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•	statements regarding our ability to pay distributions to our unitholders;

•	statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL;

•	statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction facility, pipeline facility or other projects, or any expansions or portions thereof, by certain dates, or at all;

•

statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;

•	statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;

•	statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;

•	statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;

•	statements regarding counterparties to our commercial contracts, construction contracts and other contracts;

•	statements regarding our planned development and construction of additional Trains, including the financing of such Trains;

•	statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;

•	statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;

•	statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; and

•	any other statements that relate to non-historical or future information.

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ITEMS 1. AND 2.	BUSINESS AND PROPERTIES

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•	safely, efficiently and reliably operating and maintaining our assets, including our Trains;

•	procuring natural gas and pipeline transport capacity to our facility;

•	commencing commercial delivery for our long-term SPA customers, of which we have initiated for six of eight long-term SPA customers as of December 31, 2019;

•	safely, on-time and on-budget completing construction and commencing operation of Train 6 of the Liquefaction Project; and

•	maximizing the production of LNG to serve our long-term customers and generating steady and stable revenues and operating cash flows;

•	Trains 1 through 4—FTA countries for a 30-year term, which commenced in May 2016, and non-FTA countries for a 20-year term, which commenced in June 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).

•	Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term, both of which commenced in December 2018, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).

•	Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, which partially commenced in June 2019 and the remainder commenced in September 2019, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).

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•	approximately $720 million from BG Gulf Coast LNG, LLC (“BG”), which is guaranteed by BG Energy Holdings Limited;

•	approximately $550 million from Korea Gas Corporation (“KOGAS”);

•	approximately $550 million from GAIL;

•	approximately $450 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM, Limited) (“Naturgy”), which is guaranteed by Naturgy Energy Group, S.A. (formerly known as Gas Natural SDG S.A.); and

•	approximately $310 million from Total Gas & Power North America, Inc. (“Total”), which is guaranteed by Total S.A.

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•	rates and charges, and terms and conditions for natural gas transportation, storage and related services;

•	the certification and construction of new facilities and modification of existing facilities;

•	the extension and abandonment of services and facilities;

•	the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;

•	the acquisition and disposition of facilities;

•	the initiation and discontinuation of services; and

•	various other matters.

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ITEM 1A.	RISK FACTORS

•	Risks Relating to Our Financial Matters;

•	Risks Relating to Our Business;

•	Risks Relating to Our Cash Distributions;

•	Risks Relating to an Investment in Us and Our Common Units; and

•	Risks Relating to Tax Matters.

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•	expected supply is less than the amount hedged;

•	the counterparty to the hedging contract defaults on its contractual obligations; or

•	there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

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•	the facilities’ performing below expected levels of efficiency;

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•	breakdown or failures of equipment;

•	operational errors by vessel or tug operators;

•	operational errors by us or any contracted facility operator;

•	labor disputes; and

•	weather-related interruptions of operations.

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•	design and engineer each Train to operate in accordance with specifications;

•	engage and retain third-party subcontractors and procure equipment and supplies;

•	respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;

•	attract, develop and retain skilled personnel, including engineers;

•	post required construction bonds and comply with the terms thereof;

•	manage the construction process generally, including coordinating with other contractors and regulatory agencies; and

•	maintain their own financial condition, including adequate working capital.

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•	additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from the Sabine Pass LNG terminal;

•	competitive liquefaction capacity in North America;

•	insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;

•	insufficient LNG tanker capacity;

•	weather conditions, including extreme weather events and temperature volatility resulting from climate change;

•	reduced demand and lower prices for natural gas;

•	increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

•	decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;

•	cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;

•	changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;

•	changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

•	political conditions in natural gas producing regions;

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•	sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;

•	adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and

•	cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

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•	increased construction costs;

•	economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;

•	decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;

•	the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;

•	political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and

•	any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.

•	an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;

•	political or economic disturbances in the countries where the vessels are being constructed;

•	changes in governmental regulations or maritime self-regulatory organizations;

•	work stoppages or other labor disturbances at the shipyards;

•	bankruptcy or other financial crisis of shipbuilders;

•	quality or engineering problems;

•	weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and

•	shortages of or delays in the receipt of necessary construction materials.

•	increases in worldwide LNG production capacity and availability of LNG for market supply;

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•	increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;

•	increases in the cost to supply natural gas feedstock to the Liquefaction Project;

•	decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;

•	decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;

•	increases in capacity and utilization of nuclear power and related facilities; and

•	displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

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•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventative and mitigating actions.

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•	if we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

•	if we are unable to identify attractive capital expansion projects or negotiate acceptable engineering procurement and construction arrangements for them;

•	if we are unable to obtain necessary governmental approvals;

•	if we are unable to obtain financing for the acquisitions or capital expansion projects on economically acceptable terms, or at all;

•	if we are unable to secure adequate customer commitments to use the acquired or expansion facilities; or

•	if we are outbid by competitors.

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•	an inability to integrate successfully the businesses that we acquire with our existing business;

•	a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;

•	the assumption of unknown liabilities;

•	limitations on rights to indemnity from the seller;

•	mistaken assumptions about the cash generated, or to be generated, by the business acquired or the overall costs of equity or debt;

•	the diversion of management’s and employees’ attention from other business concerns; and

•	unforeseen difficulties encountered in operating new business segments or in new geographic areas.

•	performance by counterparties of their obligations under the SPAs;

•	performance by SPL of its obligations under the SPAs;

•	performance by counterparties of their obligations under the TUAs;

•	performance by SPLNG of its obligations under the TUAs;

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•	performance by, and the level of cash receipts received from, Cheniere Marketing under the amended and restated variable capacity rights agreement; and

•	the level of our operating costs, including payments to our general partner and its affiliates.

•	the restrictions contained in our debt agreements and our debt service requirements, including our ability to pay distributions under our credit facilities and the ability of SPL to pay distributions to us under its working capital facility and senior notes;

•	the costs and capital requirements of acquisitions, if any;

•	fluctuations in our working capital needs;

•	our ability to borrow for working capital or other purposes; and

•	the amount, if any, of cash reserves established by our general partner.

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•	make certain investments;

•	purchase, redeem or retire equity interests;

•	issue preferred stock;

•	sell or transfer assets;

•	incur liens;

•	enter into transactions with affiliates;

•	consolidate, merge, sell or lease all or substantially all of its assets; and

•	enter into sale and leaseback transactions.

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•	neither our partnership agreement nor any other agreement requires Cheniere to pursue a business strategy that favors us. Cheniere’s directors and officers have a fiduciary duty to make these decisions in favor of the owners of Cheniere, which may be contrary to our interests:

•	our general partner controls the interpretation and enforcement of contractual obligations between us, on the one hand, and Cheniere, on the other hand, including provisions governing administrative services and acquisitions;

•	our general partner is allowed to take into account the interests of parties other than us, such as Cheniere and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us and our unitholders;

•	our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty;

•	Cheniere is not limited in its ability to compete with us. Please read “Cheniere is not restricted from competing with us and is free to develop, operate and dispose of, and is currently developing, LNG facilities, pipelines and other assets without any obligation to offer us the opportunity to develop or acquire those assets”;

•	our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities, and the establishment, increase or decrease in the amounts of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

•

our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

•	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;

•	our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

•	our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and

•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner, as long as it acted in good faith, meaning that it believed the decision was in the best interests of our partnership;

•

generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us;

•

provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was criminal; and

•	provides that in resolving conflicts of interest, it will be presumed that in making its decision the conflicts committee or the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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•	our unitholders’ proportionate ownership interest in us will decrease;

•	the amount of cash available per unit to pay distributions may decrease;

•	because a lower percentage of total outstanding units will be subordinated units, the risk will increase that a shortfall in the payment of the initial quarterly distributions will be borne by our common unitholders;

•	the ratio of taxable income to distributions may increase;

•	the relative voting strength of each previously outstanding unit may be diminished; and

•	the market price of the common units may decline.

•	our quarterly distributions;

•	domestic and worldwide supply of and demand for natural gas and corresponding fluctuations in the price of natural gas;

•	fluctuations in our quarterly or annual financial results or those of other companies in our industry;

•	issuance of additional equity securities which causes further dilution to our unitholders;

•	sales of a high volume of our common units by our unitholders;

•	operating and unit price performance of companies that investors deem comparable to us;

•	events affecting other companies that the market deems comparable to us;

•	changes in government regulation or proposals applicable to us;

•	actual or potential non-performance by any customer or a counterparty under any agreement;

•	announcements made by us or our competitors of significant contracts;

•	changes in accounting standards, policies, guidance, interpretations or principles;

•	general conditions in the industries in which we operate;

•	general economic conditions;

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•	the failure of securities analysts to cover our common units or changes in financial or other estimates by analysts; and

•	other factors described in these “Risk Factors.”

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 4.	MINE SAFETY DISCLOSURE

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ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

•

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and any other outstanding units that are senior or equal in right of distribution to the subordinated units equaled or exceeded the sum of the initial quarterly distributions on all of the outstanding common units, subordinated units, general partner units and any other outstanding units that are senior or equal in right of distribution to the subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•

the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the initial quarterly distributions on all of the outstanding common units, subordinated units, general partner units and any other outstanding units that are senior or equal in right of distribution to the subordinated units during those periods on a fully diluted basis; and

•	there are no arrearages in payment of the initial quarterly distribution on the common units.

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•	the subordination period will end and each subordinated unit will immediately convert into one common unit;

•	any existing arrearages in payment of the initial quarterly distribution on the common units will be extinguished; and

•	the general partner will have the right to convert its general partner units and its IDRs into common units or to receive cash in exchange for those interests.

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in connection with distributions of available cash from operating surplus, the amount of such distributions constituting “contracted adjusted operating surplus” (as defined below) on each outstanding common unit, subordinated unit and any other outstanding unit that is senior or equal in right of distribution to the subordinated units equaled or exceeded $0.638 (150% of the initial quarterly distribution) for each quarter in the four-quarter period immediately preceding that date;

•

the contracted adjusted operating surplus generated during each quarter in the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $0.638 (150% of the initial quarterly distribution) on all of the outstanding common units, subordinated units, general partner units, any other units that are senior or equal in right of distribution to the subordinated units, and any other equity securities that are junior to the subordinated units that the board of directors of our general partner deems to be appropriate for the calculation, after consultation with management of our general partner, on a fully diluted basis; and

•	there are no arrearages in payment of the initial quarterly distribution on the common units

•	operating surplus generated with respect to that period; less

•	any net increase in working capital borrowings with respect to that period; less

•	any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

•	any net decrease in working capital borrowings with respect to that period; plus

•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

•	generally means adjusted operating surplus derived solely from SPAs and TUAs, in each case, with a minimum term of three years with counterparties who are not affiliates of Cheniere; and

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•	excludes revenues and expenses attributable to the portion of payments made under the SPAs related to the final settlement price for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which the relevant cargo’s delivery window is scheduled.

ITEM 6.	SELECTED FINANCIAL DATA

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

•	Overview of Business

•	Overview of Significant Events

•	Liquidity and Capital Resources

•	Contractual Obligations

•	Results of Operations

•	Off-Balance Sheet Arrangements

•	Summary of Critical Accounting Estimates

•	Recent Accounting Standards

•	In May 2019, the board of directors of our general partner made a positive final investment decision (“FID”) with respect to Train 6 of the Liquefaction Project and issued a full notice to proceed with construction to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) in June 2019.

•	As of February 21, 2020, over 900 cumulative LNG cargoes totaling over 60 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

•	In March 2019, SPL achieved substantial completion of Train 5 of the Liquefaction Project and commenced operating activities.

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In September 2019, we issued an aggregate principal amount of $1.5 billion of 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”) to prepay the outstanding balance under the $750 million term loan under our credit facilities (the “2019 CQP Credit Facilities”), which were entered into in May 2019, and for general corporate purposes, including funding future capital expenditures in connection with the construction of Train 6 at the Liquefaction Project. After applying the proceeds of the 2029 CQP Senior Notes, only a $750 million revolving credit facility, which is currently undrawn, remains as part of the 2019 CQP Credit Facilities.

•	We reached the following contractual milestones:

◦	In September 2019, the date of first commercial delivery was reached under the 20-year SPAs with Centrica plc and Total Gas & Power North America, Inc. (“Total”) relating to Train 5 of the Liquefaction Project.

◦	In March 2019, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC relating to Train 4 of the Liquefaction Project.

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•	Trains 1 through 4—FTA countries for a 30-year term, which commenced in May 2016, and non-FTA countries for a 20-year term, which commenced in June 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).

•	Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term, both of which commenced in December 2018, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).

•	Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, which partially commenced in June 2019 and the remainder commenced in September 2019, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).

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(1)

Includes SPL’s 5.625% Senior Secured Notes due 2021 , 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”) and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”) and our CQP Senior Notes.

(2)	Includes outstanding balances under the SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2019 CQP Credit Facilities that may be used for general corporate purposes.

(3)	Consists of SPL Working Capital Facility and 2019 CQP Credit Facilities. Balance at December 31, 2018 did not include the letters of credit issued or available commitments under the terminated 2016 CQP Credit Facilities, which were not specifically for the Sabine Pass LNG Terminal.

(4)	Does not include equity contributions that may be available from Cheniere’s borrowings under its convertible notes, which may be used for the Sabine Pass LNG Terminal.

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•	issuance of an aggregate principal amount of $1.5 billion of the 2029 CQP Senior Notes, which was used to prepay the outstanding balance of the term loan under the 2019 CQP Credit Facilities;

•	$35 million of debt issuance costs related to the up-front fees paid upon the issuance of the 2019 CQP Credit Facilities and 2029 CQP Senior Notes;

•	$730 million of borrowings and repayments under the 2019 CQP Credit Facilities; and

•	$1,260 million of distributions to unitholders.

•	issuance of an aggregate principal amount of $1.1 billion of the 2026 CQP Senior Notes, which was used to prepay $1.1billion of the outstanding borrowings under the 2016 CQP Credit Facilities;

•	$8 million of debt issuance costs related to up-front fees paid upon the closing of the above transactions;

•	$7 million in debt extinguishment costs related to the prepayment of the 2016 CQP Credit Facilities; and

•	$1.1 billion in distributions to unitholders.

•	issuances of SPL’s senior notes for an aggregate principal amount of $2.15 billion;

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•	$55 million of borrowings and $369 million of repayments made under the credit facilities SPL entered into in June 2015 (the “SPL Credit Facilities”);

•	issuance of an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which was used to prepay $1.5 billion of the outstanding borrowings under the 2016 CQP Credit Facilities;

•	$110 million of borrowings and $334 million of repayments made under the SPL Working Capital Facility;

•	$50 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and

•	$294 million of distributions to unitholders.

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(1)	Agreements in force as of December 31, 2019 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2019.

(2)	Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2019.  A discussion of our debt obligations can be found in Note 11—Debt of our Notes to Consolidated Financial Statements.

(3)	Operating lease obligations primarily consist of land sites related to the Sabine Pass LNG terminal as further discussed in Note 12—Leases of our Notes to Consolidated Financial Statements.

(4)

Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include only contracts for which conditions precedent have been met. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly. We include contracts for which we have an early termination option if the option is not expected to be exercised.

(5)	Construction obligations primarily consist of the estimated remaining cost pursuant to our EPC contracts as of December 31, 2019 for Trains with respect to which we have made an FID to commence construction. A discussion of these obligations can be found at Note 16—Commitments and Contingencies of our Notes to Consolidated Financial Statements.

(6)	Pricing of natural gas supply agreements are based on estimated forward prices and basis spreads as of December 31, 2019.

(7)	Other purchase obligations primarily relate to payments under SPL’s partial TUA assignment agreement with Total as discussed in Note 13—Revenues from Contracts with Customers of our Notes to Consolidated Financial Statements.

(8)	Other non-current liabilities—affiliate primarily relate to obligations to Cheniere Marketing related to the Cooperative Endeavor Agreement, as discussed in Note 14—Related Party Transactions of our Notes to Consolidated Financial Statements.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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We are a publicly traded Delaware limited partnership formed by Cheniere in 2006. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Through our subsidiary, SPL, we are currently operating five natural gas liquefaction Trains and are constructing one additional Train for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal. Through our subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks, two marine berths and vaporizers. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”).

As of December 31, 2019, Cheniere owned 48.6% of our limited partner interest in the form of 104.5 million of our common units and 135.4 million of our subordinated units. Cheniere also owns 100% of our general partner interest and our incentive distribution rights.

 

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 accumulated 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.

 

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.

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Recent Accounting Standards

We adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard resulted in the recognition of right-of-use assets and lease liabilities for operating leases of approximately $100 million on our Consolidated Balance Sheets, with no material impact on our Consolidated Statements of Income or Consolidated Statements of Cash Flows. We have elected the practical expedients to (1) carryforward prior conclusions related to lease identification and classification for existing leases, (2) combine lease and non-lease components of an arrangement for all classes of leased assets, (3) omit short-term leases with a term of 12 months or less from recognition on the balance sheet and (4) carryforward our existing accounting for land easements not previously accounted for as leases. See Note 12—Leases for additional information on our leases following the adoption of this standard.

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 fair value measurements, revenue recognition, property, plant and equipment, derivative instruments, leases and asset retirement obligations (“AROs”), as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value Measurements

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

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

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 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. See Note 13—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.

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Restricted Cash

Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets.

Accounts Receivable

Accounts receivable is reported net of any allowances for doubtful accounts. We periodically review the collectability on our accounts receivable and recognize an allowance if there is probability of non-collection, based on historical write-off and customer-specific factors. We did not have an allowance on our accounts receivable as of December 31, 2019 and 2018.

Inventory

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

Accounting for LNG Activities

 

Generally, we begin capitalizing the costs of our LNG terminal 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 preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminal.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.

Property, Plant and Equipment 

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets.

 

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.

Interest Capitalization

We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.

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

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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 pipeline. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after the 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. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2019, 2018 and 2017. See Note 8—Derivative Instruments for additional details about our derivative instruments.

Leases

Following the adoption of ASC 842, we determine if an arrangement is, or contains, a lease at inception of the arrangement. When we determine the arrangement is, or contains, a lease, we classify the lease as either an operating lease or a finance lease. We did not have any financing leases as of December 31, 2019. Operating leases are recognized on our Consolidated Balance Sheets 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. Operating lease right-of-use assets and liabilities are generally recognized based on the present value of lease payments over the lease term. In determining the present value of lease payments, we use the implicit interest rate in the lease if readily determinable. In the absence of a readily determinable implicitly interest rate, we discount our expected future lease payments using our relevant subsidiary’s incremental borrowing rate. The incremental borrowing rate is an estimate of the interest rate that a given subsidiary would have to pay to borrow on a collateralized basis over a similar term to that of the lease term. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability, only to the extent they are reasonably certain to be exercised. We have elected practical expedients to (1) omit leases with an initial term of 12 months or less from recognition on our balance sheet and (2) to combine both the lease and non-lease components of an arrangement in calculating the right-of-use asset and lease liability for all classes of leased assets.

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Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Operating leases are included in operating lease assets, net, current operating lease liabilities and non-current operating lease liabilities on our Consolidated Balance Sheets. See Note 12—Leases for additional details about our leases.

Concentration of Credit Risk

 

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

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. 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 fixed price long-term SPAs generally with terms of 20 years with eight third parties and has entered into agreements with Cheniere Marketing. 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 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 and unsecured debt securities and credit facilities with banks and other lenders.  Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.  

Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, they are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in gain (loss) on modification or extinguishment of debt on our Consolidated Statements of Income.

Asset Retirement Obligations

 

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

 

We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass

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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 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, 2019, the tax basis of our assets and liabilities was $5.7 billion less than the reported amounts of our assets and liabilities. See Note 14—Related Party Transactions for details about income taxes under our tax sharing agreements.

Business Segment

Our liquefaction and regasification operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of Cheniere Partners in total when evaluating financial performance and for purposes of allocating resources.

 

Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2019 and 2018, restricted cash consisted of the following (in millions):

		December 31,
		2019				2018
Current restricted cash
Liquefaction Project		$	181			$	756
Cash held by us and our guarantor subsidiaries		—				785
Total current restricted cash		$	181			$	1,541

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.

The cash held by us and our guarantor subsidiaries was restricted in use under the terms of the previous $2.8 billion credit facilities (the “2016 CQP Credit Facilities”) and the related depositary agreement governing the extension of credit to us, but is no longer restricted following the termination of the 2016 CQP Credit Facilities. Amounts not classified as restricted have been reserved by our general partner under the terms of our partnership agreement.

As of December 31, 2019 and 2018, accounts and other receivables consisted of the following (in millions):

		December 31,
		2019				2018
SPL trade receivable		$	283			$	330
Other accounts receivable		14				18
Total accounts and other receivables		$	297			$	348

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As of December 31, 2019 and 2018, inventory consisted of the following (in millions):

		December 31,
		2019				2018
Natural gas		$	9			$	28
LNG		27				6
Materials and other		80				65
Total inventory		$	116			$	99

 

As of December 31, 2019 and 2018, property, plant and equipment, net consisted of the following (in millions):

		December 31,
		2019				2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities		$	16,894			$	12,760
LNG terminal construction-in-process		1,275				3,913
Accumulated depreciation		(1,807		)		(1,290		)
Total LNG terminal costs, net		16,362				15,383
Fixed assets
Fixed assets		27				26
Accumulated depreciation		(21		)		(19		)
Total fixed assets, net		6				7
Property, plant and equipment, net		$	16,368			$	15,390

 

Depreciation expense was $523 million, $413 million and $331 million during the years ended December 31, 2019, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $48 million, $94 million and $301 million during the years ended December 31, 2019, 2018 and 2017, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project, during the testing phase for its construction.

LNG Terminal Costs

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 have depreciable lives between 7 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
Water pipelines		30
Regasification processing equipment		30
Sendout pumps		20
Liquefaction processing equipment		7-50
Other		10-30

Fixed Assets and Other

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

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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 (collectively, the “Liquefaction Supply Derivatives”).

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

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2019 and 2018, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).

	Fair Value Measurements as of
	December 31, 2019																December 31, 2018
	Quoted Prices in Active Markets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total				Quoted Prices in Active Markets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
Liquefaction Supply Derivatives asset (liability)	$	3			$	(3	)		$	24			$	24			$	5			$	(23	)		$	(25	)		$	(43	)

We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of December 31, 2019 and 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2019:

		Net Fair Value Asset (in millions)		Valuation Approach		Significant Unobservable Input		Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives		$24		Market approach incorporating present value techniques		Henry Hub basis spread		$(0.350) - $0.058

Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.

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The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2019, 2018 and 2017 (in millions):

		Year Ended December 31,
		2019				2018				2017
Balance, beginning of period		$	(25	)		$	43			$	79
Realized and mark-to-market gains (losses):
Included in cost of sales		6				(3		)		(37		)
Purchases and settlements:
Purchases		—				(37		)		14
Settlements		42				(29		)		(12		)
Transfers out of Level 3 (1)		1				1				(1		)
Balance, end of period		$	24			$	(25	)		$	43
Change in unrealized gains (losses) relating to instruments still held at end of period		$	6			$	(3	)		$	(37	)

(1)    Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. 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, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

Interest Rate Derivatives

In October 2018, we settled the interest rate swaps (“CQP Interest Rate Derivatives”) we previously had to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2016 CQP Credit Facilities.

In March 2017, SPL settled the interest rate swaps (“SPL Interest Rate Derivatives”) it previously had 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 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 Income during the years ended December 31, 2019, 2018 and 2017 (in millions):

		Year Ended December 31,
		2019			2018			2017
CQP Interest Rate Derivatives gain		—			14			6
SPL Interest Rate Derivatives loss		—			—			(2	)

Liquefaction Supply Derivatives

SPL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs.

The notional natural gas position of our Liquefaction Supply Derivatives was approximately 3,663 TBtu and 2,978 TBtu as of December 31, 2019 and 2018, respectively.

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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, 2019				December 31, 2018
Derivative assets		$	17			$	6
Non-current derivative assets		32				31
Total derivative assets		49				37
Derivative liabilities		(9		)		(66		)
Non-current derivative liabilities		(16		)		(14		)
Total derivative liabilities		(25		)		(80		)
Derivative asset (liability), net		$	24			$	(43	)

(1)	Does not include collateral posted with counterparties by us of $2 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2019 and 2018, 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 Income during the years ended December 31, 2019, 2018 and 2017 (in millions):

			Year Ended December 31,
	Consolidated Statement of Income Location (1)		2019				2018				2017
Liquefaction Supply Derivatives gain (loss)	LNG revenues		$	1			$	(1	)		$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales		71				(100		)		(24		)

(1)	Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

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, 2019
Liquefaction Supply Derivatives		$	51			$	(2	)		$	49
Liquefaction Supply Derivatives		(27		)		2				(25		)
As of December 31, 2018
Liquefaction Supply Derivatives		$	63			$	(26	)		$	37
Liquefaction Supply Derivatives		(92		)		12				(80		)

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As of December 31, 2019 and 2018, other non-current assets, net consisted of the following (in millions):

		December 31,
		2019				2018
Advances made to municipalities for water system enhancements		$	87			$	90
Advances and other asset conveyances to third parties to support LNG terminal		35				36
Tax-related prepayments and receivables		17				17
Information technology service prepayments		6				20
Advances made under EPC and non-EPC contracts		15				14
Other		8				7
Total other non-current assets, net		$	168			$	184

 

As of December 31, 2019 and 2018, accrued liabilities consisted of the following (in millions):

		December 31,
		2019				2018
Interest costs and related debt fees		$	241			$	224
Accrued natural gas purchases		325				518
LNG terminal and related pipeline costs		135				79
Other accrued liabilities		8				—
Total accrued liabilities		$	709			$	821

 

As of December 31, 2019 and 2018, our debt consisted of the following (in millions):

		December 31,
		2019				2018
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)		$	2,000			$	2,000
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”)		1,500				1,500
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”)		1,350				1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)		800				800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)		1,500				1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)		1,100				1,100
4.500% Senior Notes due 2029 (“2029 CQP Senior Notes”)		1,500				—
2016 CQP Credit Facilities		—				—
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”)		—				—
Unamortized premium, discount and debt issuance costs, net		(171		)		(184		)
Total long-term debt, net		17,579				16,066
Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)		—				—
Total debt, net		$	17,579			$	16,066

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Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2019 (in millions): 

Years Ending December 31,		Principal Payments
2020		$	—
2021		2,000
2022		1,000
2023		1,500
2024		2,000
Thereafter		11,250
Total		$	17,750

Senior Notes

SPL Senior Notes

The terms of the 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 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 and are fully amortizing according to a fixed sculpted amortization schedule. 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.

CQP Senior Notes

In September 2019, we issued an aggregate principal amount of $1.5 billion of the 2029 CQP Senior Notes. The proceeds of the offering were used to prepay the outstanding balance of the $750 million term loan under the 2019 CQP Credit Facilities (“CQP Term Facility”) and for general corporate purposes, including funding future capital expenditures in connection with the construction of Train 6 at the Liquefaction Project, resulting in the recognition of debt modification and extinguishment costs of $13 million for the year ended December 31, 2019. Borrowings under the 2029 CQP Senior Notes accrue interest at a fixed rate of 4.500% per annum. As of December 31, 2019, only the $750 million revolving credit facility (“CQP Revolving Facility”), all of which is undrawn, remains as part of the 2019 CQP Credit Facilities.

The 2025 CQP Senior Notes, the 2026 CQP Senior Notes and the 2029 CQP Senior Notes (collectively, the “CQP Senior Notes”) are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (the “CQP Guarantors”). The CQP Senior Notes are governed by the same base indenture (the “CQP

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Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture, the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture and the 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture. The indentures governing the CQP Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit our ability and the CQP Guarantors’ ability 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. Interest on the CQP Senior Notes is payable semi-annually in arrears.

At any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, we may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, we may redeem up to 35% of the aggregate principal amount of the 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, 105.625% of the aggregate principal amount of the 2026 CQP Senior Notes and 104.5%of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. We also may at any time on or after October 1, 2020 through the maturity date of October 1, 2025 for the 2025 CQP Senior Notes, October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes and October 1, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.

The 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. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on substantially all our existing and future tangible and intangible assets and rights and of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2019 (in millions):

		SPL Working Capital Facility				2019 CQP Credit Facilities
Original facility size		$	1,200			$	1,500
Less:
Outstanding balance		—				—
Commitments prepaid or terminated		—				750
Letters of credit issued		414				—
Available commitment		$	786			$	750
Interest rate on available balance		LIBOR plus 1.75% or base rate plus 0.75%				LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Weighted average interest rate of outstanding balance		n/a				n/a
Maturity date		December 31, 2020				May 29, 2024

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SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility with aggregate commitments of $1.2 billion, which was amended in May 2019 in connection with commercialization and financing of Train 6 of the Liquefaction Project. The SPL Working Capital Facility is intended to be used for loans to SPL (“SPL Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“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 incremental increases 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 SPL Swing Line Loans and loans deemed made in connection with a draw upon a letter of credit (“SPL 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 SPL 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 “SPL LC Draw”) to be deemed an SPL LC Loan, SPL is required to pay the full amount of the SPL LC Draw on or prior to the business day following the notice of the SPL LC Draw. An SPL LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of December 31, 2019, no SPL 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. SPL LC Loans have a term of up to one year. SPL 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 SPL Swing Line Loan is made and (3) the first borrowing date for a SPL Working Capital Loan or SPL Swing Line Loan occurring at least three business days following the date the SPL Swing Line Loan is made. SPL is required to reduce the aggregate outstanding principal amount of all SPL 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.

CQP Credit Facilities

In May 2019, we terminated the remaining commitments under the 2016 CQP Credit Facilities and entered into the 2019 CQP Credit Facilities, which consisted of the $750 million CQP Term Facility, which was prepaid and terminated upon issuance of the 2029 CQP Senior Notes in September 2019, and the $750 million CQP Revolving Facility. Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the Liquefaction Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit.

Loans under the 2019 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 the adjusted one-month LIBOR plus 1.0%), plus the applicable margin. Under the CQP Term Facility, the applicable margin for LIBOR loans was 1.50% per annum, and the applicable margin for base rate loans was 0.50% per annum. Under the CQP Revolving Facility, the applicable margin for LIBOR loans is 1.25% to 2.125% per annum, and the applicable margin for base rate loans is 0.25% to 1.125% per annum, in each case depending on our then-current rating. Interest on LIBOR

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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.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit our ability to make restricted payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.

The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted encumbrances) on substantially all of our and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).

Restrictive Debt Covenants

As of December 31, 2019, 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,
		2019				2018				2017
Total interest cost		$	972			$	936			$	902
Capitalized interest		(87		)		(203		)		(288		)
Total interest expense, net		$	885			$	733			$	614

Fair Value Disclosures

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

		December 31, 2019								December 31, 2018
		Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
Senior notes (1)		$	16,950			$	18,320			$	15,450			$	15,672
2037 SPL Senior Notes (2)		800				934				800				817
Credit facilities (3)		—				—				—				—

(1)	Includes SPL Senior Notes except the 2037 SPL Senior Notes and the 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 SPL Working Capital Facility, 2016 CQP Credit Facilities and 2019 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.

Our leased assets consist primarily of tug vessels and land sites, all of which are classified as operating leases.

ASC 842 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. As our leases generally do not provide an implicit rate, in order to calculate the lease liability, we discounted our expected future lease

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payments using our relevant subsidiary’s incremental borrowing rate at the later of January 1, 2019 or the commencement date of the lease. The incremental borrowing rate is an estimate of the rate of interest that a given subsidiary would have to pay to borrow on a collateralized basis over a similar term to that of the lease term.

Many of our leases contain renewal options exercisable at our sole discretion. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability only to the extent they are reasonably certain to be exercised, such as when necessary to satisfy obligations that existed at the execution of the lease or when the non-renewal would otherwise result in a significant economic penalty.

We have elected the practical expedient to omit leases with an initial term of 12 months or less (“short-term lease”) from recognition on the balance sheet. We recognize short-term lease payments on a straight-line basis over the lease term and variable payments under short-term leases in the period in which the obligation is incurred.

Certain of our leases contain non-lease components which are not separated from the lease components when calculating the right-of-use asset and lease liability per our use of the practical expedient to combine both components of an arrangement for all classes of leased assets.

Certain of our leases also contain variable payments, such as inflation, that are not included when calculating the right-of-use asset and lease liability unless the payments are in-substance fixed. We recognize lease expense for operating leases on a straight-line basis over the lease term.

The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):

	Consolidated Balance Sheet Location		December 31, 2019
Right-of-use assets—Operating	Operating lease assets, net		$	94
Current operating lease liabilities	Current operating lease liabilities		6
Non-current operating lease liabilities	Non-current operating lease liabilities		87

The following table shows the classification and location of our lease cost on our Consolidated Statements of Income (in millions):

	Consolidated Statement of Income Location		Year Ended December 31, 2019
Operating lease cost (1)	Operating costs and expenses (2)		$	11

(1)    Includes $1 million of variable lease costs paid to the lessor.

(2)	Presented in cost of sales, operating and maintenance expense, general and administrative expense or general and administrative expense—affiliate consistent with the nature of the asset under lease.

During the years ended December 31, 2018 and 2017, we recognized rental expense for all operating leases of $16 million and $13 million, respectively.

Future annual minimum lease payments for operating leases as of December 31, 2019 are as follows (in millions): 

Years Ending December 31,	Operating Leases
2020	$	9
2021	10
2022	10
2023	10
2024	10
Thereafter	116
Total lease payments	165
Less: Interest	(72		)
Present value of lease liabilities	$	93

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Future annual minimum lease payments for operating leases as of December 31, 2018, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows (in millions):

Years Ending December 31,	Operating Leases (1)
2019	$	10
2020	10
2021	10
2022	10
2023	10
Thereafter	124
Total	$	174

(1)	Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components.

The following table shows the weighted-average remaining lease term (in years) and the weighted-average discount rate for our operating leases:

	December 31, 2019
Weighted-average remaining lease term (in years)	26.4
Weighted-average discount rate	4.8	%

The following table includes other quantitative information for our operating leases (in millions):

	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	10

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2019, 2018 and 2017 (in millions):

		Year Ended December 31,
		2019				2018				2017
LNG revenues		$	5,210			$	4,828			$	2,635
LNG revenues—affiliate		1,312				1,299				1,389
Regasification revenues		266				261				260
Other revenues		49				39				20
Total revenues from customers		6,837				6,427				4,304
Net derivative gains (losses) (1)		1				(1		)		—
Total revenues		$	6,838			$	6,426			$	4,304

(1)	See Note 8—Derivative Instruments for additional information about our derivatives.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 14—Related Party Transactions for additional information regarding these agreements.

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

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

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d. Approximately 2 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 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 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.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby upon substantial completion of Train 5 of the Liquefaction Project, SPL gained access to substantially all 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 Train 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 and we continue to recognize the payments received from Total as revenue. During the years ended December 31, 2019, 2018 and 2017, SPL recorded $104 million, $30 million and $23 million, respectively, 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 on our Consolidated Balance Sheets (in millions):

		Year Ended December 31,
		2019				2018
Deferred revenues, beginning of period		$	116			$	111
Cash received but not yet recognized		155				116
Revenue recognized from prior period deferral		(116		)		(111		)
Deferred revenues, end of period		$	155			$	116

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

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years ended December 31, 2019 and 2018 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2019 and 2018:

		December 31, 2019						December 31, 2018
		Unsatisfied Transaction Price (in billions)				Weighted Average Recognition Timing (years) (1)		Unsatisfied Transaction Price (in billions)				Weighted Average Recognition Timing (years) (1)
LNG revenues (2)		$	55.0			10		$	53.6			10
Regasification revenues		2.4				5		2.6				6
Total revenues		$	57.4					$	56.2

    

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

(2)	Includes future consideration from agreement contractually assigned to SPL from Cheniere Marketing.

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

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

(2)

The table above excludes substantially all variable consideration under our SPAs and TUAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 52% and 57% of our LNG revenues during the years ended December 31, 2019 and 2018, respectively, were related to variable consideration received from customers. During each of the years ended December 31, 2019 and 2018, approximately 3% of our regasification revenues were related to variable consideration received from customers. All of our LNG revenues—affiliate were related to variable consideration received from customers during each of the years ended December 31, 2019 and 2018.

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.

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Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017 (in millions):

		Year Ended December 31,
		2019				2018				2017
LNG revenues—affiliate
Cheniere Marketing Agreements		$	1,309			$	1,299			$	1,389
Contracts for Sale and Purchase of Natural Gas and LNG		3				—				—
Total LNG revenues—affiliate		1,312				1,299				1,389
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG		7				—				—
Operating and maintenance expense—affiliate
Services Agreements		138				117				94
Other agreements		—				—				6
Total operating and maintenance expense—affiliate		138				117				100
General and administrative expense—affiliate
Services Agreements		102				73				80
Other income—affiliate
Cooperative Endeavor Agreement		2				—				—

As of December 31, 2019 and 2018, we had $105 million and $114 million, respectively, of accounts receivable—affiliate, under the agreements described below.

Terminal Use Agreement

SPL obtained approximately 2 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 make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing 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 Income.

Cheniere Marketing Agreements

Cheniere Marketing SPA

Cheniere Marketing has an SPA (“Base 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.

In May 2019, SPL and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by SPL to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo.

Cheniere Marketing Master SPA

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. SPL executed a confirmation with Cheniere Marketing that obligated Cheniere

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Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project.

Cheniere Marketing Letter Agreements

In May 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu that were delivered between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu.

In December 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes scheduled for delivery in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.

Services Agreements

As of December 31, 2019 and 2018, we had $158 million and $228 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.

Cheniere Partners Services Agreement

We have a services agreement with Cheniere Terminals, a 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 Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.

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

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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 initiative represented an aggregate commitment of $25 million over 10 years in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish may grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal as early as 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 ad valorem tax levied on our LNG terminal in the year the Cameron Parish dollar-for-dollar credit is applied.

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 obligations. We had $2 million and $3 million in due to affiliates and $20 million and $22 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing as of December 31, 2019 and 2018, respectively.

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.

SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related

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to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with Cheniere Terminals to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. The agreement also provides that Tug Services shall contingently pay Cheniere Terminals a portion of its future revenues. Accordingly, Tug Services distributed $8 million, $6 million and $3 million during the years ended December 31, 2019, 2018 and 2017, respectively, to Cheniere Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity.

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, 2019, 2018 and 2017.

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 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.

 

Net income (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 income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statements of Partners’ Equity. On January 28, 2020, we declared a $0.63 distribution per common unit and subordinated unit and the related distribution to our general partner and IDR holders to be paid on February 14, 2020 to unitholders of record as of February 7, 2020 for the period from October 1, 2019 to December 31, 2019.

The two-class method dictates that net income 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 (loss) 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

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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 Class B units previously held by Cheniere Energy Partners LP Holdings, LLC and Blackstone CQP Holdco, respectively. The impact of the beneficial conversion feature was also included in earnings per unit for the year ended December 31, 2017.

The following table provides a reconciliation of net income and the allocation of net income to the common units, the subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income (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, 2019
Net income		$	1,175
Declared distributions		1,278				858				—				333				26				62
Assumed allocation of undistributed net loss (1)		$	(103	)		(73		)		—				(28		)		(2		)		—
Assumed allocation of net income						$	785			$	—			$	305			$	24			$	62
Weighted average units outstanding						348.6				—				135.4
Basic and diluted net income per unit						$	2.25							$	2.25
Year Ended December 31, 2018
Net income		$	1,274
Declared distributions		1,162				795				—				309				22				36
Assumed allocation of undistributed net income (1)		$	112			79				—				31				2				—
Assumed allocation of net income						$	874			$	—			$	340			$	24			$	36
Weighted average units outstanding						348.6				—				135.4
Basic and diluted net income per unit						$	2.51							$	2.51
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		$	(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
Basic and diluted net loss per unit (2)						$	(1.32	)						$	(9.52	)

 

(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).

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(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.

 

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, 2019, 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 6 of the Liquefaction Project. The EPC contract price for Train 6 of the Liquefaction Project is approximately $2.5 billion, reflecting amounts incurred under change orders through December 31, 2019, and including estimated costs for an optional third marine berth.  As of December 31, 2019, we have incurred $1.1 billion under this contract. 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 physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. As of December 31, 2019, SPL has secured up to approximately 3,850 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the certain events or states of affairs are satisfied.

Additionally, SPL has natural gas transportation and storage service agreements for the Liquefaction Project. The initial terms of the natural gas transportation agreements range up to 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The initial terms of the SPL natural gas storage service agreements range up to 10 years.

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As of December 31, 2019, 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)
2020	$	2,248
2021	1,334
2022	849
2023	640
2024	320
Thereafter	1,914
Total	$	7,305

(1)	Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2019. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

    

Services Agreements

 

We have certain services agreements with affiliates. See Note 14—Related Party Transactions for information regarding such agreements.

 

Restricted Net Assets

 

At December 31, 2019, our restricted net assets of consolidated subsidiaries were approximately $3.0 billion.

Other Commitments

 

State Tax Sharing Agreements

 

SPLNG, SPL and CTPL have state tax sharing agreements with Cheniere. See Note 14—Related Party Transactions for information regarding such agreements.

Other Agreements

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

Environmental and Regulatory Matters

The Sabine Pass LNG Terminal and CTPL are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

 

Legal Proceedings

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The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers:

		Percentage of Total Revenues from External Customers						Percentage of Accounts Receivable from External Customers
		Year Ended December 31,						December 31,
		2019		2018		2017		2019		2018
Customer A		27%		28%		39%		21%		35%
Customer B		18%		21%		27%		13%		23%
Customer C		19%		23%		23%		22%		30%
Customer D		20%		19%		—%		13%		8%
Customer E		*		—%		—%		13%		—%
Customer F		*		*		*		14%		—%

* Less than 10%

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

	Revenues from External Customers
	Year Ended December 31,
	2019				2018				2017
United States	$	2,354			$	1,880			$	1,441
India	1,113				981				—
South Korea	1,071				1,168				666
Ireland	988				1,098				787
Other countries	—				—				21
Total	$	5,526			$	5,127			$	2,915

 

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

	Year Ended December 31,
	2019				2018				2017
Cash paid during the period for interest, net of amounts capitalized	$	829			$	719			$	510

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $291 million, $263 million and $273 million as of December 31, 2019, 2018 and 2017, respectively.

Our CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-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 indenture governing the CQP Senior Notes. See Note 11—Debt for additional information regarding the CQP Senior Notes.

The following is condensed consolidating financial information for Cheniere Partners (“Parent Issuer”), the Guarantors on a combined basis and the Non-Guarantors on a combined basis. The condensed consolidating financial information has been prepared using the same accounting policies as described in Note 3—Summary of Significant Accounting Policies, except for the investments in subsidiaries, which is accounted for using the equity method.

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In lieu of Schedule I pursuant to the requirements of Rule 5-04 of Reg S-X, the condensed parent company financial statements are presented below in the Parent Issuer column. The condensed parent only financial statements have been provided in accordance with the rules and regulations of the SEC and should be read in conjunction with Cheniere Partners’ Consolidated Financial Statements. Pursuant to the SEC rules and regulations, the condensed parent company financial statements do not include all of the financial information and notes normally included with financial statements prepared in accordance with GAAP.

 

Condensed Consolidating Balance Sheet
December 31, 2019
(in millions)
	Parent Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	1,778			$	3			$	—			$	—			$	1,781
Restricted cash	—				—				181				—				181
Accounts and other receivables	—				5				292				—				297
Accounts receivable—affiliate	—				43				104				(42		)		105
Advances to affiliate	—				145				133				(120		)		158
Inventory	—				13				103				—				116
Derivative assets	—				—				17				—				17
Other current assets	—				15				36				—				51
Other current assets—affiliate	—				1				22				(22		)		1
Total current assets	1,778				225				888				(184		)		2,707
Property, plant and equipment, net	79				2,454				13,861				(26		)		16,368
Operating lease assets, net	—				88				21				(15		)		94
Debt issuance costs, net	9				—				6				—				15
Non-current derivative assets	—				—				32				—				32
Investments in subsidiaries	2,963				508				—				(3,471		)		—
Other non-current assets, net	—				24				144				—				168
Total assets	$	4,829			$	3,299			$	14,952			$	(3,696	)		$	19,384
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—			$	2			$	38			$	—			$	40
Accrued liabilities	56				24				629				—				709
Due to affiliates	3				155				49				(161		)		46
Deferred revenue	—				23				132				—				155
Deferred revenue—affiliate	—				22				—				(21		)		1
Current operating lease liabilities	—				6				—				—				6
Derivative liabilities	—				—				9				—				9
Total current liabilities	59				232				857				(182		)		966
Long-term debt, net	4,055				—				13,524				—				17,579
Non-current operating lease liabilities	—				82				5				—				87
Non-current derivative liabilities	—				—				16				—				16
Other non-current liabilities	—				1				—				—				1
Other non-current liabilities—affiliate	—				21				16				(17		)		20
Partners’ equity	715				2,963				534				(3,497		)		715
Total liabilities and partners’ equity	$	4,829			$	3,299			$	14,952			$	(3,696	)		$	19,384

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Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)
	Parent Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—			$	—			$	—			$	—			$	—
Restricted cash	779				6				756				—				1,541
Accounts and other receivables	1				1				346				—				348
Accounts receivable—affiliate	1				40				113				(40		)		114
Advances to affiliate	—				104				210				(86		)		228
Inventory	—				12				87				—				99
Derivative assets	—				—				6				—				6
Other current assets	—				2				18				—				20
Other current assets—affiliate	—				—				21				(21		)		—
Total current assets	781				165				1,557				(147		)		2,356
Property, plant and equipment, net	79				2,128				13,209				(26		)		15,390
Debt issuance costs, net	1				—				12				—				13
Non-current derivative assets	—				—				31				—				31
Investments in subsidiaries	2,544				440				—				(2,984		)		—
Other non-current assets, net	—				26				158				—				184
Total assets	$	3,405			$	2,759			$	14,967			$	(3,157	)		$	17,974
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—			$	4			$	11			$	—			$	15
Accrued liabilities	39				14				768				—				821
Due to affiliates	—				127				48				(126		)		49
Deferred revenue	—				25				91				—				116
Deferred revenue—affiliate	—				22				—				(21		)		1
Derivative liabilities	—				—				66				—				66
Total current liabilities	39				192				984				(147		)		1,068
Long-term debt, net	2,566				—				13,500				—				16,066
Non-current derivative liabilities	—				—				14				—				14
Other non-current liabilities	—				1				3				—				4
Other non-current liabilities—affiliate	—				22				—				—				22
Partners’ equity	800				2,544				466				(3,010		)		800
Total liabilities and partners’ equity	$	3,405			$	2,759			$	14,967			$	(3,157	)		$	17,974

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Condensed Consolidating Statement of Income
Year Ended December 31, 2019
(in millions)
	Parent Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
Revenues
LNG revenues	$	—			$	—			$	5,211			$	—			$	5,211
LNG revenues—affiliate	—				—				1,312				—				1,312
Regasification revenues	—				266				—				—				266
Regasification revenues—affiliate	—				262				—				(262		)		—
Other revenues	—				49				—				—				49
Other revenues—affiliate	—				137				—				(137		)		—
Total revenues	—				714				6,523				(399		)		6,838
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—				1				3,373				—				3,374
Cost of sales—affiliate	—				7				47				(47		)		7
Operating and maintenance expense	—				85				547				—				632
Operating and maintenance expense—affiliate	—				30				450				(342		)		138
General and administrative expense	3				2				6				—				11
General and administrative expense—affiliate	13				27				79				(17		)		102
Depreciation and amortization expense	3				78				447				(1		)		527
Impairment expense and loss on disposal of assets	—				1				6				—				7
Total operating costs and expenses	19				231				4,955				(407		)		4,798
Income (loss) from operations	(19		)		483				1,568				8				2,040
Other income (expense)
Interest expense, net of capitalized interest	(174		)		(6		)		(705		)		—				(885		)
Loss on modification or extinguishment of debt	(13		)		—				—				—				(13		)
Equity earnings of subsidiaries	1,360				873				—				(2,233		)		—
Other income	21				—				10				—				31
Other income—affiliate	—				2				—				—				2
Total other income (expense)	1,194				869				(695		)		(2,233		)		(865		)
Net income	$	1,175			$	1,352			$	873			$	(2,225	)		$	1,175

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Condensed Consolidating Statement of Income
Year Ended December 31, 2018
(in millions)
	Parent Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
Revenues
LNG revenues	$	—			$	—			$	4,827			$	—			$	4,827
LNG revenues—affiliate	—				—				1,299				—				1,299
Regasification revenues	—				261				—				—				261
Regasification revenues—affiliate	—				258				—				(258		)		—
Other revenues	—				39				—				—				39
Other revenues—affiliate	—				247				—				(247		)		—
Total revenues	—				805				6,126				(505		)		6,426
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—				—				3,403				—				3,403
Cost of sales—affiliate	—				—				32				(32		)		—
Operating and maintenance expense	—				67				342				—				409
Operating and maintenance expense—affiliate	—				151				423				(457		)		117
Development expense	—				—				2				—				2
General and administrative expense	4				2				5				—				11
General and administrative expense—affiliate	12				25				50				(14		)		73
Depreciation and amortization expense	2				74				349				(1		)		424
Impairment expense and loss on disposal of assets	—				8				—				—				8
Total operating costs and expenses	18				327				4,606				(504		)		4,447
Income (loss) from operations	(18		)		478				1,520				(1		)		1,979
Other income (expense)
Interest expense, net of capitalized interest	(139		)		(5		)		(589		)		—				(733		)
Loss on modification or early extinguishment of debt	(12		)		—				—				—				(12		)
Derivative gain, net	14				—				—				—				14
Equity earnings of subsidiaries	1,416				944				—				(2,360		)		—
Other income	13				—				13				—				26
Total other income (expense)	1,292				939				(576		)		(2,360		)		(705		)
Net income	$	1,274			$	1,417			$	944			$	(2,361	)		$	1,274

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Condensed Consolidating Statement of Income
Year Ended December 31, 2017
(in millions)
	Parent Issuer				Guarantors				Non-Guarantors				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
Impairment expense and loss on disposal of assets	—				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 modification or 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

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Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2019
(in millions)
	Parent Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
Cash flows provided by operating activities	$	1,220			$	1,403			$	1,161			$	(2,237	)		$	1,547
Cash flows from investing activities
Property, plant and equipment, net	(2		)		(49		)		(1,282		)		2				(1,331		)
Investments in subsidiaries	(1,273		)		(1,046		)		—				2,319				—
Return of capital	853				626				—				(1,479		)		—
Other	—				—				(1		)		—				(1		)
Net cash used in investing activities	(422		)		(469		)		(1,283		)		842				(1,332		)
Cash flows from financing activities
Proceeds from issuances of debt	2,230				—				—				—				2,230
Repayments of debt	(730		)		—				—				—				(730		)
Debt issuance and deferred financing costs	(35		)		—				—				—				(35		)
Distributions to parent	—				(2,215		)		(1,499		)		3,714				—
Contributions from parent	—				1,273				1,046				(2,319		)		—
Distributions to owners	(1,260		)		—				—				—				(1,260		)
Other	(4		)		5				—				—				1
Net cash provided by (used in) financing activities	201				(937		)		(453		)		1,395				206
Net increase (decrease) in cash, cash equivalents and restricted cash	999				(3		)		(575		)		—				421
Cash, cash equivalents and restricted cash—beginning of period	779				6				756				—				1,541
Cash, cash equivalents and restricted cash—end of period	$	1,778			$	3			$	181			$	—			$	1,962

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2019
	Parent Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
Cash and cash equivalents	$	1,778			$	3			$	—			$	—			$	1,781
Restricted cash	—				—				181				—				181
Total cash, cash equivalents and restricted cash	$	1,778			$	3			$	181			$	—			$	1,962

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Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2018
(in millions)
	Parent Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
Cash flows provided by operating activities	$	714			$	569			$	1,423			$	(832	)		$	1,874
Cash flows from investing activities
Property, plant and equipment, net	—				(34		)		(771		)		1				(804		)
Investments in subsidiaries	(304		)		(129		)		—				433				—
Distributions received from affiliates, net	454				537				—				(991		)		—
Net cash provided by (used in) investing activities	150				374				(771		)		(557		)		(804		)
Cash flows from financing activities
Proceeds from issuances of debt	1,100				—				—				—				1,100
Repayments of debt	(1,090		)		—				—				—				(1,090		)
Debt issuance and deferred financing costs	(8		)		—				—				—				(8		)
Debt extinguishment costs	(7		)		—				—				—				(7		)
Distributions to parent	—				(1,253		)		(569		)		1,822				—
Contributions from parent	—				304				129				(433		)		—
Distributions to owners	(1,113		)		—				—				—				(1,113		)
Net cash used in financing activities	(1,118		)		(949		)		(440		)		1,389				(1,118		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(254		)		(6		)		212				—				(48		)
Cash, cash equivalents and restricted cash—beginning of period	1,033				12				544				—				1,589
Cash, cash equivalents and restricted cash—end of period	$	779			$	6			$	756			$	—			$	1,541

	December 31, 2018
	Parent Issuer				Guarantors				Non-Guarantors				Eliminations				Consolidated
Cash and cash equivalents	$	—			$	—			$	—			$	—			$	—
Restricted cash	779				6				756				—				1,541
Total cash, cash equivalents and restricted cash	$	779			$	6			$	756			$	—			$	1,541

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Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
(in millions)
	Parent Issuer				Guarantors				Non-Guarantors				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

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Summarized Quarterly Financial Data—(in millions, except per unit amounts)

		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Year ended December 31, 2019:
Revenues		$	1,749			$	1,705			$	1,476			$	1,908
Income from operations		563				455				346				676
Net income		385				232				110				448
Net income per common unit—basic and diluted (1)		0.75				0.44				0.19				0.87
Year ended December 31, 2018:
Revenues		$	1,593			$	1,407			$	1,529			$	1,897
Income from operations		508				455				492				524
Net income		335				281				307				351
Net income per common unit—basic and diluted (1)		0.67				0.55				0.60				0.69

(1)	The sum of the quarterly net income per common unit may not equal the full year amount as the undistributed income and loss allocations and computations of the weighted average common units outstanding for basic and diluted common units outstanding for each quarter and the full year are performed independently.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

ITEM 9B.	OTHER INFORMATION

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ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND CORPORATE GOVERNANCE

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(1)	Reflects aggregate grant date fair value. The phantom units are to be settled, at the director’s election, in common units, cash, or an equal amount of both. The units are valued using the closing unit price on the date of grant and are revalued on a quarterly basis through the date of vesting.

(2)

Mr. Fusco served as an executive officer of our general partner and as an executive officer of Cheniere during fiscal year 2019. Mr. Wortley served as an executive officer of our general partner and as an executive officer of Cheniere during fiscal year 2019. Mr. Bensaude served as an officer of Cheniere Marketing Ltd., a subsidiary of Cheniere during fiscal year 2019. Mr. Shanda served as an officer of our general partner and as an executive officer of Cheniere from January 1 until November 1, 2019. Mr. Stephenson has served as an officer of our general partner and as an executive officer of Cheniere since November 1, 2019. Cheniere compensates these officers for the performance of their duties as employees of Cheniere, which includes managing our partnership. They do not receive additional compensation for service as directors.

(3)	Mr. Meier is compensated by Blackstone CQP Holdco pursuant to the Meier Consulting Letter Agreement and received no additional compensation for service as a director. For a further description of the Meier Consulting Letter Agreement, see “Related-Party Transactions-Arrangements involving Mr. Meier and Meier Consulting LLC” below.

(4)	Mr. Munfa is a Managing Director in the Private Equity Group of Blackstone Group and Mr. Welch serves as Senior Advisor to Blackstone Group. They do not receive additional compensation for service as directors.

(5)	Mr. Ball was granted 3,000 phantom units in 2019 with a grant date fair value of $132,000. In addition, Mr. Ball received $49,500 in cash and 1,875 common units on account of 3,000 phantom units granted in earlier years that vested in 2019. As of December 31, 2019, he held 7,500 phantom units and 11,250 common units for a total of 18,750 units.

(6)	Mr. McCain was granted 3,000 phantom units in 2019 with a grant date fair value of $122,070. In addition, Mr. McCain received $61,035 in cash and 1,500 common units on account of 3,000 phantom units granted in earlier years that vested in 2019. As of December 31, 2019, he held 7,500 phantom units and 6,750 common units for a total of 14,250 units.

(7)	Mr. Pagano was granted 3,000 phantom units in 2019 with a grant date fair value of $117,360. In addition, Mr. Pagano received $58,680 in cash and 1,500 common units on account of 3,000 phantom units granted in earlier years that vested in 2019. As of December 31, 2019, he held 7,500 phantom units and 5,625 common units for a total of 13,125 units.

(8)	Mr. Richard was granted 3,000 phantom units in 2019 with a grant date fair value of $132,000. In addition, Mr. Richard received $33,000 in cash and 2,250 common units on account of 3,000 phantom units granted in earlier years that vested in 2019. As of December 31, 2019, he held 7,500 phantom units and 9,375 common units for a total of 16,875 units.

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ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED UNITHOLDER MATTERS

(1)	Cheniere Energy, Inc. also owns 9,877,546 of our general partner units.

(2)

Information is based on the Schedule 13D/A filed with the SEC on August 11, 2017 by the Blackstone Group, L.P., Blackstone CQP Common Holdco L.P., Blackstone CQP Common Holdco GP LLC, Blackstone Energy Management Associates L.L.C., Blackstone EMA L.L.C., Blackstone Management Associates VI L.L.C., BMA VI L.L.C., Blackstone Holdings III L.P., Blackstone Holdings III GP L.P., Blackstone Holdings III GP Management L.L.C., GSO Credit Alpha Fund AIV-2 LP, GSO Coastline Credit Partners LP, GSO Credit-A Partners LP, GSO Palmetto Opportunistic Investment Partners LP, GSO Special Situations Fund LP, GSO Special Situations Master Fund LP, GSO Special Situations Overseas Master Fund Ltd., Blackstone Holdings I L.P., Blackstone Holdings II L.P., Blackstone Holdings I/II GP Inc., GSO Capital Partners LP, GSO Advisor

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(1)	Includes 177,778 shares held by trust.

(2)	Messrs. Meier, Munfa and Welch were appointed as directors of our general partner pursuant to the rights of Blackstone CQP Holdco under the Third Amended and Restated Limited Liability Company Agreement of our general partner to appoint certain directors to the board of directors of our general partner.

(3)	Excludes shares owned by Mr. Shanda, who was no longer an executive officer of the Company on February 19, 2020.

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(1)	The phantom units that have been granted are payable, at the director’s election, in common units, in cash at the time of vesting in an amount equal to the fair market value of a common unit on such date or an equal amount of both.

(2)	The number of securities remaining available for issuance does not include securities reserved for issuance upon the vesting of unvested phantom units issued to directors for which such directors have made an irrevocable election to receive common units in lieu of cash.

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

•	whether the related party transaction is on terms no less favorable than the terms generally available to an unaffiliated third-party under the same or similar circumstances;

•	whether the transaction is material to the Company or the related party; and

•	the extent of the related person’s interest in the transaction.

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•	a director who is, or during the past three years was, employed by the partnership, general partner or by any parent or subsidiary of the partnership or general partner, other than prior employment as an interim executive officer (provided the interim employment did not last longer than one year);

•

a director who accepts, or has an immediate family member who accepts, any compensation from the partnership, general partner or any parent or subsidiary of the partnership or general partner in excess of $120,000 during any twelve consecutive-month period within the three years preceding the determination of independence, other than compensation for board or committee services, or compensation paid to an immediate family member who is a non-executive employee of the partnership, general partner or any parent or subsidiary of the partnership or general partner, among other exceptions;

•	a director who is an immediate family member of an individual who is, or at any time during the past three years was, employed by the partnership, general partner or any parent or subsidiary of the partnership or general partner as an executive officer;

•

a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive officer of, any organization to which the partnership, general partner or any parent or subsidiary of the partnership or general partner made, or from which the partnership, general partner or any parent or subsidiary of the partnership or general partner received, payments (other than those arising solely from investments in our common units or payments under non-discretionary charitable contribution matching programs) that exceed 5% of the organization’s consolidated gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years;

•	a director who is, or has an immediate family member who is, employed as an executive officer of another entity where at any time during the most recent three fiscal years any of the executive officers of the partnership, general partner or any parent or subsidiary of the partnership or general partner serves on the compensation committee of such other entity; or

•

a director who is, or has an immediate family member who is, a current partner of the outside auditor of the partnership, general partner or parent or subsidiary of the partnership or general partner, or was a partner or employee of the outside auditor of the partnership, general partner or any parent or subsidiary of the partnership or general partner who worked on our audit at any time during any of the past three years.

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ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES

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(a)	Financial Statements and Exhibits

(1)	Financial Statements—Cheniere Energy Partners, L.P.:

(2)	Financial Statement Schedules:

(3)	Exhibits:

•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•	may have been qualified by disclosures that were made to the other parties in connection with the    negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;

•	may apply standards of materiality that differ from those of a reasonable investor; and

•	were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.

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ITEM 16.	FORM 10-K SUMMARY

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