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Delaware
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20-5913059
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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700 Milam Street, Suite 1900
Houston, Texas
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77002
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(Address of principal executive offices)
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(Zip Code)
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Common Units Representing Limited Partner Interests
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NYSE American
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(Title of Class)
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(Name of each exchange on which registered)
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Large accelerated filer
x
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Accelerated filer
o
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Non-accelerated filer
o
(Do not check if a smaller reporting company)
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Smaller reporting company
o
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Emerging growth company
o
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Bcf
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billion cubic feet
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Bcf/d
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billion cubic feet per day
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Bcf/yr
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billion cubic feet per year
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Bcfe
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billion cubic feet equivalent
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DOE
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U.S. Department of Energy
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EPC
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engineering, procurement and construction
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FERC
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Federal Energy Regulatory Commission
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FTA countries
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countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
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GAAP
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generally accepted accounting principles in the United States
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Henry Hub
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the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
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LIBOR
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London Interbank Offered Rate
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LNG
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liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
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MMBtu
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million British thermal units, an energy unit
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mtpa
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million tonnes per annum
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non-FTA countries
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countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
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SEC
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U.S. Securities and Exchange Commission
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SPA
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LNG sale and purchase agreement
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TBtu
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trillion British thermal units, an energy unit
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Train
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an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
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TUA
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terminal use agreement
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•
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statements regarding our ability to pay distributions to our unitholders;
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•
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statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL;
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•
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statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all;
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•
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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;
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•
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statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
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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 such EPC or other contractor, and anticipated costs related thereto;
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•
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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;
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•
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statements regarding our planned development and construction of additional Trains, including the financing of such Trains;
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statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
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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;
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•
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statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
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statements regarding the Tax Cuts and Jobs Act; and
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any other statements that relate to non-historica
l or future information.
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ITEMS 1. AND 2.
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BUSINESS AND PROPERTIES
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achieving the date of first commercial delivery for our SPA customers;
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•
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safely, efficiently and reliably
maintaining and operating our assets, including our Trains;
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completing construction and commencing operation of Train 5 of the Liquefaction Project;
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making LNG available to our long-term SPA customers to generate steady and reliable revenues and operating cash flows;
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obtaining
the requisite long-term commercial contracts and financing to reach a final investment decision
(“FID”)
regarding Train 6 of the Liquefaction Project;
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further expanding and optimizing the Liquefaction Project by leveraging existing infrastructure; and
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•
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expanding our existing asset base through acquisitions from Cheniere or third parties or our own development of the Liquefaction Project or complementary businesses or assets such as other LNG facilities, midstream assets, natural gas storage assets and natural gas pipelines.
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Train 5
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Overall project completion percentage
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83.1%
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Completion percentage of:
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Engineering
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100%
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Procurement
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100%
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Subcontract work
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63.4%
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Construction
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62.1%
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Date of expected substantial completion
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1H 2019
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•
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Trains 1 through 4—
FTA countries
for a 30-year term, which commenced on May 15, 2016, and
non-FTA countries
for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16
mtpa
(approximately 803
Bcf/yr
of natural gas).
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•
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Trains 1 through 4—
FTA countries
for a 25-year term and non-FTA countries for a 20-year term in an amount up to a combined total of the equivalent of approximately 203
Bcf/yr
of natural gas (approximately 4 mtpa).
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•
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Trains 5 and 6—
FTA countries
and
non-FTA countries
for a 20-year term, in an amount up to a combined total of 503.3
Bcf/yr
of natural gas (approximately 10 mtpa).
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•
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approximately $720 million from
BG
, which is guaranteed by BG Energy Holdings Limited;
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•
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approximately $550 million from Korea Gas Corporation
(“KOGAS”)
;
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•
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approximately $550 million from GAIL (India) Limited; and
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•
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approximately $450 million from Gas Natural Fenosa LNG GOM, Limited
(“Gas Natural Fenosa”)
, which is guaranteed by Gas Natural SDG S.A.
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•
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rates and charges, and terms and conditions for natural gas transportation and related services;
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•
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the certification and construction of new facilities;
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•
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the extension and abandonment of services and facilities;
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the maintenance of accounts and records;
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the acquisition and disposition of facilities;
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the initiation and discontinuation of services; and
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various other matters.
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ITEM 1A.
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RISK FACTORS
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Risks Relating to Our Financial Matters;
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•
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Risks Relating to Our Business;
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Risks Relating to Our Cash Distributions;
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Risks Relating to an Investment in Us and Our Common Units; and
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Risks Relating to Tax Matters.
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expected supply is less than the amount hedged;
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the counterparty to the hedging contract defaults on its contractual obligations; or
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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;
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operational errors by vessel or tug operators;
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operational errors by us or any contracted facility operator;
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labor disputes; and
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weather-related interruptions of operations.
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design and engineer each Train to operate in accordance with specifications;
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engage and retain third-party subcontractors and procure equipment and supplies;
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respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
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attract, develop and retain skilled personnel, including engineers;
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post required construction bonds and comply with the terms thereof;
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manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
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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;
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competitive liquefaction capacity in North America;
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insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
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insufficient LNG tanker capacity;
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weather conditions;
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reduced demand and lower prices for natural gas;
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increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
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decreased oil and natural gas exploration activities, which may decrease the production of natural gas;
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cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;
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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;
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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;
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political conditions in natural gas producing regions;
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adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
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cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
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increased construction costs;
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economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
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decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;
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the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
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political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and
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any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
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•
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an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
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political or economic disturbances in the countries where the vessels are being constructed;
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changes in governmental regulations or maritime self-regulatory organizations;
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work stoppages or other labor disturbances at the shipyards;
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bankruptcy or other financial crisis of shipbuilders;
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quality or engineering problems;
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weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
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shortages of or delays in the receipt of necessary construction materials.
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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;
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increases in the cost to supply natural gas feedstock to the Liquefaction Project;
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decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
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decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
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increases in capacity and utilization of nuclear power and related facilities; and
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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;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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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;
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if we are unable to identify attractive capital expansion projects or negotiate acceptable engineering procurement and construction arrangements for them;
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if we are unable to obtain necessary governmental approvals;
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if we are unable to obtain financing for the acquisitions or capital expansion projects on economically acceptable terms, or at all;
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if we are unable to secure adequate customer commitments to use the acquired or expansion facilities; or
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if we are outbid by competitors.
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an inability to integrate successfully the businesses that we acquire with our existing business;
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a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the cash generated, or to be generated, by the business acquired or the overall costs of equity or debt;
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the diversion of management’s and employees’ attention from other business concerns; and
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unforeseen difficulties encountered in operating new business segments or in new geographic areas.
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performance by counterparties of their obligations under the SPAs;
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performance by SPL of its obligations under the SPAs;
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performance by counterparties of their obligations under the TUAs;
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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 VCRA
; and
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the level of our operating costs, including payments to our general partner and its affiliates.
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the restrictions contained in our debt agreements and our debt service requirements, including our ability to pay distributions under our
2016 CQP Credit Facilities
and the ability of SPL to pay distributions to us under its working capital facility and senior notes;
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the costs and capital requirements of acquisitions, if any;
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fluctuations in our working capital needs;
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our ability to borrow for working capital or other purposes; and
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the amount, if any, of cash reserves established by our general partner.
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make certain investments;
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purchase, redeem or retire equity interests;
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issue preferred stock;
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sell or transfer assets;
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incur liens;
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enter into transactions with affiliates;
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consolidate, merge, sell or lease all or substantially all of its assets; and
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enter into sale and leaseback transactions.
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•
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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:
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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;
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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;
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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;
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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”;
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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;
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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;
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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;
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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;
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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
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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;
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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;
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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;
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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
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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;
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the amount of cash available per unit to pay distributions may decrease;
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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;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of the common units may decline.
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our quarterly distributions;
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domestic and worldwide supply of and demand for natural gas and corresponding fluctuations in the price of natural gas;
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fluctuations in our quarterly or annual financial results or those of other companies in our industry;
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issuance of additional equity securities which causes further dilution to our unitholders;
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sales of a high volume of units of our common units by our unitholders;
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operating and unit price performance of companies that investors deem comparable to us;
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events affecting other companies that the market deems comparable to us;
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changes in government regulation or proposals applicable to us;
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actual or potential non-performance by any customer or a counterparty under any agreement;
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announcements made by us or our competitors of significant contracts;
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changes in accounting standards, policies, guidance, interpretations or principles;
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general conditions in the industries in which we operate;
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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
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other factors described in these “Risk Factors.”
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ITEM 1B.
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UNRESOLVED STAFF COMMENTS
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ITEM 4.
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MINE SAFETY DISCLOSURE
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ITEM 5.
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MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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High
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Low
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Cash Distributions Per Common Unit (1)
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Cash Distributions Per Subordinated Unit
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Cash Distributions
Per Class B Unit (2)
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||||||||||
2017
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||||||||||
First Quarter
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$
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33.33
|
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$
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27.92
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$
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0.425
|
|
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$
|
—
|
|
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$
|
—
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Second Quarter
|
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33.47
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29.91
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0.425
|
|
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—
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|
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—
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|||||
Third Quarter
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32.61
|
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26.41
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0.440
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0.440
|
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—
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|||||
Fourth Quarter (3)
|
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29.88
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26.68
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0.500
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0.500
|
|
|
—
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|||||
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||||||||||
2016
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|||||
First Quarter
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$
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30.78
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$
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19.22
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$
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0.425
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|
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$
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—
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$
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—
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Second Quarter
|
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31.49
|
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26.82
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0.425
|
|
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—
|
|
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—
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|||||
Third Quarter
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30.12
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25.87
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0.425
|
|
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—
|
|
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—
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|||||
Fourth Quarter
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29.87
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25.97
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0.425
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—
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—
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(1)
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We also paid cash distributions to our general partner, with respect to its 2% general partner interest.
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(2)
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Class B units were not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantially all of our assets).
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(3)
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We also paid cash distributions on the
IDR
s held by the general partner.
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•
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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;
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•
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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
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•
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there are no arrearages in payment of the initial quarterly distribution on the common units.
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•
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the subordination period will end and each subordinated unit will immediately convert into one common unit;
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•
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any existing arrearages in payment of the initial quarterly distribution on the common units will be extinguished; and
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•
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the general partner will have the right to convert its general partner units and its
IDR
s into common units or to receive cash in exchange for those interests.
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•
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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;
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•
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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
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•
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there are no arrearages in payment of the initial quarterly distribution on the common units
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•
|
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
|
•
|
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.
|
|
|
Total Quarterly Distribution
Target Amount
|
|
Marginal Percentage
Interest Distributions
|
||
|
|
Common and Subordinated Unitholders
|
|
General Partner
|
||
Initial quarterly distribution
|
|
$0.425
|
|
98%
|
|
2%
|
First Target Distribution
|
|
Above $0.425 up to $0.489
|
|
98%
|
|
2%
|
Second Target Distribution
|
|
Above $0.489 up to $0.531
|
|
85%
|
|
15%
|
Third Target Distribution
|
|
Above $0.531 up to $0.638
|
|
75%
|
|
25%
|
Thereafter
|
|
Above $0.638
|
|
50%
|
|
50%
|
ITEM 6.
|
SELECTED FINANCIAL DATA
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Revenues (including transactions with affiliates)
|
|
$
|
4,304
|
|
|
$
|
1,100
|
|
|
$
|
270
|
|
|
$
|
269
|
|
|
$
|
268
|
|
Income (loss) from operations
|
|
1,156
|
|
|
250
|
|
|
3
|
|
|
1
|
|
|
(32
|
)
|
|||||
Interest expense, net of capitalized interest
|
|
(614
|
)
|
|
(357
|
)
|
|
(185
|
)
|
|
(177
|
)
|
|
(178
|
)
|
|||||
Net income (loss)
|
|
490
|
|
|
(171
|
)
|
|
(319
|
)
|
|
(410
|
)
|
|
(258
|
)
|
|||||
Net loss per common unit
|
|
$
|
(1.32
|
)
|
|
$
|
(0.20
|
)
|
|
$
|
(0.43
|
)
|
|
$
|
(0.89
|
)
|
|
$
|
(0.03
|
)
|
Weighted average units outstanding
|
|
178.5
|
|
|
57.1
|
|
|
57.1
|
|
|
57.1
|
|
|
54.2
|
|
|
|
December 31,
|
||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Property, plant and equipment, net
|
|
$
|
15,139
|
|
|
$
|
14,158
|
|
|
$
|
11,932
|
|
|
$
|
8,978
|
|
|
$
|
6,384
|
|
Total assets
|
|
17,553
|
|
|
15,542
|
|
|
12,833
|
|
|
10,247
|
|
|
8,414
|
|
|||||
Current debt, net
|
|
—
|
|
|
224
|
|
|
1,673
|
|
|
—
|
|
|
—
|
|
|||||
Long-term debt, net
|
|
16,046
|
|
|
14,209
|
|
|
10,018
|
|
|
8,851
|
|
|
6,474
|
|
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
|
•
|
To date, approximately 300 cumulative LNG cargoes have been produced, loaded and exported from the
Liquefaction Project
, with over 200 cargoes in 2017 alone, with deliveries completed to 25 countries and regions worldwide.
|
•
|
SPL commenced production and shipment of LNG commissioning cargoes from Train 3 of the
Liquefaction Project
in January 2017 and achieved substantial completion and commenced operating activities in March 2017.
|
•
|
Commissioning activities for Train 4 of the
Liquefaction Project
began in March 2017, and substantial completion was achieved in October 2017.
|
•
|
In June 2017, the date of first commercial delivery was reached under the 20-year SPA with Korea Gas Corporation relating to Train 3 of the
Liquefaction Project
.
|
•
|
In August 2017, the date of first commercial delivery relating to Train 2 of the
Liquefaction Project
was reached under the respective 20-year SPAs with Gas Natural Fenosa LNG GOM, Limited and BG Gulf Coast LNG, LLC
(“BG”)
.
|
•
|
In February and March 2017, SPL issued aggregate principal amounts of
$800 million
of 5.00% Senior Secured Notes due 2037
(the “2037 SPL Senior Notes”)
and
$1.35 billion
, before discount, of 4.200% Senior Secured Notes due 2028
(the “2028 SPL Senior Notes”)
, respectively. Net proceeds of the offerings of the
2037 SPL Senior Notes
and
2028 SPL Senior Notes
were
$789 million
and
$1.33 billion
, respectively, after deducting the initial purchasers’ commissions (for the
2028 SPL Senior Notes
) and estimated fees and expenses. The net proceeds of the
2037 SPL Senior Notes
, after provisioning for incremental interest required during construction, were used to prepay the outstanding borrowings under the credit facilities SPL entered into in June 2015
(the “2015 SPL Credit Facilities”)
and, along with the net proceeds of the
2028 SPL Senior Notes
, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the
Liquefaction Project
in lieu of the terminated portion of the commitments under the
2015 SPL Credit Facilities
.
|
•
|
In September 2017, we issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025
(“the 2025 CQP Senior Notes”)
. Net proceeds of the offering of approximately $1.5 billion, after deducting commissions, fees and expenses, were used to prepay a portion of the outstanding indebtedness under our credit facilities
(the “2016 CQP Credit Facilities”)
.
|
•
|
Fitch Ratings (“Fitch”) assigned SPL’s senior secured debt an investment grade rating of BBB- in January 2017 and an investment-grade issuer default rating of BBB- in June 2017.
|
•
|
In May 2017, Moody’s Investors Service (“Moody’s”) upgraded SPL’s senior secured debt rating from Ba1 to Baa3, an investment-grade rating.
|
•
|
In September 2017, Moody’s, S&P Global Ratings and Fitch assigned ratings of Ba2 / BB / BB, respectively to the
2025 CQP Senior Notes
.
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash designated for the following purposes:
|
|
|
|
||||
Liquefaction Project
|
544
|
|
|
358
|
|
||
CQP and cash held by guarantor subsidiaries
|
1,045
|
|
|
247
|
|
||
Available commitments under the following credit facilities:
|
|
|
|
||||
2015 SPL Credit Facilities
|
—
|
|
|
1,642
|
|
||
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
|
470
|
|
|
653
|
|
||
2016 CQP Credit Facilities
|
220
|
|
|
195
|
|
|
Train 5
|
|
Overall project completion percentage
|
83.1%
|
|
Completion percentage of:
|
|
|
Engineering
|
100%
|
|
Procurement
|
100%
|
|
Subcontract work
|
63.4%
|
|
Construction
|
62.1%
|
|
Date of expected substantial completion
|
1H 2019
|
|
|
|
|
•
|
Trains 1 through 4—
FTA countries
for a 30-year term, which commenced on May 15, 2016, and
non-FTA countries
for a 20-year term, which commenced on June 3, 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 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, in an amount up to a combined total of 503.3
Bcf/yr
of natural gas (approximately 10 mtpa).
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Senior notes (1)
|
|
$
|
15,151
|
|
|
$
|
11,500
|
|
Credit facilities outstanding balance (2)
|
|
1,090
|
|
|
3,097
|
|
||
Letters of credit issued (3)
|
|
730
|
|
|
324
|
|
||
Available commitments under credit facilities (3)
|
|
470
|
|
|
2,295
|
|
||
Total capital resources from borrowings and available commitments
|
|
$
|
17,441
|
|
|
$
|
17,216
|
|
|
(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
(the “2025 SPL Senior Notes”)
, 5.875% Senior Secured Notes due 2026
(the “2026 SPL Senior Notes”)
, 5.00% Senior Secured Notes due 2027
(the “2027 SPL Senior Notes”)
,
2028 SPL Senior Notes
and
2037 SPL Senior Notes
(collectively, the “SPL Senior Notes”)
and our
2025 CQP Senior Notes
.
|
(2)
|
Includes
2015 SPL Credit Facilities
,
SPL Working Capital Facility
and CTPL and SPLNG tranche term loans outstanding under the
2016 CQP Credit Facilities
.
|
(3)
|
Includes
2015 SPL Credit Facilities
and
SPL Working Capital Facility
. Does not include the letters of credit issued or available commitments under the
2016 CQP Credit Facilities
, which are not specifically for the
Liquefaction Project
.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Operating cash flows
|
$
|
977
|
|
|
$
|
—
|
|
|
$
|
(171
|
)
|
Investing cash flows
|
(1,290
|
)
|
|
(2,353
|
)
|
|
(2,975
|
)
|
|||
Financing cash flows
|
1,297
|
|
|
2,524
|
|
|
2,591
|
|
|||
|
|
|
|
|
|
||||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
984
|
|
|
171
|
|
|
(555
|
)
|
|||
Cash, cash equivalents and restricted cash—beginning of period
|
605
|
|
|
434
|
|
|
989
|
|
|||
Cash, cash equivalents and restricted cash—end of period
|
$
|
1,589
|
|
|
$
|
605
|
|
|
$
|
434
|
|
•
|
issuances of aggregate principal amounts of
$800 million
of the
2037 SPL Senior Notes
and
$1.35 billion
of the
2028 SPL Senior Notes
;
|
•
|
$55 million of borrowings and $369 million of repayments made under the
2015 SPL Credit Facilities
;
|
•
|
$110 million of borrowings and $334 million of repayments made under the
SPL Working Capital Facility
;
|
•
|
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
;
|
•
|
$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.
|
•
|
$2.6 billion of borrowings under the
2016 CQP Credit Facilities
used to prepay the $400 million
CTPL Term Loan
and redeem and repay $2.1 billion of the
SPLNG Senior Notes
;
|
•
|
$2.0 billion of borrowings under the
2015 SPL Credit Facilities
;
|
•
|
issuance of an aggregate principal amount of $1.5 billion of the
2026 SPL Senior Notes
in June 2016, which was used to prepay $1.3 billion of the outstanding borrowings under the
2015 SPL Credit Facilities
;
|
•
|
issuance of an aggregate principal amount of $1.5 billion of the
2027 SPL Senior Notes
in September 2016, which was used to prepay $1.2 billion of the outstanding borrowings under the
2015 SPL Credit Facilities
and pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the
Liquefaction Project
;
|
•
|
$474 million of borrowings and $265 million of repayments made under the
SPL Working Capital Facility
;
|
•
|
$115 million
of debt issuance costs related to up-front fees paid upon the closing of these transactions;
|
•
|
$14 million
of debt extinguishment costs paid in connection with redemptions and prepayments of outstanding borrowings; and
|
•
|
$99 million
of distributions to unitholders.
|
•
|
$860 million of borrowings under the
2015 SPL Credit Facilities
;
|
•
|
issuance of an aggregate principal amount of $2.0 billion of the 2025 SPL Senior Notes in March 2015;
|
•
|
$170 million
of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions; and
|
•
|
$99 million
of distributions to unitholders.
|
|
|
Payments Due By Period (1)
|
||||||||||||||||||
|
|
Total
|
|
2018
|
|
2019 - 2020
|
|
2021 - 2022
|
|
Thereafter
|
||||||||||
Debt (2)
|
|
$
|
16,240
|
|
|
$
|
—
|
|
|
$
|
1,090
|
|
|
$
|
3,000
|
|
|
$
|
12,150
|
|
Interest payments (2)
|
|
5,963
|
|
|
887
|
|
|
1,742
|
|
|
1,386
|
|
|
1,948
|
|
|||||
Construction obligations (3)
|
|
372
|
|
|
293
|
|
|
79
|
|
|
—
|
|
|
—
|
|
|||||
Purchase obligations (4)
|
|
7,718
|
|
|
2,308
|
|
|
2,924
|
|
|
1,317
|
|
|
1,169
|
|
|||||
Operating lease obligations (5)
|
|
55
|
|
|
2
|
|
|
5
|
|
|
4
|
|
|
44
|
|
|||||
Obligations to affiliates (6)
|
|
802
|
|
|
45
|
|
|
90
|
|
|
90
|
|
|
577
|
|
|||||
Total
|
|
$
|
31,150
|
|
|
$
|
3,535
|
|
|
$
|
5,930
|
|
|
$
|
5,797
|
|
|
$
|
15,888
|
|
|
(1)
|
Agreements in force as of
December 31, 2017
that have terms dependent on project milestone dates are based on the estimated dates as of
December 31, 2017
.
|
(2)
|
Based on the total debt balance, scheduled maturities and interest rates in effect at
December 31, 2017
. See
Note 11—Debt
of our Notes to Consolidated Financial Statements.
|
(3)
|
Construction obligations relate to the EPC contract for Train 5 of the Liquefaction Project. The estimated remaining cost pursuant to our EPC contracts as of
December 31, 2017
is included. A discussion of these obligations can be found at
Note 15—Commitments and Contingencies
of our Notes to Consolidated Financial Statements.
|
(4)
|
Purchase obligations consist of contracts for which conditions precedent have been met, and primarily relate to natural gas supply, transportation and storage services for the Liquefaction Project. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly.
|
(5)
|
Operating lease obligations primarily relate to land sites related to the Sabine Pass LNG terminal. A discussion of these obligations can be found in
Note 14—Leases
of our Notes to Consolidated Financial Statements.
|
(6)
|
Obligations arising through intercompany service agreements include only fixed fees and do not include variable fees. A discussion of these obligations can be found in
Note 12—Related Party Transactions
of our Notes to Consolidated Financial Statements.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions, except volumes)
|
|
2017
|
|
2016
|
|
Change
|
|
2015
|
|
Change
|
||||||||||
LNG revenues
|
|
$
|
2,635
|
|
|
$
|
539
|
|
|
$
|
2,096
|
|
|
$
|
—
|
|
|
$
|
539
|
|
LNG revenues—affiliate
|
|
1,389
|
|
|
294
|
|
|
1,095
|
|
|
—
|
|
|
294
|
|
|||||
Regasification revenues
|
|
260
|
|
|
259
|
|
|
1
|
|
|
259
|
|
|
—
|
|
|||||
Other revenues
|
|
20
|
|
|
4
|
|
|
16
|
|
|
7
|
|
|
(3
|
)
|
|||||
Other revenues—affiliate
|
|
—
|
|
|
4
|
|
|
(4
|
)
|
|
4
|
|
|
—
|
|
|||||
Total revenues
|
|
$
|
4,304
|
|
|
$
|
1,100
|
|
|
$
|
3,204
|
|
|
$
|
270
|
|
|
$
|
830
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
LNG volumes recognized as revenues (in TBtu)
|
|
684
|
|
|
151
|
|
|
533
|
|
|
—
|
|
|
151
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions)
|
2017
|
|
2016
|
|
Change
|
|
2015
|
|
Change
|
||||||||||
Cost (cost recovery) of sales
|
$
|
2,320
|
|
|
$
|
410
|
|
|
$
|
1,910
|
|
|
$
|
(31
|
)
|
|
$
|
441
|
|
Cost of sales—affiliate
|
—
|
|
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
2
|
|
|||||
Operating and maintenance expense
|
292
|
|
|
127
|
|
|
165
|
|
|
62
|
|
|
65
|
|
|||||
Operating and maintenance expense—affiliate
|
100
|
|
|
52
|
|
|
48
|
|
|
29
|
|
|
23
|
|
|||||
Development expense
|
3
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|
(3
|
)
|
|||||
Development expense—affiliate
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(1
|
)
|
|||||
General and administrative expense
|
12
|
|
|
13
|
|
|
(1
|
)
|
|
15
|
|
|
(2
|
)
|
|||||
General and administrative expense—affiliate
|
80
|
|
|
90
|
|
|
(10
|
)
|
|
122
|
|
|
(32
|
)
|
|||||
Depreciation and amortization expense
|
339
|
|
|
156
|
|
|
183
|
|
|
66
|
|
|
90
|
|
|||||
Other
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|||||
Total operating costs and expenses
|
$
|
3,148
|
|
|
$
|
850
|
|
|
$
|
2,298
|
|
|
$
|
267
|
|
|
$
|
583
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions)
|
2017
|
|
2016
|
|
Change
|
|
2015
|
|
Change
|
||||||||||
Interest expense, net of capitalized interest
|
$
|
614
|
|
|
$
|
357
|
|
|
$
|
257
|
|
|
$
|
185
|
|
|
$
|
172
|
|
Loss on early extinguishment of debt
|
67
|
|
|
72
|
|
|
(5
|
)
|
|
96
|
|
|
(24
|
)
|
|||||
Derivative loss (gain), net
|
(4
|
)
|
|
(6
|
)
|
|
2
|
|
|
42
|
|
|
(48
|
)
|
|||||
Other income
|
(11
|
)
|
|
(2
|
)
|
|
(9
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|||||
Total other expense
|
$
|
666
|
|
|
$
|
421
|
|
|
$
|
245
|
|
|
$
|
322
|
|
|
$
|
99
|
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||
|
Fair Value
|
|
Change in Fair Value
|
|
Fair Value
|
|
Change in Fair Value
|
||||||||
Liquefaction Supply Derivatives
|
$
|
55
|
|
|
$
|
5
|
|
|
$
|
73
|
|
|
$
|
6
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||
|
Fair Value
|
|
Change in Fair Value
|
|
Fair Value
|
|
Change in Fair Value
|
||||||||
SPL Interest Rate Derivatives
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(6
|
)
|
|
$
|
2
|
|
CQP Interest Rate Derivatives
|
21
|
|
|
5
|
|
|
13
|
|
|
6
|
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
Cheniere Energy Partners, L.P.
|
|
|
|
By:
|
Cheniere Energy Partners GP, LLC,
|
|
Its general partner
|
By:
|
/s/ Jack A. Fusco
|
|
By:
|
/s/ Michael J. Wortley
|
|
Jack A. Fusco
|
|
|
Michael J. Wortley
|
|
President and Chief Executive Officer
(Principal Executive Officer) |
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial Officer) |
/s/ KPMG LLP
|
KPMG LLP
|
|
/s/ KPMG LLP
|
KPMG LLP
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash
|
|
1,589
|
|
|
605
|
|
||
Accounts and other receivables
|
|
191
|
|
|
90
|
|
||
Accounts receivable—affiliate
|
|
163
|
|
|
99
|
|
||
Advances to affiliate
|
|
36
|
|
|
38
|
|
||
Inventory
|
|
95
|
|
|
97
|
|
||
Other current assets
|
|
65
|
|
|
29
|
|
||
Total current assets
|
|
2,139
|
|
|
958
|
|
||
|
|
|
|
|
||||
Property, plant and equipment, net
|
|
15,139
|
|
|
14,158
|
|
||
Debt issuance costs, net
|
|
38
|
|
|
121
|
|
||
Non-current derivative assets
|
|
31
|
|
|
83
|
|
||
Other non-current assets, net
|
|
206
|
|
|
222
|
|
||
Total assets
|
|
$
|
17,553
|
|
|
$
|
15,542
|
|
|
|
|
|
|
||||
LIABILITIES AND PARTNERS’ EQUITY
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts payable
|
|
$
|
12
|
|
|
$
|
27
|
|
Accrued liabilities
|
|
637
|
|
|
418
|
|
||
Current debt
|
|
—
|
|
|
224
|
|
||
Due to affiliates
|
|
68
|
|
|
99
|
|
||
Deferred revenue
|
|
111
|
|
|
73
|
|
||
Deferred revenue—affiliate
|
|
1
|
|
|
1
|
|
||
Derivative liabilities
|
|
—
|
|
|
14
|
|
||
Total current liabilities
|
|
829
|
|
|
856
|
|
||
|
|
|
|
|
||||
Long-term debt, net
|
|
16,046
|
|
|
14,209
|
|
||
Non-current deferred revenue
|
|
1
|
|
|
5
|
|
||
Non-current derivative liabilities
|
|
3
|
|
|
2
|
|
||
Other non-current liabilities
|
|
10
|
|
|
—
|
|
||
Other non-current liabilities—affiliate
|
|
25
|
|
|
27
|
|
||
|
|
|
|
|
||||
Commitments and contingencies (see Note 15)
|
|
|
|
|
||||
|
|
|
|
|
||||
Partners’ equity
|
|
|
|
|
||||
Common unitholders’ interest (348.6 million units and 57.1 million units issued and outstanding at December 31, 2017 and 2016, respectively)
|
|
1,670
|
|
|
130
|
|
||
Class B unitholders’ interest (zero and 145.3 million units issued and outstanding at December 31, 2017 and 2016, respectively)
|
|
—
|
|
|
62
|
|
||
Subordinated unitholders’ interest (135.4 million units issued and outstanding at December 31, 2017 and 2016)
|
|
(1,043
|
)
|
|
240
|
|
||
General partner’s interest (2% interest with 9.9 million units and 6.9 million units issued and outstanding at December 31, 2017 and 2016, respectively)
|
|
12
|
|
|
11
|
|
||
Total partners’ equity
|
|
639
|
|
|
443
|
|
||
Total liabilities and partners’ equity
|
|
$
|
17,553
|
|
|
$
|
15,542
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues
|
|
|
|
|
|
||||||
LNG revenues
|
$
|
2,635
|
|
|
$
|
539
|
|
|
$
|
—
|
|
LNG revenues—affiliate
|
1,389
|
|
|
294
|
|
|
—
|
|
|||
Regasification revenues
|
260
|
|
|
259
|
|
|
259
|
|
|||
Other revenues
|
20
|
|
|
4
|
|
|
7
|
|
|||
Other revenues—affiliate
|
—
|
|
|
4
|
|
|
4
|
|
|||
Total revenues
|
4,304
|
|
|
1,100
|
|
|
270
|
|
|||
|
|
|
|
|
|
||||||
Operating costs and expenses
|
|
|
|
|
|
||||||
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)
|
2,320
|
|
|
410
|
|
|
(31
|
)
|
|||
Cost of sales—affiliate
|
—
|
|
|
2
|
|
|
—
|
|
|||
Operating and maintenance expense
|
292
|
|
|
127
|
|
|
62
|
|
|||
Operating and maintenance expense—affiliate
|
100
|
|
|
52
|
|
|
29
|
|
|||
Development expense
|
3
|
|
|
—
|
|
|
3
|
|
|||
Development expense—affiliate
|
—
|
|
|
—
|
|
|
1
|
|
|||
General and administrative expense
|
12
|
|
|
13
|
|
|
15
|
|
|||
General and administrative expense—affiliate
|
80
|
|
|
90
|
|
|
122
|
|
|||
Depreciation and amortization expense
|
339
|
|
|
156
|
|
|
66
|
|
|||
Other
|
2
|
|
|
—
|
|
|
—
|
|
|||
Total operating costs and expenses
|
3,148
|
|
|
850
|
|
|
267
|
|
|||
|
|
|
|
|
|
||||||
Income from operations
|
1,156
|
|
|
250
|
|
|
3
|
|
|||
|
|
|
|
|
|
||||||
Other income (expense)
|
|
|
|
|
|
||||||
Interest expense, net of capitalized interest
|
(614
|
)
|
|
(357
|
)
|
|
(185
|
)
|
|||
Loss on early extinguishment of debt
|
(67
|
)
|
|
(72
|
)
|
|
(96
|
)
|
|||
Derivative gain (loss), net
|
4
|
|
|
6
|
|
|
(42
|
)
|
|||
Other income
|
11
|
|
|
2
|
|
|
1
|
|
|||
Total other expense
|
(666
|
)
|
|
(421
|
)
|
|
(322
|
)
|
|||
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
490
|
|
|
$
|
(171
|
)
|
|
$
|
(319
|
)
|
|
|
|
|
|
|
||||||
Basic and diluted net loss per common unit
|
$
|
(1.32
|
)
|
|
$
|
(0.20
|
)
|
|
$
|
(0.43
|
)
|
|
|
|
|
|
|
||||||
Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation
|
178.5
|
|
|
57.1
|
|
|
57.1
|
|
|
Common Unitholders’ Interest
|
|
Class B Unitholders’ Interest
|
|
Subordinated Unitholder’s Interest
|
|
General Partner’s Interest
|
|
Total Partners’ Equity
|
||||||||||||||||||||||
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
|||||||||||||||
Balance at December 31, 2014
|
57.1
|
|
|
$
|
496
|
|
|
145.3
|
|
|
$
|
(38
|
)
|
|
135.4
|
|
|
$
|
648
|
|
|
6.9
|
|
|
$
|
25
|
|
|
$
|
1,131
|
|
Net loss
|
—
|
|
|
(93
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(220
|
)
|
|
—
|
|
|
(6
|
)
|
|
(319
|
)
|
|||||
Distributions
|
—
|
|
|
(97
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(99
|
)
|
|||||
Amortization of beneficial conversion feature of Class B units
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Balance at December 31, 2015
|
57.1
|
|
|
306
|
|
|
145.3
|
|
|
(37
|
)
|
|
135.4
|
|
|
427
|
|
|
6.9
|
|
|
17
|
|
|
713
|
|
|||||
Net loss
|
—
|
|
|
(50
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(117
|
)
|
|
—
|
|
|
(4
|
)
|
|
(171
|
)
|
|||||
Distributions
|
—
|
|
|
(97
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(99
|
)
|
|||||
Amortization of beneficial conversion feature of Class B units
|
—
|
|
|
(29
|
)
|
|
—
|
|
|
99
|
|
|
—
|
|
|
(70
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Balance at December 31, 2016
|
57.1
|
|
|
130
|
|
|
145.3
|
|
|
62
|
|
|
135.4
|
|
|
240
|
|
|
6.9
|
|
|
11
|
|
|
443
|
|
|||||
Net income
|
—
|
|
|
294
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
186
|
|
|
—
|
|
|
10
|
|
|
490
|
|
|||||
Distributions
|
—
|
|
|
(226
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(59
|
)
|
|
—
|
|
|
(9
|
)
|
|
(294
|
)
|
|||||
Conversion of Class B units into common units
|
291.5
|
|
|
2,066
|
|
|
(145.3
|
)
|
|
(2,066
|
)
|
|
—
|
|
|
—
|
|
|
3.0
|
|
|
—
|
|
|
—
|
|
|||||
Amortization of beneficial conversion feature of Class B units
|
—
|
|
|
(594
|
)
|
|
—
|
|
|
2,004
|
|
|
—
|
|
|
(1,410
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Balance at December 31, 2017
|
348.6
|
|
|
$
|
1,670
|
|
|
—
|
|
|
$
|
—
|
|
|
135.4
|
|
|
$
|
(1,043
|
)
|
|
9.9
|
|
|
$
|
12
|
|
|
$
|
639
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
490
|
|
|
$
|
(171
|
)
|
|
$
|
(319
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
||||||
Non-cash LNG inventory write-downs
|
—
|
|
|
—
|
|
|
18
|
|
|||
Depreciation and amortization expense
|
339
|
|
|
156
|
|
|
66
|
|
|||
Amortization of debt issuance costs, deferred commitment fees, premium and discount
|
36
|
|
|
30
|
|
|
12
|
|
|||
Loss on early extinguishment of debt
|
67
|
|
|
72
|
|
|
96
|
|
|||
Total losses (gains) on derivatives, net
|
20
|
|
|
(48
|
)
|
|
7
|
|
|||
Net cash used for settlement of derivative instruments
|
(16
|
)
|
|
(8
|
)
|
|
(41
|
)
|
|||
Other
|
8
|
|
|
1
|
|
|
—
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
Accounts and other receivables
|
(101
|
)
|
|
(90
|
)
|
|
—
|
|
|||
Accounts receivable—affiliate
|
(62
|
)
|
|
(98
|
)
|
|
1
|
|
|||
Advances to affiliate
|
(12
|
)
|
|
—
|
|
|
(13
|
)
|
|||
Inventory
|
13
|
|
|
(58
|
)
|
|
(25
|
)
|
|||
Accounts payable and accrued liabilities
|
210
|
|
|
167
|
|
|
(1
|
)
|
|||
Due to affiliates
|
(42
|
)
|
|
11
|
|
|
15
|
|
|||
Deferred revenue
|
34
|
|
|
42
|
|
|
(4
|
)
|
|||
Other, net
|
(5
|
)
|
|
(7
|
)
|
|
(11
|
)
|
|||
Other, net—affiliate
|
(2
|
)
|
|
1
|
|
|
28
|
|
|||
Net cash provided by (used in) operating activities
|
977
|
|
|
—
|
|
|
(171
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities
|
|
|
|
|
|
|
|
||||
Property, plant and equipment, net
|
(1,290
|
)
|
|
(2,315
|
)
|
|
(2,913
|
)
|
|||
Other
|
—
|
|
|
(38
|
)
|
|
(62
|
)
|
|||
Net cash used in investing activities
|
(1,290
|
)
|
|
(2,353
|
)
|
|
(2,975
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities
|
|
|
|
|
|
|
|
||||
Proceeds from issuances of debt
|
3,814
|
|
|
8,003
|
|
|
2,860
|
|
|||
Repayments of debt
|
(2,173
|
)
|
|
(5,251
|
)
|
|
—
|
|
|||
Debt issuance and deferred financing costs
|
(50
|
)
|
|
(115
|
)
|
|
(170
|
)
|
|||
Debt extinguishment costs
|
—
|
|
|
(14
|
)
|
|
—
|
|
|||
Distributions to owners
|
(294
|
)
|
|
(99
|
)
|
|
(99
|
)
|
|||
Net cash provided by financing activities
|
1,297
|
|
|
2,524
|
|
|
2,591
|
|
|||
|
|
|
|
|
|
||||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
984
|
|
|
171
|
|
|
(555
|
)
|
|||
Cash, cash equivalents and restricted cash—beginning of period
|
605
|
|
|
434
|
|
|
989
|
|
|||
Cash, cash equivalents and restricted cash—end of period
|
$
|
1,589
|
|
|
$
|
605
|
|
|
$
|
434
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash
|
1,589
|
|
|
605
|
|
||
Total cash, cash equivalents and restricted cash
|
$
|
1,589
|
|
|
$
|
605
|
|
•
|
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.
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Current restricted cash
|
|
|
|
|
||||
Liquefaction Project
|
|
$
|
544
|
|
|
$
|
358
|
|
CQP and cash held by guarantor subsidiaries
|
|
1,045
|
|
|
247
|
|
||
Total current restricted cash
|
|
$
|
1,589
|
|
|
$
|
605
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
SPL trade receivable
|
|
$
|
185
|
|
|
$
|
88
|
|
Other accounts receivable
|
|
6
|
|
|
2
|
|
||
Total accounts and other receivables
|
|
$
|
191
|
|
|
$
|
90
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Natural gas
|
|
$
|
17
|
|
|
$
|
15
|
|
LNG
|
|
26
|
|
|
45
|
|
||
Materials and other
|
|
52
|
|
|
37
|
|
||
Total inventory
|
|
$
|
95
|
|
|
$
|
97
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
LNG terminal costs
|
|
|
|
|
||||
LNG terminal
|
|
$
|
12,703
|
|
|
$
|
7,976
|
|
LNG terminal construction-in-process
|
|
3,310
|
|
|
6,728
|
|
||
Accumulated depreciation
|
|
(880
|
)
|
|
(553
|
)
|
||
Total LNG terminal costs, net
|
|
15,133
|
|
|
14,151
|
|
||
Fixed assets
|
|
|
|
|
|
|
||
Fixed assets
|
|
23
|
|
|
20
|
|
||
Accumulated depreciation
|
|
(17
|
)
|
|
(13
|
)
|
||
Total fixed assets, net
|
|
6
|
|
|
7
|
|
||
Property, plant and equipment, net
|
|
$
|
15,139
|
|
|
$
|
14,158
|
|
Components
|
|
Useful life (yrs)
|
LNG storage tanks
|
|
50
|
Natural gas pipeline facilities
|
|
40
|
Marine berth, electrical, facility and roads
|
|
35
|
Regasification processing equipment
|
|
30
|
Sendout pumps
|
|
20
|
Liquefaction processing equipment
|
|
6-50
|
Other
|
|
15-30
|
•
|
interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under certain credit facilities
(“Interest Rate Derivatives”)
and
|
•
|
commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the
Liquefaction Project
(“Physical Liquefaction Supply Derivatives”)
and associated economic hedges
(“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”)
.
|
|
Fair Value Measurements as of
|
||||||||||||||||||||||||||||||
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||||||||||
|
Quoted Prices in Active Markets
(Level 1)
|
|
Significant Other Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
|
Total
|
|
Quoted Prices in Active Markets
(Level 1)
|
|
Significant Other Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
|
Total
|
||||||||||||||||
SPL Interest Rate Derivatives liability
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
(6
|
)
|
CQP Interest Rate Derivatives asset
|
—
|
|
|
21
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
13
|
|
|
—
|
|
|
13
|
|
||||||||
Liquefaction Supply Derivatives asset (liability)
|
2
|
|
|
10
|
|
|
43
|
|
|
55
|
|
|
(4
|
)
|
|
(2
|
)
|
|
79
|
|
|
73
|
|
|
|
Net Fair Value Asset
(in millions)
|
|
Valuation Approach
|
|
Significant Unobservable Input
|
|
Significant Unobservable Inputs Range
|
Physical Liquefaction Supply Derivatives
|
|
$43
|
|
Market approach incorporating present value techniques
|
|
Basis Spread
|
|
$(0.503) - $0.432
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Balance, beginning of period
|
|
$
|
79
|
|
|
$
|
32
|
|
|
$
|
—
|
|
Realized and mark-to-market gains (losses):
|
|
|
|
|
|
|
||||||
Included in cost of sales (1)
|
|
(37
|
)
|
|
48
|
|
|
32
|
|
|||
Purchases and settlements:
|
|
|
|
|
|
|
||||||
Purchases
|
|
14
|
|
|
1
|
|
|
—
|
|
|||
Settlements (1)
|
|
(12
|
)
|
|
(2
|
)
|
|
—
|
|
|||
Transfers out of Level 3
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Balance, end of period
|
|
$
|
43
|
|
|
$
|
79
|
|
|
$
|
32
|
|
Change in unrealized gains relating to instruments still held at end of period
|
|
$
|
(37
|
)
|
|
$
|
49
|
|
|
$
|
32
|
|
|
(1)
|
Does not include the decrease in fair value of
$1 million
related to the realized gains capitalized during the
year ended December 31, 2016
.
|
|
|
Initial Notional Amount
|
|
Maximum Notional Amount
|
|
Effective Date
|
|
Maturity Date
|
|
Weighted Average Fixed Interest Rate Paid
|
|
Variable Interest Rate Received
|
CQP Interest Rate Derivatives
|
|
$225 million
|
|
$1.3 billion
|
|
March 22, 2016
|
|
February 29, 2020
|
|
1.19%
|
|
One-month LIBOR
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||
|
|
SPL Interest Rate Derivatives
|
|
CQP Interest Rate Derivatives
|
|
Total
|
|
SPL Interest Rate Derivatives
|
|
CQP Interest Rate Derivatives
|
|
Total
|
||||||||||||
Balance Sheet Location
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other current assets
|
|
$
|
—
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Non-current derivative assets
|
|
—
|
|
|
14
|
|
|
14
|
|
|
—
|
|
|
16
|
|
|
16
|
|
||||||
Total derivative assets
|
|
—
|
|
|
21
|
|
|
21
|
|
|
—
|
|
|
16
|
|
|
16
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(3
|
)
|
|
(7
|
)
|
||||||
Non-current derivative liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
||||||
Total derivative liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(3
|
)
|
|
(9
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative asset (liability), net
|
|
$
|
—
|
|
|
$
|
21
|
|
|
$
|
21
|
|
|
$
|
(6
|
)
|
|
$
|
13
|
|
|
$
|
7
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
SPL Interest Rate Derivatives loss
|
|
$
|
(2
|
)
|
|
$
|
(6
|
)
|
|
$
|
(42
|
)
|
CQP Interest Rate Derivatives gain
|
|
6
|
|
|
12
|
|
|
—
|
|
|
|
|
Fair Value Measurements as of (1)
|
||||||
|
Balance Sheet Location
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
Liquefaction Supply Derivatives
|
Other current assets
|
|
$
|
41
|
|
|
$
|
13
|
|
Liquefaction Supply Derivatives
|
Non-current derivative assets
|
|
17
|
|
|
67
|
|
||
Liquefaction Supply Derivatives
|
Derivative liabilities
|
|
—
|
|
|
(7
|
)
|
||
Liquefaction Supply Derivatives
|
Non-current derivative liabilities
|
|
(3
|
)
|
|
—
|
|
|
(1)
|
Does not include a collateral call of
$1 million
and a collateral deposit of
$6 million
for such contracts, which are included in
other current assets
in our Consolidated Balance Sheets as of
December 31, 2017
and
2016
, respectively.
|
|
|
|
Year Ended December 31,
|
|||||||||
|
Statement of Operations Location (1)
|
|
2017
|
|
2016
|
|
2015
|
|||||
Liquefaction Supply Derivatives loss (gain) (2)
|
Cost of sales
|
|
$
|
24
|
|
|
$
|
(42
|
)
|
|
(33
|
)
|
|
(1)
|
Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
|
(2)
|
Does not include the realized value associated with derivative instruments that settle through physical delivery.
|
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
||||||
Offsetting Derivative Assets (Liabilities)
|
|
|
|
|||||||||
As of December 31, 2017
|
|
|
|
|
|
|
||||||
CQP Interest Rate Derivatives
|
|
$
|
21
|
|
|
$
|
—
|
|
|
$
|
21
|
|
Liquefaction Supply Derivatives
|
|
64
|
|
|
(6
|
)
|
|
58
|
|
|||
Liquefaction Supply Derivatives
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|||
As of December 31, 2016
|
|
|
|
|
|
|
||||||
SPL Interest Rate Derivatives
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
(6
|
)
|
CQP Interest Rate Derivatives
|
|
16
|
|
|
—
|
|
|
16
|
|
|||
CQP Interest Rate Derivatives
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|||
Liquefaction Supply Derivatives
|
|
82
|
|
|
(2
|
)
|
|
80
|
|
|||
Liquefaction Supply Derivatives
|
|
(11
|
)
|
|
4
|
|
|
(7
|
)
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Advances made under EPC and non-EPC contracts
|
|
$
|
26
|
|
|
$
|
23
|
|
Advances made to municipalities for water system enhancements
|
|
93
|
|
|
95
|
|
||
Advances and other asset conveyances to third parties to support LNG terminals
|
|
30
|
|
|
31
|
|
||
Tax-related payments and receivables
|
|
25
|
|
|
28
|
|
||
Information technology service assets
|
|
24
|
|
|
27
|
|
||
Other
|
|
8
|
|
|
18
|
|
||
Total other non-current assets, net
|
|
$
|
206
|
|
|
$
|
222
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Interest costs and related debt fees
|
|
$
|
253
|
|
|
$
|
205
|
|
Sabine Pass LNG terminal and related pipeline costs
|
|
384
|
|
|
211
|
|
||
Other accrued liabilities
|
|
—
|
|
|
2
|
|
||
Total accrued liabilities
|
|
$
|
637
|
|
|
$
|
418
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Long-term debt:
|
|
|
|
|
||||
SPL
|
|
|
|
|
||||
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7
|
|
$
|
2,006
|
|
|
$
|
2,007
|
|
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)
|
|
1,000
|
|
|
1,000
|
|
||
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $6
|
|
1,505
|
|
|
1,506
|
|
||
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)
|
|
2,000
|
|
|
2,000
|
|
||
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)
|
|
2,000
|
|
|
2,000
|
|
||
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero
|
|
1,349
|
|
|
—
|
|
||
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)
|
|
800
|
|
|
—
|
|
||
2015 SPL Credit Facilities
|
|
—
|
|
|
314
|
|
||
Cheniere Partners
|
|
|
|
|
||||
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)
|
|
1,500
|
|
|
—
|
|
||
2016 CQP Credit Facilities
|
|
1,090
|
|
|
2,560
|
|
||
Unamortized debt issuance costs
|
|
(204
|
)
|
|
(178
|
)
|
||
Total long-term debt, net
|
|
16,046
|
|
|
14,209
|
|
||
|
|
|
|
|
||||
Current debt:
|
|
|
|
|
||||
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
|
|
—
|
|
|
224
|
|
||
|
|
|
|
|
||||
Total debt, net
|
|
$
|
16,046
|
|
|
$
|
14,433
|
|
Years Ending December 31,
|
|
Principal Payments
|
||
2018
|
|
$
|
—
|
|
2019
|
|
55
|
|
|
2020
|
|
1,035
|
|
|
2021
|
|
2,000
|
|
|
2022
|
|
1,000
|
|
|
Thereafter
|
|
12,150
|
|
|
Total
|
|
$
|
16,240
|
|
|
|
SPL Working Capital Facility
|
|
2016 CQP Credit Facilities
|
||||
Original facility size
|
|
$
|
1,200
|
|
|
$
|
2,800
|
|
Less:
|
|
|
|
|
||||
Outstanding balance
|
|
—
|
|
|
1,090
|
|
||
Commitments prepaid or terminated
|
|
—
|
|
|
1,470
|
|
||
Letters of credit issued
|
|
730
|
|
|
20
|
|
||
Available commitment
|
|
$
|
470
|
|
|
$
|
220
|
|
|
|
|
|
|
||||
Interest rate
|
|
LIBOR plus 1.75% or base rate plus 0.75%
|
|
LIBOR plus 2.25% or base rate plus 1.25% (1)
|
||||
Maturity date
|
|
December 31, 2020, with various terms for underlying loans
|
|
February 25, 2020, with principal payments due quarterly commencing on March 31, 2019
|
|
(1)
|
There is a
0.50%
step-up for both LIBOR and base rate loans beginning on February 25, 2019.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Total interest cost
|
|
$
|
902
|
|
|
$
|
841
|
|
|
$
|
708
|
|
Capitalized interest
|
|
(288
|
)
|
|
(484
|
)
|
|
(523
|
)
|
|||
Total interest expense, net
|
|
$
|
614
|
|
|
$
|
357
|
|
|
$
|
185
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
||||||||
Senior notes, net of premium or discount (1)
|
|
$
|
14,360
|
|
|
$
|
15,485
|
|
|
$
|
11,513
|
|
|
$
|
12,309
|
|
2037 SPL Senior Notes (2)
|
|
800
|
|
|
871
|
|
|
—
|
|
|
—
|
|
||||
Credit facilities (3)
|
|
1,090
|
|
|
1,090
|
|
|
3,098
|
|
|
3,098
|
|
|
(1)
|
Includes
2021 SPL Senior Notes
,
2022 SPL Senior Notes
,
2023 SPL Senior Notes
,
2024 SPL Senior Notes
,
2025 SPL Senior Notes
,
2026 SPL Senior Notes
,
2027 SPL Senior Notes
,
2028 SPL Senior Notes
and
2025 CQP Senior Notes
. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
|
(2)
|
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
|
(3)
|
Includes
2015 SPL Credit Facilities
,
SPL Working Capital Facility
and
2016 CQP Credit Facilities
. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
|
|
Year Ended December 31,
|
|||||||||||
|
2017
|
|
2016
|
|
2015
|
|||||||
LNG revenues—affiliate
|
||||||||||||
Cheniere Marketing SPA and Cheniere Marketing Master SPA
|
$
|
1,389
|
|
|
$
|
294
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|||||||
Other revenues—affiliate
|
||||||||||||
Contracts for Sale and Purchase of Natural Gas and LNG
|
—
|
|
|
1
|
|
|
1
|
|
||||
Terminal Marine Services Agreement
|
—
|
|
|
3
|
|
|
3
|
|
||||
Total other revenues—affiliate
|
—
|
|
|
4
|
|
|
4
|
|
||||
|
|
|
||||||||||
Cost of sales—affiliate
|
||||||||||||
Fees under the Pre-commercial LNG Marketing Agreement
|
—
|
|
|
2
|
|
|
—
|
|
||||
|
|
|
|
|
|
|||||||
Operating and maintenance expense—affiliate
|
||||||||||||
Contracts for Sale and Purchase of Natural Gas and LNG
|
—
|
|
|
1
|
|
|
1
|
|
||||
Services Agreements
|
94
|
|
|
51
|
|
|
28
|
|
||||
Other agreements
|
6
|
|
|
—
|
|
|
—
|
|
||||
Total operating and maintenance expense—affiliate
|
100
|
|
|
52
|
|
|
29
|
|
||||
|
|
|
||||||||||
Development expense—affiliate
|
||||||||||||
Services Agreements
|
—
|
|
|
—
|
|
|
1
|
|
||||
|
|
|
||||||||||
General and administrative expense—affiliate
|
||||||||||||
Services Agreements
|
80
|
|
|
90
|
|
|
122
|
|
|
|
|
|
Limited Partner Units
|
|
|
|
|
||||||||||||||||
|
|
Total
|
|
Common Units
|
|
Class B Units
|
|
Subordinated Units
|
|
General Partner Units
|
|
IDR
|
||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income
|
|
$
|
490
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Declared distributions
|
|
514
|
|
|
376
|
|
|
—
|
|
|
127
|
|
|
10
|
|
|
1
|
|
||||||
Amortization of beneficial conversion feature of Class B units
|
|
—
|
|
|
(594
|
)
|
|
2,004
|
|
|
(1,410
|
)
|
|
—
|
|
|
—
|
|
||||||
Assumed allocation of undistributed net loss (1)
|
|
$
|
(24
|
)
|
|
(17
|
)
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|||||
Assumed allocation of net income
|
|
|
|
$
|
(235
|
)
|
|
$
|
2,004
|
|
|
$
|
(1,290
|
)
|
|
$
|
10
|
|
|
$
|
1
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Weighted average units outstanding
|
|
|
|
178.5
|
|
|
84.8
|
|
|
135.4
|
|
|
|
|
|
|||||||||
Net loss per unit (2)
|
|
|
|
$
|
(1.32
|
)
|
|
|
|
|
$
|
(9.52
|
)
|
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net loss
|
|
$
|
(171
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Declared distributions
|
|
99
|
|
|
97
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||||
Amortization of beneficial conversion feature of Class B units
|
|
—
|
|
|
(29
|
)
|
|
100
|
|
|
(71
|
)
|
|
—
|
|
|
—
|
|
||||||
Assumed allocation of undistributed net loss
|
|
$
|
(270
|
)
|
|
(79
|
)
|
|
—
|
|
|
(186
|
)
|
|
(5
|
)
|
|
—
|
|
|||||
Assumed allocation of net loss
|
|
|
|
$
|
(11
|
)
|
|
$
|
100
|
|
|
$
|
(257
|
)
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Weighted average units outstanding
|
|
|
|
57.1
|
|
|
145.3
|
|
|
135.4
|
|
|
|
|
|
|||||||||
Net loss per unit (2)
|
|
|
|
$
|
(0.20
|
)
|
|
|
|
|
$
|
(1.90
|
)
|
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net loss
|
|
$
|
(319
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Declared distributions
|
|
99
|
|
|
97
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||||
Assumed allocation of undistributed net loss
|
|
$
|
(418
|
)
|
|
(121
|
)
|
|
—
|
|
|
(288
|
)
|
|
(8
|
)
|
|
—
|
|
|||||
Assumed allocation of net loss
|
|
|
|
$
|
(24
|
)
|
|
$
|
—
|
|
|
$
|
(288
|
)
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Weighted average units outstanding
|
|
|
|
57.1
|
|
|
145.3
|
|
|
135.4
|
|
|
|
|
|
|||||||||
Net loss per unit (2)
|
|
|
|
$
|
(0.43
|
)
|
|
|
|
|
$
|
(2.13
|
)
|
|
|
|
|
|
(1)
|
Under our partnership agreement, the
IDR
s participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the
IDR
s from participating in undistributed net income (loss).
|
(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.
|
Years Ending December 31,
|
Operating Leases (1)
|
||
2018
|
$
|
2
|
|
2019
|
2
|
|
|
2020
|
2
|
|
|
2021
|
2
|
|
|
2022
|
2
|
|
|
Thereafter
|
45
|
|
|
Total
|
$
|
55
|
|
|
(1)
|
Includes certain lease option renewals that are reasonably assured
.
|
Years Ending December 31,
|
Payments Due (1)
|
||
2018
|
$
|
2,274
|
|
2019
|
1,527
|
|
|
2020
|
1,397
|
|
|
2021
|
981
|
|
|
2022
|
336
|
|
|
Thereafter
|
1,169
|
|
|
Total
|
$
|
7,684
|
|
|
(1)
|
Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread
.
Amounts included are based on prices and basis spreads as of
December 31, 2017
.
|
|
|
Percentage of Total Third-Party Revenues
|
|
Percentage of Accounts Receivable from Third Parties
|
||||||
|
|
Year Ended December 31,
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
Customer A
|
|
39%
|
|
52%
|
|
—%
|
|
39%
|
|
47%
|
Customer B
|
|
27%
|
|
*
|
|
—%
|
|
32%
|
|
50%
|
Customer C
|
|
23%
|
|
—%
|
|
—%
|
|
26%
|
|
—%
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Cash paid during the period for interest, net of amounts capitalized
|
$
|
510
|
|
|
$
|
242
|
|
|
$
|
136
|
|
Non-cash conveyance of assets
|
—
|
|
|
—
|
|
|
13
|
|
Standard
|
|
Description
|
|
Expected Date of Adoption
|
|
Effect on our Consolidated Financial Statements or Other Significant Matters
|
ASU 2014-09,
Revenue from Contracts with Customers (Topic 606)
, and subsequent amendments thereto
|
|
This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).
|
|
January 1, 2018
|
|
We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard.
|
ASU 2016-02,
Leases (Topic 842)
, and subsequent amendments thereto
|
|
This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.
|
|
January 1, 2019
|
|
We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
|
ASU 2016-16,
Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
|
|
This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.
|
|
January 1, 2018
|
|
We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
|
Standard
|
|
Description
|
|
Date of Adoption
|
|
Effect on our Consolidated Financial Statements or Other Significant Matters
|
ASU 2015-11,
Inventory (Topic 330): Simplifying the Measurement of Inventory
|
|
This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.
|
|
January 1, 2017
|
|
The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
Year ended December 31, 2017:
|
|
|
|
|
|
|
|
|
||||||||
Revenues
|
|
$
|
891
|
|
|
$
|
992
|
|
|
$
|
903
|
|
|
$
|
1,518
|
|
Income from operations
|
|
219
|
|
|
200
|
|
|
197
|
|
|
540
|
|
||||
Net income
|
|
47
|
|
|
46
|
|
|
23
|
|
|
374
|
|
||||
Net income (loss) per common unit—basic and diluted (1)
|
|
(0.80
|
)
|
|
(3.71
|
)
|
|
(1.10
|
)
|
|
0.76
|
|
||||
Year ended December 31, 2016:
|
|
|
|
|
|
|
|
|
||||||||
Revenues
|
|
$
|
67
|
|
|
$
|
151
|
|
|
$
|
331
|
|
|
$
|
551
|
|
Income (loss) from operations
|
|
(10
|
)
|
|
13
|
|
|
48
|
|
|
199
|
|
||||
Net income (loss)
|
|
(75
|
)
|
|
(100
|
)
|
|
(82
|
)
|
|
86
|
|
||||
Net income (loss) per common unit—basic and diluted (1)
|
|
(0.08
|
)
|
|
(0.21
|
)
|
|
(0.27
|
)
|
|
0.07
|
|
|
|
|
|
|
(1)
|
The sum of the quarterly net income (loss) per common unit may not equal the full year amount as the undistributed income and loss allocations and computations of the weighted average common units outstanding for basic and diluted common units outstanding for each quarter and the full year are performed independently.
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
ITEM 9A.
|
CONTROLS AND PROCEDURES
|
ITEM 9B.
|
OTHER INFORMATION
|
ITEM 10.
|
DIRECTORS, EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND CORPORATE GOVERNANCE
|
Name
|
|
Age
|
|
Election Date
|
|
Position with Our General Partner
|
Jack A. Fusco
|
|
55
|
|
May 2016
|
|
Chairman of the Board and President and Chief Executive Officer
|
Michael J. Wortley
|
|
41
|
|
January 2014
|
|
Director and Executive Vice President and Chief Financial Officer
|
Eric Bensaude
|
|
51
|
|
September 2016
|
|
Director and Senior Vice President, Commercial Operations
|
Doug Shanda
|
|
48
|
|
September 2016
|
|
Director and Senior Vice President, Operations
|
Philip Meier
|
|
59
|
|
July 2013
|
|
Director
|
John-Paul Munfa
|
|
36
|
|
February 2015
|
|
Director
|
Jamie Welch
|
|
51
|
|
August 2017
|
|
Director
|
James R. Ball
|
|
67
|
|
December 2012
|
|
Director
|
Lon McCain
|
|
70
|
|
March 2007
|
|
Director
|
Vincent Pagano, Jr.
|
|
67
|
|
December 2012
|
|
Director
|
Oliver G. Richard, III
|
|
65
|
|
September 2012
|
|
Director
|
Name
|
|
Fees
Earned
or Paid
in Cash
|
|
Unit
Awards (1)
|
|
Option
Awards
|
|
Non-Equity
Incentive Plan
Compensation
|
|
Change in Pension Value and Nonqualified Deferred Compensation Earnings
|
|
All Other
Compensation
|
|
Total
|
||||||||||||||
Jack A. Fusco (2)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Michael J. Wortley (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Eric Bensaude (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Doug Shanda (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Philip Meier (3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
John-Paul Munfa (4)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Sean T. Klimczak
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Jamie Welch (4)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
James R. Ball (5)
|
|
117,500
|
|
|
82,770
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
200,270
|
|
|||||||
Lon McCain (6)
|
|
107,500
|
|
|
98,760
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
206,260
|
|
|||||||
Vincent Pagano, Jr. (7)
|
|
102,500
|
|
|
82,680
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
185,180
|
|
|||||||
Oliver G. Richard, III (8)
|
|
92,500
|
|
|
82,770
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
175,270
|
|
|
(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 2017. Mr. Wortley served as an executive officer of our general partner and as an executive officer of Cheniere during fiscal year 2017. Mr. Bensaude served as an officer of our general partner during fiscal year 2017. Mr. Shanda served as an officer of our general partner and as an executive officer of Cheniere during fiscal year 2017. 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. Welch serves as Senior Advisor to Blackstone Group and Mr. Munfa is a Managing Director in the Private Equity Group of Blackstone Group. They do not receive additional compensation for service as directors.
|
(5)
|
Mr. Ball was granted 3,000 phantom units in 2017 with a grant date fair value of $82,770. In addition, Mr. Ball received $10,346 in cash and 2,625 common units on account of 3,000 phantom units granted in earlier years that vested in 2017. As of December 31, 2017, he held 7,500 phantom units and 7,125 common units for a total of 14,625 units.
|
(6)
|
Mr. McCain was granted 3,000 phantom units in 2017 with a grant date fair value of $98,760. In addition, Mr. McCain received $49,380 in cash and 1,500 common units on account of 3,000 phantom units granted in earlier years that vested in 2017. As of December 31, 2017, he held 7,500 phantom units and 3,375 common units for a total of 10,875 units.
|
(7)
|
Mr. Pagano was granted 3,000 phantom units in 2017 with a grant date fair value of $82,680. In addition, Mr. Pagano received $41,340 in cash and 1,500 common units on account of 3,000 phantom units granted in earlier years that vested in 2017. As of December 31, 2017, he held 7,500 phantom units and 2,625 common units for a total of 10,125 units.
|
(8)
|
Mr. Richard was granted 3,000 phantom units in 2017 with a grant date fair value of $82,770. In addition, Mr. Richard received $20,693 in cash and 2,250 common units on account of 3,000 phantom units granted in earlier years that vested in 2017. As of December 31, 2017, he held 7,500 phantom units and 4,500 common units for a total of 12,000 units.
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED UNITHOLDER MATTERS
|
Name of Beneficial Owner
|
|
Common
Units
Beneficially
Owned
|
|
Percentage
of
Common
Units
Beneficially
Owned
|
|
Subordinated
Units
Beneficially
Owned
|
|
Percentage
of
Subordinated
Units
Beneficially
Owned
|
|
Percentage
of Total
Securities
Beneficially
Owned
|
|||||
Cheniere Energy, Inc. (1)
|
|
104,488,671
|
|
|
30
|
%
|
|
135,383,831
|
|
|
100
|
%
|
|
51
|
%
|
Cheniere Energy Partners LP Holdings, LLC
|
|
104,488,671
|
|
|
30
|
%
|
|
135,383,831
|
|
|
100
|
%
|
|
49
|
%
|
Blackstone Group (2)
|
|
4,382,079
|
|
|
1
|
%
|
|
—
|
|
|
—
|
|
|
1
|
%
|
Blackstone CQP Holdco
|
|
198,978,886
|
|
|
57
|
%
|
|
—
|
|
|
—
|
|
|
40
|
%
|
|
(1)
|
Cheniere Energy, Inc. is the parent company of Cheniere Energy Partners LP Holdings, LLC and may, therefore, be deemed to beneficially own the units held by Cheniere Energy Partners LP Holdings, LLC. Cheniere Energy, Inc. owns 82.7% of the outstanding common shares of Cheniere Energy Partners LP Holdings, LLC, as well as the sole share of that entity authorized to elect its directors. Cheniere Energy, Inc. also owns 9,877,232 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.,
|
|
|
Cheniere Energy Partners, L.P.
|
|
Cheniere Energy Partners LP Holdings, LLC
|
|
Cheniere Energy, Inc.
|
||||||||||||
Name of Beneficial Owner
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Class
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Class
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Class
|
||||||
Jack A. Fusco (1)
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
597,166
|
|
(1)
|
*%
|
|
Michael J. Wortley
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
468,788
|
|
|
*
|
|
Eric Bensaude
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,000
|
|
|
*
|
|
Doug Shanda
|
|
2,850
|
|
|
*
|
|
|
—
|
|
|
—
|
|
|
116,353
|
|
|
*
|
|
Philip Meier
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
John-Paul Munfa (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sean T. Klimczak
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Jamie Welch (2)
|
|
8,788
|
|
|
*
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
James R. Ball
|
|
7,125
|
|
|
*
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Lon McCain
|
|
3,375
|
|
|
*
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Vincent Pagano, Jr.
|
|
2,625
|
|
|
*
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oliver G. Richard, III
|
|
4,500
|
|
|
*
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
All current directors and executive officers as a group (11 persons)
|
|
29,263
|
|
|
*%
|
|
|
—
|
|
|
—
|
%
|
|
1,185,307
|
|
|
*%
|
|
|
(1)
|
Includes 154,378 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.
|
Plan Category
|
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)
|
|
Weighted-average exercise price of outstanding
options, warrants and rights
|
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column) (2)
|
||
Equity compensation plans approved by security holders
|
|
—
|
|
|
N/A
|
|
—
|
|
Equity compensation plans not approved by security holders
|
|
18,750
|
|
|
N/A
|
|
1,218,500
|
|
Total
|
|
18,750
|
|
|
N/A
|
|
1,218,500
|
|
|
(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.
|
•
|
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
|
ITEM 14.
|
PRINCIPAL ACCOUNTANT FEES AND SERVICES
|
|
|
Fiscal 2017
|
|
Fiscal 2016
|
||||
Audit Fees
|
|
$
|
3
|
|
|
$
|
3
|
|
ITEM 15.
|
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|
(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.
|
Exhibit No.
|
|
Description
|
2.1
|
|
|
2.2
|
|
|
3.1
|
|
Exhibit No.
|
|
Description
|
3.2
|
|
|
3.3
|
|
|
3.4
|
|
|
4.1
|
|
|
4.2
|
|
|
4.3
|
|
|
4.4
|
|
|
4.5
|
|
|
4.6
|
|
|
4.7
|
|
|
4.8
|
|
|
4.9
|
|
|
4.10
|
|
|
4.11
|
|
|
4.12
|
|
|
4.13
|
|
|
4.14
|
|
|
4.15
|
|
|
4.16
|
|
|
4.17
|
|
|
4.18
|
|
|
4.19
|
|
|
4.20
|
|
|
4.21
|
|
Exhibit No.
|
|
Description
|
4.22
|
|
|
4.23
|
|
|
4.24
|
|
|
4.25
|
|
|
4.26
|
|
|
10.1
|
|
|
10.2
|
|
|
10.3
|
|
|
10.4
|
|
|
10.5
|
|
|
10.6
|
|
|
10.7
|
|
|
10.8
|
|
|
10.9
|
|
|
10.10
|
|
|
10.11
|
|
|
10.12
|
|
|
10.13
|
|
|
10.14
|
|
Exhibit No.
|
|
Description
|
10.15
|
|
|
10.16
|
|
|
10.17
|
|
|
10.18
|
|
|
10.19
|
|
|
10.20*
|
|
|
10.21
|
|
|
10.22†
|
|
|
10.23†
|
|
|
10.24†
|
|
|
10.25†
|
|
|
10.26†
|
|
|
10.27†
|
|
|
10.28†
|
|
Exhibit No.
|
|
Description
|
10.29
|
|
|
10.30
|
|
|
10.31
|
|
|
10.32
|
|
|
10.33
|
|
|
10.34
|
|
|
10.35
|
|
|
10.36
|
|
|
10.37
|
|
Exhibit No.
|
|
Description
|
10.38
|
|
|
10.39
|
|
|
10.40
|
|
|
10.41*
|
|
|
10.42
|
|
|
10.43
|
|
|
10.44
|
|
|
10.45
|
|
|
10.46
|
|
|
10.47
|
|
|
10.48
|
|
|
10.49
|
|
|
10.50
|
|
Exhibit No.
|
|
Description
|
10.51
|
|
|
10.52
|
|
|
10.53
|
|
|
10.54
|
|
|
10.55
|
|
|
10.56
|
|
|
10.57
|
|
|
10.58
|
|
|
10.59
|
|
|
10.60
|
|
|
10.61
|
|
|
10.62
|
|
|
10.63
|
|
|
10.64
|
|
|
10.65
|
|
|
10.66
|
|
Exhibit No.
|
|
Description
|
10.67
|
|
|
10.68
|
|
|
21.1*
|
|
|
23.1*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1**
|
|
|
32.2**
|
|
|
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
|
|
|
|
*
|
Filed herewith.
|
**
|
Furnished herewith.
|
†
|
Management contract or compensatory plan or arrangement.
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
ASSETS
|
|
|
|
|
|
|
||
Current assets
|
|
|
|
|
|
|
||
Cash and cash equivalents
|
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash
|
|
1,033
|
|
|
234
|
|
||
Prepaid expenses and other
|
|
8
|
|
|
—
|
|
||
Total current assets
|
|
1,041
|
|
|
234
|
|
||
|
|
|
|
|
||||
Property, plant and equipment, net
|
|
80
|
|
|
79
|
|
||
Debt issuance and deferred financing costs, net
|
|
20
|
|
|
63
|
|
||
Investment in affiliates
|
|
2,076
|
|
|
2,617
|
|
||
Non-current derivative assets
|
|
14
|
|
|
16
|
|
||
Total assets
|
|
$
|
3,231
|
|
|
$
|
3,009
|
|
|
|
|
|
|
||||
|
|
|
|
|
||||
LIABILITIES AND PARTNERS’ EQUITY
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accrued interest costs and related debt fees
|
|
$
|
23
|
|
|
$
|
1
|
|
Derivative liabilities
|
|
—
|
|
|
3
|
|
||
Other current liabilities
|
|
—
|
|
|
2
|
|
||
Total current liabilities
|
|
23
|
|
|
6
|
|
||
|
|
|
|
|
||||
Long-term debt, net
|
|
2,569
|
|
|
2,560
|
|
||
|
|
|
|
|
||||
Partners’ equity
|
|
639
|
|
|
443
|
|
||
Total liabilities and partners’ equity
|
|
$
|
3,231
|
|
|
$
|
3,009
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Operating costs and expenses
|
|
|
|
|
|
|
||||||
Operating and maintenance expense
|
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
3
|
|
Operating and maintenance expense—affiliate
|
|
6
|
|
|
—
|
|
|
—
|
|
|||
General and administrative expense
|
|
4
|
|
|
4
|
|
|
3
|
|
|||
General and administrative expense—affiliate
|
|
11
|
|
|
12
|
|
|
11
|
|
|||
Depreciation and amortization expense
|
|
2
|
|
|
1
|
|
|
—
|
|
|||
Total operating costs and expenses
|
|
27
|
|
|
22
|
|
|
17
|
|
|||
|
|
|
|
|
|
|
||||||
Other income (expense)
|
|
|
|
|
|
|
||||||
Interest expense, net of capitalized interest
|
|
(111
|
)
|
|
(23
|
)
|
|
—
|
|
|||
Loss on early extinguishment of debt
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|||
Derivative gain, net
|
|
6
|
|
|
12
|
|
|
—
|
|
|||
Other income
|
|
4
|
|
|
—
|
|
|
—
|
|
|||
Equity income (loss) of affiliates
|
|
643
|
|
|
(138
|
)
|
|
(302
|
)
|
|||
Total other income (expense)
|
|
517
|
|
|
(149
|
)
|
|
(302
|
)
|
|||
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
490
|
|
|
$
|
(171
|
)
|
|
$
|
(319
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Cash used in operating activities
|
$
|
(101
|
)
|
|
$
|
(53
|
)
|
|
$
|
(43
|
)
|
|
|
|
|
|
|
||||||
Cash flows from investing activities
|
|
|
|
|
|
||||||
Property, plant and equipment, net
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Investments in subsidiaries
|
(245
|
)
|
|
(2,429
|
)
|
|
13
|
|
|||
Distributions received from affiliates, net
|
1,431
|
|
|
218
|
|
|
18
|
|
|||
Net cash provided by (used in) investing activities
|
1,186
|
|
|
(2,211
|
)
|
|
30
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities
|
|
|
|
|
|
|
|||||
Proceeds from issuance of debt
|
1,500
|
|
|
2,560
|
|
|
—
|
|
|||
Repayments of debt
|
(1,470
|
)
|
|
—
|
|
|
—
|
|
|||
Debt issuance and deferred financing costs
|
(22
|
)
|
|
(73
|
)
|
|
—
|
|
|||
Distributions to owners
|
(294
|
)
|
|
(99
|
)
|
|
(99
|
)
|
|||
Net cash provided by (used in) financing activities
|
(286
|
)
|
|
2,388
|
|
|
(99
|
)
|
|||
|
|
|
|
|
|
||||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
799
|
|
|
124
|
|
|
(112
|
)
|
|||
Cash, cash equivalents and restricted cash—beginning of period
|
234
|
|
|
110
|
|
|
222
|
|
|||
Cash, cash equivalents and restricted cash—end of period
|
$
|
1,033
|
|
|
$
|
234
|
|
|
$
|
110
|
|
|
December 31
|
||||||
|
2017
|
|
2016
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash
|
1,033
|
|
|
234
|
|
||
Total cash, cash equivalents and restricted cash
|
$
|
1,033
|
|
|
$
|
234
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Long-term debt:
|
|
|
|
|
||||
5.250% Senior Notes due 2025
|
|
$
|
1,500
|
|
|
$
|
—
|
|
2016 CQP Credit Facilities
|
|
1,090
|
|
|
2,560
|
|
||
Unamortized debt issuance costs
|
|
(21
|
)
|
|
—
|
|
||
Total long-term debt, net
|
|
$
|
2,569
|
|
|
$
|
2,560
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Non-cash capital distributions (contributions) (1)
|
|
$
|
643
|
|
|
$
|
(138
|
)
|
|
$
|
(302
|
)
|
|
(1)
|
Amounts represent equity income (loss) of affiliates not funded by Cheniere Partners.
|
ITEM 16.
|
FORM 10-K SUMMARY
|
|
CHENIERE ENERGY PARTNERS, L.P.
|
|
|
By:
|
Cheniere Energy Partners GP, LLC,
its general partner
|
|
|
|
|
By:
|
/s/ Jack A. Fusco
|
|
|
Jack A. Fusco
|
|
|
President and Chief Executive Officer
(Principal Executive Officer) |
|
Date:
|
February 20, 2018
|
Signature
|
Title
|
Date
|
|
|
|
/s/ Jack A. Fusco
|
President and Chief Executive Officer, Chairman of the Board
(Principal Executive Officer) |
February 20, 2018
|
Jack A. Fusco
|
|
|
|
|
|
/s/ Michael J. Wortley
|
Executive Vice President and Chief Financial Officer, Director
(Principal Financial Officer) |
February 20, 2018
|
Michael J. Wortley
|
|
|
|
|
|
/s/ Leonard Travis
|
Vice President and Chief Accounting Officer
(Principal Accounting Officer) |
February 20, 2018
|
Leonard Travis
|
|
|
|
|
|
/s/ Eric Bensaude
|
Director
|
February 20, 2018
|
Eric Bensaude
|
|
|
|
|
|
/s/ Doug Shanda
|
Director
|
February 20, 2018
|
Doug Shanda
|
|
|
|
|
|
/s/ Philip Meier
|
Director
|
February 20, 2018
|
Philip Meier
|
|
|
|
|
|
/s/ John-Paul Munfa
|
Director
|
February 20, 2018
|
John-Paul Munfa
|
|
|
|
|
|
/s/ Jamie Welch
|
Director
|
February 20, 2018
|
Jamie Welch
|
|
|
|
|
|
/s/ James R. Ball
|
Director
|
February 20, 2018
|
James R. Ball
|
|
|
|
|
|
/s/ Lon McCain
|
Director
|
February 20, 2018
|
Lon McCain
|
|
|
|
|
|
/s/ Vincent Pagano Jr.
|
Director
|
February 20, 2018
|
Vincent Pagano Jr.
|
|
|
|
|
|
/s/ Oliver G. Richard, III
|
Director
|
February 20, 2018
|
Oliver G. Richard, III
|
|
|
(a)
|
The reference to “Section 2.18
(Ratable Sharing)
” in the definition of “Aggregate Amounts Due” is hereby updated to “Section 2.16
(Ratable Sharing)
”.
|
(a)
|
authorizes and consents to the Borrower making Restricted Payments on Quarterly Payment Dates and True-Up Dates in accordance with the Financing Documents;
|
(b)
|
authorizes and consents to any and all amendments and other modifications to each of the Financing Documents, the exhibits and schedules thereto and each other ancillary document, in each case, to the extent necessary or appropriate, in the reasonable opinion of the Administrative Agent to reflect and/or effect the amendments and modifications set forth in this Amendment; and
|
(c)
|
directs the Administrative Agent to (i) execute this Amendment and (ii) direct the Collateral Agent and Depositary Bank to execute this Amendment.
|
CHENIERE ENERGY PARTNERS,
|
|
L.P.,
|
|
as Borrower
|
|
|
|
|
|
By:
|
Cheniere Energy Partners GP, LLC, its
|
general partner
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa C. Cohen
|
|
Title: Vice President and Treasurer
|
|
|
|
|
|
CHENIERE ENERGY INVESTMENTS,
|
|
LLC,
|
|
as Subsidiary Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa C. Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
CHENIERE PIPELINE GP INTERESTS, LLC,
|
|
as Subsidiary Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa C. Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
CHENIERE CREOLE TRAIL PIPELINE, L.P.,
|
|
as Subsidiary Guarantor
|
|
|
|
|
|
By: CHENIERE PIPELINE GP INTERESTS,
|
|
LLC, its general partner
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa C. Cohen
|
|
Title: Treasurer
|
SABINE PASS LNG, L.P.,
|
|
as Subsidiary Guarantor
|
|
|
|
|
|
By:
|
SABINE PASS LNG-GP, LLC,
|
|
its General Partner
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa C. Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
SABINE PASS LNG-GP, LLC,
|
|
as Subsidiary Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa C. Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
SABINE PASS LNG-LP, LLC,
|
|
as Subsidiary Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa C. Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
SABINE PASS TUG SERVICES, LLC,
|
|
as Subsidiary Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa C. Cohen
|
|
Title: Treasurer
|
THE BANK OF TOKYO-MITSUBISHI
|
|
UFJ, LTD
,
|
|
as Administrative Agent and Controlling
|
|
Agent under the Intercreditor Agreement
|
|
|
|
|
|
By:
|
/s/ Lawrence Blat
|
Name: Lawrence Blat
|
|
Title: Authorized Signatory
|
|
|
|
|
|
MUFG UNION BANK, N.A.
,
|
|
as the Collateral Agent and Depositary
|
|
Bank
|
|
|
|
|
|
By:
|
/s/ Fernando Moreyra
|
Name: Fernando Moreyra
|
|
Title: Vice President
|
THE BANK OF TOKYO-MITSUBISHI
|
|
UFJ, LTD
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Saad Iqbal
|
Name: Saad Iqbal
|
|
Title: Managing Director
|
SOCIÉTÉ GÉNÉRALE
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Ellen Turkel
|
Name: Ellen Turkel
|
|
Title: Director
|
INDUSTRIAL AND COMMERCIAL
|
|
BANK OF CHINA LIMITED SEOUL
|
|
BRANCH
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Niu, Jianjun
|
Name: Niu, Jianjun
|
|
Title: General Manager
|
INDUSTRIAL AND COMMERCIAL
|
|
BANK OF CHINA LIMITED NEW
|
|
YORK BRANCH
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Guoshen Sun
|
Name: Guoshen Sun
|
|
Title: Deputy General Manager
|
INTESA SANPAOLO S.P.A., NEW
|
|
YORK, BRANCH
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Francesco DiMario
|
Name: Francesco DiMario
|
|
Title: First Vice President
|
|
|
|
|
|
|
|
By:
|
/s/ Nicholas A. Matacchieri
|
Name: Nicholas A. Matacchieri
|
|
Title: Vice President
|
JPMORGAN CHASE BANK, N.A.
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Travis Watson
|
Name: Travis Watson
|
|
Title: Vice President
|
MIZUHO BANK, LTD.
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Brian Caldwell
|
Name: Brian Caldwell
|
|
Title: Managing Director
|
SUMITOMO MITSUI BANKING
|
|
CORPORATION
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Juan Kreutz
|
Name: Juan Kreutz
|
|
Title: Managing Director
|
MORGAN STANLEY SENIOR
|
|
FUNDING, INC.
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Pat Layton
|
Name: Pat Layton
|
|
Title: Vice President
|
BANK OF AMERICA, N.A.
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Ronald E. McKaig
|
Name: Ronald E. McKaig
|
|
Title: Managing Director
|
CREDIT SUISSE AG, CAYMAN
|
|
ISLANDS BRANCH
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Nupur Kumar
|
Name: Nupur Kumar
|
|
Title: Authorized Signatory
|
|
|
|
|
|
|
|
By:
|
/s/ Christopher Zybrick
|
Name: Christopher Zybrick
|
|
Title: Authorized Signatory
|
HSBC BANK USA, NATIONAL
|
|
ASSOCIATION
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Raphael Dumas
|
Name: Raphael Dumas
|
|
Title: Director
|
CANADIAN IMPERIAL BANK OF
|
|
COMMERCE, NEW YORK BRANCH
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Jim King
|
Name: Jim King
|
|
Title: Authorized Signatory
|
|
|
|
|
|
|
|
By:
|
/s/ Joshua Hogarth
|
Name: Joshua Hogarth
|
|
Title: Authorized Signatory
|
lNG CAPITAL LLC
,
|
|
as Lender
|
|
|
|
|
|
By:
|
/s/ Subha Pasumarti
|
Name: Subha Pasumarti
|
|
Title: Managing Director
|
|
|
|
|
|
|
|
By:
|
/s/ Cheryl LaBelle
|
Name: Cheryl LaBelle
|
|
Title: Managing Director
|
PROJECT NAME:
Sabine Pass LNG Stage 3 Liquefaction Facility
OWNER:
Sabine Pass Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: May 4, 2015
|
CHANGE ORDER NUMBER:
CO-00022
DATE OF CHANGE ORDER:
October 24, 2017
|
1.
|
Per Article 6.1.B of the Agreement, Parties agree Bechtel will modify the original stair rail system per the following:
|
a.
|
Per
OSHA 29 CFR 1910.29 (f)(l)(ii)(A)/(B)
, the height of stair rail systems installed before January 17, 2017 is not less than 30 or more than 34 inches from the leading edge of the stair tread to the top surface of the top rail; and the height of stair rail systems installed on or after January 17, 2017 is not less than 42 inches from the leading edge of the stair tread to the top surface of the top rail.
|
b.
|
The modified stair railing design is in accordance with the specifications in the current version of
OSHA 29 CFR Subpart D 1910 Subpart D Walking-Working Surfaces
and is only applicable to the stairs previously fabricated and in process of installation.
|
c.
|
Stair guardrails for stair railing “issued for construction” after January 17, 2017 will be per drawing 25936-100-SS-000-00017. These same standards will also be followed for the tank stairs.
|
d.
|
Stair guardrails already fabricated and on-site will be retrofitted per drawing 25936-100-SS-000-00018.
|
e.
|
Adjustments to lighting and bracketing due to changes in handrails.
|
f.
|
The scope of work incorporated into the Agreement via this Change Order will be completed before Substantial Completion of Stage 3.
|
2.
|
This Change Order excludes any updates to Stage 3 vessels.
|
3.
|
The overall cost breakdown associated with the increase in the OSHA Handrail and Guardrail Modifications is provided in Exhibit B of this Change Order.
|
4.
|
Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit C of this Change Order.
|
The original Contract Price was
|
$
|
2,987,000,000
|
|
Net change by previously authorized Change Orders (#0001-00021)
|
$
|
97,638,960
|
|
The Contract Price prior to this Change Order was
|
$
|
3,084,638,960
|
|
The Contract Price will be increased by this Change Order in the amount of
|
$
|
2,081,387
|
|
The new Contract Price including this Change Order will be
|
$
|
3,086,720,347
|
|
/s/ Ed Lehotsky
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
Ed Lehotsky
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP LNG E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
November 8, 2017
|
|
October 24, 2017
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Sabine Pass LNG Stage 3 Liquefaction Facility
OWNER:
Sabine Pass Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: May 4, 2015
|
CHANGE ORDER NUMBER:
CO-00023
DATE OF CHANGE ORDER:
October 31, 2017
|
1.
|
The value of the Operating Spare Part Provisional Sum in the Agreement was U.S. $6,354,664. Parties now agree to close this Provisional Sum. Actual cost for the Operational Spare Parts was $0. The contract price will be decreased by $6,735,944 which reflects the closure of the provisional sum and credit for the 6% fee.
|
2.
|
The Provisional Sum breakdown is described as follows:
|
a.
|
The previous Operating Spare Part Provisional Sum specified in Article 2.3 of Attachment EE, Schedule EE-2, of the Agreement was U.S. $6,354,664. The Operating Spare Part Provisional Sum will be reduced by U.S. $6,354,664. The new value of the Operating Spare Part Provisional Sum will be $0.
|
b.
|
The Parties agree to adjust the Aggregate Provisional Sum specified in Article 7.1A of the Agreement which prior to this Change Order was Three Hundred Twenty-Two Million, Six Hundred One Thousand, One Hundred One U.S. Dollars (U.S.$322,601,101). This Change Order will decrease the Aggregate Provisional Sum amount by Six Million, Three Hundred Fifty-Four Thousand, Six Hundred Sixty-Four U.S. Dollars (U.S.$6,354,664) and the new Aggregate Provisional Sum value shall be Three Hundred Sixteen Million, Two Hundred Forty-Six Thousand, Four Hundred Thirty-Seven U.S. Dollars (U.S. $316,246,437).
|
3.
|
Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit A of this Change Order.
|
The original Contract Price was
|
$
|
2,987,000,000
|
|
Net change by previously authorized Change Orders (#0001-00022)
|
$
|
99,720,347
|
|
The Contract Price prior to this Change Order was
|
$
|
3,086,720,347
|
|
The Contract Price will be decreased by this Change Order in the amount of
|
$
|
(6,735,944
|
)
|
The new Contract Price including this Change Order will be
|
$
|
3,079,984,403
|
|
/s/ Ed Lehotsky
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
Ed Lehotsky
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP LNG E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
November 8, 2017
|
|
October 31, 2017
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Sabine Pass LNG Stage 3 Liquefaction Facility
OWNER:
Sabine Pass Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: May 4, 2015
|
CHANGE ORDER NUMBER:
CO-00024
DATE OF CHANGE ORDER:
November 28, 2017
|
1.
|
In exchange for an adjustment to the Contract Price of U.S.$ 1,000,000, Contractor hereby waives, relinquishes, remits and releases all claims, demands, actions, causes of actions or other rights at law, in contract, quantum meruit, unjust enrichment, tort, equity or otherwise that Contractor has or may have had against Owner (whether or not known to Contractor) arising out of the Agreement or the Project concerning any and all Force Majeure events occurring prior to October 1, 2017, including, but not limited to those Force Majeure events conveyed to Owner in the following correspondences:
|
a.
|
Correspondence No. 25936-100-T16-GAM-00053, dated May 10, 2016;
|
b.
|
Correspondence No. 25936-100-T17-GAM-00004, dated January 11, 2017;
|
c.
|
Correspondence No. 25936-100-T17-GAM-00043, dated June 26, 2017;
|
d.
|
Correspondence No. 25936-100-T17-GAM-00048, dated July 12, 2017; and
|
e.
|
Correspondence No. 25936-100-T17-GAM-00059, dated September 6, 2017.
|
2.
|
In addition, Owner shall pay Contractor One Million Nine Hundred Eighty-Eight Thousand U.S. Dollars (U.S.$1,988,000) for short term craft incentives (the “Craft Incentive Payment”) for any and all impacts arising out of Hurricane Harvey and associated events. This Craft Incentive Payment shall be paid by Owner under the Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum.
|
The original Contract Price was
|
$
|
2,987,000,000
|
|
Net change by previously authorized Change Orders (#0001-00023)
|
$
|
92,984,403
|
|
The Contract Price prior to this Change Order was
|
$
|
3,079,984,403
|
|
The Contract Price will be increased by this Change Order in the amount of
|
$
|
2,988,000
|
|
The new Contract Price including this Change Order will be
|
$
|
3,082,972,403
|
|
/s/ Ed Lehotsky
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
Ed Lehotsky
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP LNG E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
December 13, 2017
|
|
November 28, 2017
|
Date of Signing
|
|
Date of Signing
|
Entity Name
|
|
Jurisdiction of Incorporation
|
Cheniere Creole Trail Pipeline, L.P.
|
|
Delaware
|
Cheniere Energy Investments, LLC
|
|
Delaware
|
Cheniere Pipeline GP Interests, LLC
|
|
Delaware
|
Sabine Pass Liquefaction, LLC
|
|
Delaware
|
Sabine Pass LNG-GP, LLC
|
|
Delaware
|
Sabine Pass LNG-LP, LLC
|
|
Delaware
|
Sabine Pass LNG, L.P.
|
|
Delaware
|
Sabine Pass Tug Services, LLC
|
|
Delaware
|
|
/s/ KPMG LLP
|
KPMG LLP
|
|
1.
|
I have reviewed this
annual report on Form 10-K
of Cheniere Energy Partners, L.P.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter
(the registrant’s fourth quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ Jack A. Fusco
|
Jack A. Fusco
|
Chief Executive Officer of
|
Cheniere Energy Partners GP, LLC, the general partner of
|
Cheniere Energy Partners, L.P.
|
1.
|
I have reviewed this
annual report on Form 10-K
of Cheniere Energy Partners, L.P.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter
(the registrant’s fourth quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ Michael J. Wortley
|
Michael J. Wortley
|
Chief Financial Officer of
|
Cheniere Energy Partners GP, LLC, the general partner of
|
Cheniere Energy Partners, L.P.
|
(1)
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
/s/ Jack A. Fusco
|
Jack A. Fusco
|
Chief Executive Officer of
|
Cheniere Energy Partners GP, LLC, the general partner of
|
Cheniere Energy Partners, L.P.
|
(1)
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
/s/ Michael J. Wortley
|
Michael J. Wortley
|
Chief Financial Officer of
|
Cheniere Energy Partners GP, LLC, the general partner of
|
Cheniere Energy Partners, L.P.
|