALANCE SHEETS

(in thousands)

		December 31,
		2017				2016
ASSETS
Current assets
Cash and cash equivalents		$	—			$	—
Restricted cash		48				96
Accounts receivable—affiliate		6,805				6,805
Advances to affiliate		3,937				5,787
Inventory		1,536				1,651
Other current assets		1,014				302
Total current assets		13,340				14,641
Property, plant and equipment, net		560,534				578,737
Other non-current assets, net		9,583				7,859
Total assets		$	583,457			$	601,237
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable		$	757			$	675
Accrued liabilities		219				299
Accrued liabilities—affiliate		3,991				1,888
Other current liabilities—affiliate		601				550
Total current liabilities		5,568				3,412
Other non-current liabilities—affiliate		—				390
Commitments and contingencies (see Note 8)
Partners’ equity		577,889				597,435
Total liabilities and partners’ equity		$	583,457			$	601,237

The accompanying notes are an integral part of these financial statements.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.

STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2017				2016				2015
Revenues—affiliate	$	81,762			$	56,363			$	1,117
Expenses
Operating and maintenance expense	7,709				4,774				2,689
Operating and maintenance expense—affiliate	12,088				11,137				4,996
General and administrative expense	1,589				1,103				3,399
General and administrative expense—affiliate	1,336				695				9,031
Depreciation and amortization expense	19,373				19,767				18,171
Total expenses	42,095				37,476				38,286
Income (loss) from operations	39,667				18,887				(37,169		)
Other income (expense)
Interest expense, net of capitalized interest	—				(581		)		(13,562		)
Loss on early extinguishment of debt	—				(1,457		)		—
Other income (expense)	(3		)		(2		)		16
Total other expense	(3		)		(2,040		)		(13,546		)
Net income (loss)	$	39,664			$	16,847			$	(50,715	)

The accompanying notes are an integral part of these financial statements.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.

STATEMENTS OF PARTNERS’ EQUITY

(in thousands)

		General Partner Interest				Limited Partner Interest				Total Partners’ Equity
Balance at December 31, 2014		$	—			$	227,269			$	227,269
Net loss		—				(50,715		)		(50,715		)
Contributions		—				33,265				33,265
Balance at December 31, 2015		—				209,819				209,819
Net income		—				16,847				16,847
Contributions		—				420,248				420,248
Distributions		—				(49,479		)		(49,479		)
Balance at December 31, 2016		—				597,435				597,435
Net income		—				39,664				39,664
Contributions		—				22,532				22,532
Distributions		—				(81,742		)		(81,742		)
Balance at December 31, 2017		$	—			$	577,889			$	577,889

The accompanying notes are an integral part of these financial statements.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.

STATEMENTS OF CASH FLOWS

(in thousands)

		Year Ended December 31,
		2017				2016				2015
Cash flows from operating activities
Net income (loss)		$	39,664			$	16,847			$	(50,715	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense		19,373				19,767				18,171
Loss on early extinguishment of debt		—				1,457				—
Amortization of debt issuance costs and discount		—				192				1,034
Changes in operating assets and liabilities:
Accounts receivable—affiliate		—				(6,648		)		(188		)
Inventory		116				(372		)		(554		)
Accounts payable and accrued liabilities		(201		)		(1,379		)		(409		)
Accrued liabilities—affiliate		2,107				(2,680		)		3,906
Advances to affiliate		1,851				(1,417		)		(2,885		)
Other		(2,809		)		(1,049		)		144
Other—affiliate		(339		)		442				180
Net cash provided by (used in) operating activities		59,762				25,160				(31,316		)
Cash flows from investing activities
Property, plant and equipment, net		(600		)		(2,047		)		(18,621		)
Other		—				(1,654		)		(555		)
Net cash used in investing activities		(600		)		(3,701		)		(19,176		)
Cash flows from financing activities
Repayments of debt		—				(400,000		)		—
Debt duration fees		—				—				(1,000		)
Capital contributions		22,532				420,248				23,135
Distributions		(81,742		)		(49,479		)		—
Other		—				(13		)		—
Net cash provided by (used in) financing activities		(59,210		)		(29,244		)		22,135
Net decrease in cash, cash equivalents and restricted cash		(48		)		(7,785		)		(28,357		)
Cash, cash equivalents and restricted cash—beginning of period		96				7,881				36,238
Cash, cash equivalents and restricted cash—end of period		$	48			$	96			$	7,881

Balances per Balance Sheets:

		December 31
		2017				2016
Cash and cash equivalents		$	—			$	—
Restricted cash		48				96
Total cash, cash equivalents and restricted cash		$	48			$	96

The accompanying notes are an integral part of these financial statements.

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CHENIERE CREOLE TRAIL PIPELINE, L.P. 

NOTES TO FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Cheniere Creole Trail Pipeline, L.P. (“CTPL”), a Delaware limited partnership, is a Houston based partnership formed with one general partner, Cheniere Pipeline GP Interests, LLC, and one limited partner, Cheniere Energy Investments, LLC (“Cheniere Investments”), both of which are wholly owned subsidiaries of Cheniere Energy Partners, L.P. (“Cheniere Partners”). Cheniere Partners is a publicly-traded Delaware limited partnership formed by Cheniere Energy, Inc. (“Cheniere”). Unless the context requires otherwise, references to “we,” “us” and “our” refer to CTPL.

We were formed to own and operate a 94-mile pipeline (the “Creole Trail Pipeline”) interconnecting the Sabine Pass liquefied natural gas (“LNG”) terminal with a number of large interstate pipelines. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC (“SPL”). Cheniere Partners plans to construct up to six industrial trains comprised of refrigerant compressor loops used to cool natural gas into LNG (“Trains”), which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 million tonnes per annum (“mtpa”) and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. Cheniere Partners also owns and operates regasification facilities at the Sabine Pass LNG terminal through its wholly owned subsidiary, Sabine Pass LNG, L.P. (“SPLNG”), that include pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 billion cubic feet equivalent (“Bcfe”), two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 billion cubic feet per day (“Bcf/d”).

SPL has entered into transportation precedent and other agreements to secure firm pipeline capacity with us, which supplement enabling agreements and long-term natural gas supply contracts SPL has executed with third parties to secure natural gas feedstock for the Liquefaction Project.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

Our Financial Statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”).

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto using the full retrospective method. We have elected to adopt the new accounting standard retrospectively for all periods presented.

We have evaluated subsequent events through June 15, 2018, the date the Financial Statements were available to be issued.

Use of Estimates

The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, 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

The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Revenue Recognition

We transport natural gas for shippers under a tariff regulated by the Federal Energy Regulatory Commission (“FERC”).  The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system.  Our revenues are derived from agreements for the receipt and delivery of natural gas at points along the pipeline system as specified in each shipper’s individual transportation contract.  See Note 5—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents

We did not have any cash and cash equivalents as of December 31, 2017 and 2016, since our operations are funded through contributions from Cheniere Partners or contractually restricted as to usage or withdrawal.

Restricted Cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. As of both December 31, 2017 and 2016, the balance of restricted cash consisted of funds reserved for the payment of short-term operating expenses.

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 not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

Inventory is recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. Inventory cost is determined using the average cost method. We did not record any expense related to inventory write downs during the years ended December 31, 2017, 2016 and 2015.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We 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 did not record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015.

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

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 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.

Concentration of Credit Risk

 

SPL has entered into transportation precedent and other agreements to secure firm pipeline capacity with us, which is our only customer. We are dependent SPL’s creditworthiness and its willingness to perform under its agreements with us.

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

We have not recorded an ARO associated with retirement of 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 a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

At December 31, 2017, the tax basis of our assets and liabilities was $114 million less than the reported amounts of our assets and liabilities.

Business Segment

Our pipeline operations represent a single reportable segment. Our chief operating decision maker reviews the financial results of CTPL in total when evaluating financial performance and for purposes of allocating resources. All of our revenues and long-lived assets are attributed to the United States.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment, net consists of natural gas pipeline costs and fixed assets, as follows (in thousands):

		December 31,
		2017				2016
Natural gas pipeline costs
Natural gas pipeline		$	706,980			$	705,847
Natural gas pipeline construction-in-progress		86				653
Accumulated depreciation		(147,206		)		(129,045		)
Total natural gas pipeline costs, net		559,860				577,455
Fixed assets
Fixed assets		7,290				7,138
Accumulated depreciation		(6,616		)		(5,856		)
Total fixed assets, net		674				1,282
Property, plant and equipment, net		$	560,534			$	578,737

Depreciation expense during the years ended December 31, 2017, 2016 and 2015 was $19.0 million, $19.4 million and $17.6 million, respectively.

Our natural gas pipeline cost is depreciated using the straight-line depreciation method with an estimated useful life of 40 years. Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 4—ACCRUED LIABILITIES

 

As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in thousands):

		December 31,
		2017				2016
Pipeline costs		$	179			$	64
Other		40				235
Total accrued liabilities		$	219			$	299

NOTE 5—REVENUES FROM CONTRACTS WITH CUSTOMERS

SPL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of adequate natural gas feedstock to the Sabine Pass LNG terminal. These agreements have a primary term through September 2036, with the right for SPL to extend the term of the agreements for up to two consecutive ten-year terms. Thereafter, the agreements continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. SPL has continuous access to its firm transportation capacity during the contract term but has no ability to defer unused capacity to future periods. SPL pays fixed fees of approximately $82 million per year to reserve the right to transport natural gas up to maximum contractually specified levels, regardless of the quantities that SPL actually transports.

Because we are continuously available to provide transportation service on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to SPL on a continuous basis over time. Because our rights to consideration corresponds directly with the value of the incremental service performed, we have elected to recognize revenue when we have the right to invoice SPL for services performed to date, which results in a substantially straight-line recognition pattern over the term of the contract.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Transaction Price Allocated to Future Performance Obligations

Because our sales contract with SPL has a long-term duration, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:

		Unsatisfied Transaction Price (in billions)				Weighted Average Recognition Timing (years) (1)
Revenues—affiliate		$	1.5			9.4

    

(1)	The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We omit from the table above all variable consideration expected to be recognized through our use of the right to invoice election.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 6—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Operations for the years ended December 31, 2017, 2016 and 2015 (in thousands):

	Year Ended December 31,
	2017				2016				2015
Revenues—affiliate
Transportation Agreements	$	81,660			$	56,349			$	1,117
Other agreements	102				14				—
Total revenues—affiliate	81,762				56,363				1,117
Operating and maintenance expense—affiliate
Services Agreements	9,789				10,533				5,093
Operational Balancing Agreements	2,299				604				(82		)
Other agreements	—				—				(15		)
Total operating and maintenance expense—affiliate	12,088				11,137				4,996
General and administrative expense—affiliate
Services Agreements	1,336				695				9,031

We had $3.9 million and $5.8 million of advances to affiliates, $4.0 million and $1.9 million of accrued liabilities—affiliate and zero and $0.4 million of other non-current liabilities—affiliate as of December 31, 2017 and 2016, respectively, under the services agreements described below.

Services Agreements

Operation and Maintenance Agreement

We have a long-term operation and maintenance agreement (the “O&M Agreement”) with Cheniere Investments pursuant to which we receive all necessary services required to operate and maintain the Creole Trail Pipeline. We are required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses. Cheniere Investments meets its obligations under the O&M Agreement with resources provided by a wholly owned subsidiary of Cheniere pursuant to a secondment agreement. All payments received by Cheniere Investments under the O&M Agreement are required to be remitted to such subsidiary.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere 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.

Operational Balancing Agreements

We have Operational Balancing Agreements (“OBAs”) with SPLNG and SPL that provide for the resolution of any operational imbalances (1) during the term of the agreement on an in-kind basis and (2) upon termination of the agreement by cash-out at a rate equivalent to the average of the midpoint prices for Henry Hub, Louisiana pricing published in “Gas Daily’s-Daily Price Survey” for each day of the month following termination. The SPLNG OBA became effective following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, and the SPL OBA became effective in April 2015. As of both December 31, 2017 and 2016, we had $0.6 million of other current liabilities—affiliate under the operational balancing agreements.

 

Transportation Agreements

SPL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of adequate natural gas feedstock to the Sabine Pass LNG terminal. See Note 5—Revenues from Contracts with Customers for information regarding these agreements. As of both December 31, 2017 and 2016, we had $6.8 million of accounts receivable—affiliate under the transportation agreements.

Interconnect Agreement

We had an agreement with SPL whereby SPL constructed certain interconnect facilities between the Creole Trail Pipeline and the Liquefaction Project, with ownership and responsibility for maintenance and operation transferred to us following construction. Upon completion of certain modifications during the third quarter of 2015, SPL conveyed $10.1 million of assets to us under this agreement.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement is effective for tax returns due on or after May 2013.

NOTE 7—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $0.4 million, $0.3 million and $0.3 million, respectively, related primarily to land sites and office space. 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.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands): 

Years Ending December 31,	Operating Leases (1)
2018	$	330
2019	330
2020	329
2021	329
2022	393
Thereafter	5,530
Total	$	7,241

(1)	Includes certain lease option renewals that are reasonably assured.

NOTE 8—COMMITMENTS AND CONTINGENCIES

Services Agreements

We have certain services agreements with affiliates. See Note 6—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. See Note 6—Related Party Transactions for additional information regarding this agreement.

Guarantees

Certain subsidiaries of Cheniere Partners, including us, have unconditionally guaranteed the debt obligations of Cheniere Partners. See Note 10—Guarantees for information regarding these guarantees.

Other Commitments

 

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position and meet the definition of a commitment as of December 31, 2017. Additionally, we have various operating lease commitments, as disclosed in Note 7—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, 2017, 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.

NOTE 9—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of cash flow information (in thousands):

		Year Ended December 31,
		2017				2016				2015
Cash paid during the period for interest, net of amounts capitalized		$	—			$	2,429			$	12,483
Non-cash contribution from affiliate for conveyance of assets		—				—				10,130

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $0.4 million, $0.2 million and $0.9 million as of December 31, 2017, 2016 and 2015, respectively.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 10—GUARANTEES

 

In February 2016, Cheniere Partners entered into a credit and guaranty agreement aggregating $2.8 billion (the “2016 CQP Credit Facilities”), which included a $450.0 million CTPL tranche term loan that was used to satisfy our obligations under an existing term loan in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LNG-LP, LLC, a wholly owned subsidiary of Cheniere Partners, subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2017, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us, and the real property of Sabine Pass LNG, L.P. (except for certain excluded properties).

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 11—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:

Standard		Description		Expected Date of Adoption		Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto		This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).		January 1, 2018		We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 5—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto		This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and 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 Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases on our 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. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
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 Financial Statements and related disclosures.

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CHENIERE CREOLE TRAIL PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:

Standard		Description		Date of Adoption		Effect on our Financial Statements or Other Significant Matters
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 did not have a material impact on our Financial Statements or related disclosures.

NOTE 12—SUBSEQUENT EVENTS

Recent FERC Developments

On March 15, 2018, the FERC issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (“MLP”) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in Tax Reform and this policy statement. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are currently evaluating the impact of these developments and continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform.

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