|
Delaware
|
95-4352386
|
(State or other jurisdiction of incorporation or organization)
|
(I.R.S. Employer Identification No.)
|
|
|
700 Milam Street, Suite 1900
|
|
Houston, Texas
|
77002
|
(Address of principal executive offices)
|
(Zip code)
|
Common Stock, $ 0.003 par value
|
NYSE American
|
(Title of each class)
|
(Name of each exchange on which registered)
|
Large accelerated filer
x
|
Accelerated filer
o
|
Non-accelerated filer
o
|
Smaller reporting company
o
|
|
Emerging growth company
o
|
|
Bcf
|
|
billion cubic feet
|
Bcf/d
|
|
billion cubic feet per day
|
Bcf/yr
|
|
billion cubic feet per year
|
Bcfe
|
|
billion cubic feet equivalent
|
DOE
|
|
U.S. Department of Energy
|
EPC
|
|
engineering, procurement and construction
|
FERC
|
|
Federal Energy Regulatory Commission
|
FTA countries
|
|
countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
|
GAAP
|
|
generally accepted accounting principles in the United States
|
Henry Hub
|
|
the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
|
LIBOR
|
|
London Interbank Offered Rate
|
LNG
|
|
liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
|
MMBtu
|
|
million British thermal units, an energy unit
|
mtpa
|
|
million tonnes per annum
|
non-FTA countries
|
|
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
|
SEC
|
|
U.S. Securities and Exchange Commission
|
SPA
|
|
LNG sale and purchase agreement
|
TBtu
|
|
trillion British thermal units, an energy unit
|
Train
|
|
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
|
TUA
|
|
terminal use agreement
|
•
|
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;
|
•
|
statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
|
•
|
statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
|
•
|
statements relating to the construction of our Trains and pipelines, including statements concerning the engagement of any
EPC
contractor or other contractor and the anticipated terms and provisions of any agreement with any
EPC
or other contractor, and anticipated costs related thereto;
|
•
|
statements regarding any
SPA
or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
|
•
|
statements regarding counterparties to our commercial contracts, construction contracts, and other contracts;
|
•
|
statements regarding our planned development and construction of additional Trains and pipelines, including the financing of such Trains or pipelines;
|
•
|
statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
|
•
|
statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
|
•
|
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
|
•
|
statements regarding marketing of volumes expected to be made available to our integrated marketing function; and
|
•
|
any other statements that relate to non-historica
l or future information.
|
ITEMS 1. AND 2.
|
BUSINESS AND PROPERTIES
|
•
|
achieving the date of first commercial delivery for our SPA customers;
|
•
|
safely, efficiently and reliably maintaining and operating our assets;
|
•
|
completing construction and commencing operation of Train 5 of the SPL Project and the first three Trains of the CCL Project;
|
•
|
making LNG available to our SPA customers to generate steady and reliable revenues and operating cash flows;
|
•
|
obtaining the requisite long-term commercial contracts and financing to reach an
FID
regarding Train 6 of the SPL Project;
|
•
|
further expanding and optimizing the SPL Project and the CCL Project by leveraging existing infrastructure;
|
•
|
developing business relationships for the marketing of LNG volumes expected to be made available to our integrated marketing function and additional LNG liquefaction projects or expansions;
|
•
|
expanding our existing asset base through acquisitions or development of complementary businesses or assets across the LNG value chain; and
|
•
|
maintaining a flexible capital structure to finance the acquisition, development, construction and operation of the energy assets needed to supply our customers.
|
|
|
SPL Train 5
|
|
Overall project completion percentage
|
|
99.7%
|
|
Completion percentage of:
|
|
|
|
Engineering
|
|
100%
|
|
Procurement
|
|
100%
|
|
Subcontract work
|
|
98.0%
|
|
Construction
|
|
99.6%
|
|
Date of expected substantial completion
|
|
1Q 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).
|
•
|
approximately $720 million from
BG
, which is guaranteed by BG Energy Holdings Limited;
|
•
|
approximately $550 million from Korea Gas Corporation
(“KOGAS”)
;
|
•
|
approximately $550 million from
GAIL
; and
|
•
|
approximately $450 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM, Limited)
(“Naturgy”)
, which is guaranteed by
Naturgy Energy Group, S.A.
(formerly known as Gas Natural SDG S.A.).
|
|
CCL Stage 1
|
|
CCL Stage 2
|
||
Overall project completion percentage
|
96.7%
|
|
42.0%
|
||
Completion percentage of:
|
|
|
|
|
|
Engineering
|
100%
|
|
87.0%
|
||
Procurement
|
100%
|
|
63.0%
|
||
Subcontract work
|
89.5%
|
|
8.5%
|
||
Construction
|
93.1%
|
|
11.7%
|
||
Expected date of substantial completion
|
Train 1
|
1Q 2019
|
|
Train 3
|
2H 2021
|
|
Train 2
|
2H 2019
|
|
|
|
•
|
CCL Project—
FTA countries
for a 25-year term and to
non-FTA countries
for a 20-year term up to a combined total of the equivalent of 767
Bcf/yr
(approximately 15 mtpa) of natural gas.
|
•
|
Corpus Christi Stage 3
—FTA countries for a 20-year term in an amount equivalent to 514 Bcf/yr (approximately 10 mtpa) of natural gas (the “Stage 3 FTA”). The application for authorization to export that same 514 Bcf/yr of domestically produced LNG by vessel to non-FTA countries is currently pending before the DOE (the “Stage 3 Non-FTA”).
|
•
|
approximately $410 million from Endesa S.A.;
|
•
|
approximately $280 million from PT Pertamina (Persero); and
|
•
|
approximately $270 million from
Naturgy
, which is guaranteed by
Naturgy Energy Group, S.A.
|
•
|
rates and charges, and terms and conditions for natural gas transportation and related services;
|
•
|
the certification and construction of new facilities;
|
•
|
the extension and abandonment of services and facilities;
|
•
|
the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;
|
•
|
the acquisition and disposition of facilities;
|
•
|
the initiation and discontinuation of services; and
|
•
|
various other matters.
|
ITEM 1A.
|
RISK FACTORS
|
•
|
Risks Relating to Our Financial Matters;
|
•
|
Risks Relating to Our LNG Terminal Operations and Commercialization;
|
•
|
Risks Relating to Our LNG Business in General; and
|
•
|
Risks Relating to Our Business in General.
|
•
|
make certain investments;
|
•
|
purchase, redeem or retire equity interests;
|
•
|
issue preferred stock;
|
•
|
sell or transfer assets;
|
•
|
incur liens;
|
•
|
enter into transactions with affiliates;
|
•
|
consolidate, merge, sell or lease all or substantially all of our assets; and
|
•
|
enter into sale and leaseback transactions.
|
•
|
expected supply is less than the amount hedged;
|
•
|
the counterparty to the hedging contract defaults on its contractual obligations; or
|
•
|
there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
|
•
|
the facilities’ performing below expected levels of efficiency;
|
•
|
breakdown or failures of equipment;
|
•
|
operational errors by vessel or tug operators;
|
•
|
operational errors by us or any contracted facility operator;
|
•
|
labor disputes; and
|
•
|
weather-related interruptions of operations.
|
•
|
design and engineer each Train to operate in accordance with specifications;
|
•
|
engage and retain third-party subcontractors and procure equipment and supplies;
|
•
|
respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
|
•
|
attract, develop and retain skilled personnel, including engineers;
|
•
|
post required construction bonds and comply with the terms thereof;
|
•
|
manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
|
•
|
maintain their own financial condition, including adequate working capital.
|
•
|
perform ongoing assessments of pipeline integrity;
|
•
|
identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”;
|
•
|
improve data collection, integration and analysis;
|
•
|
repair and remediate the pipeline as necessary; and
|
•
|
implement preventative and mitigating actions.
|
•
|
additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from the Sabine Pass LNG terminal and the Corpus Christi LNG terminal;
|
•
|
competitive liquefaction capacity in North America;
|
•
|
insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
|
•
|
insufficient LNG tanker capacity;
|
•
|
weather conditions;
|
•
|
reduced demand and lower prices for natural gas;
|
•
|
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
|
•
|
decreased oil and natural gas exploration activities, which may decrease the production of natural gas;
|
•
|
cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;
|
•
|
changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
|
•
|
changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
|
•
|
political conditions in natural gas producing regions;
|
•
|
adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
|
•
|
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
|
•
|
increased construction costs;
|
•
|
economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
|
•
|
decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;
|
•
|
the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
|
•
|
political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and
|
•
|
any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
|
•
|
an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
|
•
|
political or economic disturbances in the countries where the vessels are being constructed;
|
•
|
changes in governmental regulations or maritime self-regulatory organizations;
|
•
|
work stoppages or other labor disturbances at the shipyards;
|
•
|
bankruptcy or other financial crisis of shipbuilders;
|
•
|
quality or engineering problems;
|
•
|
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
|
•
|
shortages of or delays in the receipt of necessary construction materials.
|
•
|
increases in worldwide LNG production capacity and availability of LNG for market supply;
|
•
|
increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
|
•
|
increases in the cost to supply natural gas feedstock to our liquefaction projects;
|
•
|
decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
|
•
|
decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
|
•
|
increases in capacity and utilization of nuclear power and related facilities; and
|
•
|
displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
|
•
|
domestic and worldwide supply of and demand for natural gas and corresponding fluctuations in the price of natural gas;
|
•
|
fluctuations in our quarterly or annual financial results or those of other companies in our industry;
|
•
|
issuance of additional equity securities which causes further dilution to stockholders;
|
•
|
sales of a high volume of shares of our common stock by our stockholders;
|
•
|
operating and stock price performance of companies that investors deem comparable to us;
|
•
|
events affecting other companies that the market deems comparable to us;
|
•
|
changes in government regulation or proposals applicable to us;
|
•
|
actual or potential non-performance by any customer or a counterparty under any agreement;
|
•
|
announcements made by us or our competitors of significant contracts;
|
•
|
changes in accounting standards, policies, guidance, interpretations or principles;
|
•
|
general conditions in the industries in which we operate;
|
•
|
general economic conditions;
|
•
|
the failure of securities analysts to cover our common stock or changes in financial or other estimates by analysts; and
|
•
|
other factors described in these “Risk Factors.”
|
ITEM 1B.
|
UNRESOLVED STAFF COMMENTS
|
ITEM 4.
|
MINE SAFETY DISCLOSURE
|
ITEM 5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
|
Period
|
|
Total Number of Shares Purchased (1)
|
|
Average Price Paid Per Share (2)
|
|
Total Number of Shares Purchased as a Part of Publicly Announced Plans
|
|
Maximum Number of Units That May Yet Be Purchased Under the Plans
|
October 1 - 31, 2018
|
|
133,205
|
|
$65.85
|
|
—
|
|
—
|
November 1 - 30, 2018
|
|
14,623
|
|
$61.65
|
|
—
|
|
—
|
December 1 - 31, 2018
|
|
1,108
|
|
$61.37
|
|
—
|
|
—
|
|
(1)
|
Represents shares surrendered to us by participants in our share-based compensation plans to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under these plans.
|
(2)
|
The price paid per share was based on the closing trading price of our common stock on the dates on which we repurchased shares from the participants under our share-based compensation plans.
|
New Peer Group
|
||
Air Products and Chemicals, Inc. (APD)
|
|
Kinder Morgan, Inc. (KMI)
|
Anadarko Petroleum Corporation (APC)
|
|
LyondellBasell Industries N.V. (LYB)
|
Andeavor (ANDV)
|
|
Marathon Oil Corporation (MRO)
|
Apache Corporation (APA)
|
|
Marathon Petroleum Corporation (MPC)
|
Baker Hughes, a GE company (BHGE)
|
|
Noble Energy, Inc. (NBL)
|
Concho Resources Inc. (CXO)
|
|
Occidental Petroleum Corporation (OXY)
|
ConocoPhillips (COP)
|
|
ONEOK, Inc. (OKE)
|
Continental Resources, Inc. (CLR)
|
|
Phillips 66 (PSX)
|
Devon Energy Corporation (DVN)
|
|
Pioneer Natural Resources Company (PXD)
|
Enterprise Products Partners L.P. (EPD)
|
|
Praxair, Inc. (PX)
|
EOG Resources, Inc. (EOG)
|
|
Schlumberger Limited (SLB)
|
EQT Corporation (EQT)
|
|
Suncor Energy Inc. (SU)
|
Freeport-McMoRan Inc. (FCX)
|
|
Valero Energy Corporation (VLO)
|
Halliburton Company (HAL)
|
|
The Williams Companies, Inc. (WMB)
|
Hess Corporation (HES)
|
|
|
Old Peer Group
|
||
Ameren Corporation (AEE)
|
|
PG&E Corporation (PCG)
|
Calpine Corp. (CPN)
|
|
Public Service Enterprise Group Inc. (PEG)
|
CMS Energy Corp. (CMS)
|
|
Sempra Energy (SRE)
|
Dominion Resources, Inc. (D)
|
|
Targa Resources Corp. (TRGP)
|
DTE Energy Company (DTE)
|
|
TransCanada Corporation (TRP)
|
Dynegy Inc. (DYN)
|
|
MarkWest Energy Partners, L.P. (MWE)
|
Enterprise Products Partners L.P. (EPD)
|
|
Spectra Energy Corp (SE)
|
Magellan Midstream Partners, L.P. (MMP)
|
|
Enbridge (ENB)
|
ONEOK, Inc. (OKE)
|
|
|
Company / Index
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
||||||
Cheniere Energy, Inc.
|
|
100.00
|
|
|
163.27
|
|
|
86.39
|
|
|
96.08
|
|
|
124.86
|
|
|
137.27
|
|
S&P 500 Index
|
|
100.00
|
|
|
113.69
|
|
|
115.26
|
|
|
129.05
|
|
|
157.22
|
|
|
150.33
|
|
New Peer Group
|
|
100.00
|
|
|
96.50
|
|
|
77.10
|
|
|
105.03
|
|
|
109.89
|
|
|
86.74
|
|
Old Peer Group
|
|
100.00
|
|
|
121.50
|
|
|
98.35
|
|
|
120.50
|
|
|
126.61
|
|
|
116.16
|
|
ITEM 6.
|
SELECTED FINANCIAL DATA
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Revenues
|
|
$
|
7,987
|
|
|
$
|
5,601
|
|
|
$
|
1,283
|
|
|
$
|
271
|
|
|
$
|
268
|
|
Income (loss) from operations
|
|
2,024
|
|
|
1,388
|
|
|
(30
|
)
|
|
(449
|
)
|
|
(272
|
)
|
|||||
Interest expense, net of capitalized interest
|
|
(875
|
)
|
|
(747
|
)
|
|
(488
|
)
|
|
(322
|
)
|
|
(181
|
)
|
|||||
Net income (loss) attributable to common stockholders
|
|
471
|
|
|
(393
|
)
|
|
(610
|
)
|
|
(975
|
)
|
|
(548
|
)
|
|||||
Net income (loss) per share attributable to common stockholders—basic
|
|
$
|
1.92
|
|
|
$
|
(1.68
|
)
|
|
$
|
(2.67
|
)
|
|
$
|
(4.30
|
)
|
|
$
|
(2.44
|
)
|
Net income (loss) per share attributable to common stockholders—diluted
|
|
$
|
1.90
|
|
|
$
|
(1.68
|
)
|
|
$
|
(2.67
|
)
|
|
$
|
(4.30
|
)
|
|
$
|
(2.44
|
)
|
Weighted average number of common shares outstanding—basic
|
|
245.6
|
|
|
233.1
|
|
|
228.8
|
|
|
226.9
|
|
|
224.3
|
|
|||||
Weighted average number of common shares outstanding—diluted
|
|
248.0
|
|
|
233.1
|
|
|
228.8
|
|
|
226.9
|
|
|
224.3
|
|
|
|
December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Property, plant and equipment, net
|
|
$
|
27,245
|
|
|
$
|
23,978
|
|
|
$
|
20,635
|
|
|
$
|
16,194
|
|
|
$
|
9,247
|
|
Total assets
|
|
31,987
|
|
|
27,906
|
|
|
23,703
|
|
|
18,809
|
|
|
12,433
|
|
|||||
Current debt, net
|
|
239
|
|
|
—
|
|
|
247
|
|
|
1,673
|
|
|
—
|
|
|||||
Long-term debt, net
|
|
28,179
|
|
|
25,336
|
|
|
21,688
|
|
|
14,920
|
|
|
9,665
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
Overview of Business
|
•
|
Overview of Significant Events
|
•
|
Liquidity and Capital Resources
|
•
|
Contractual Obligations
|
•
|
Results of Operations
|
•
|
Off-Balance Sheet Arrangements
|
•
|
Summary of Critical Accounting Estimates
|
•
|
Recent Accounting Standards
|
•
|
In November 2018, SPL entered into an EPC contract with Bechtel Oil, Gas and Chemicals, Inc.
(“Bechtel”)
for Train 6 of the SPL Project. SPL also issued limited notices to proceed to Bechtel to commence early engineering, procurement and site works.
|
•
|
In May 2018, our board of directors made a positive
FID
with respect to
Stage 2
of the CCL Project and issued a full notice to proceed to Bechtel under the EPC contract for Stage 2.
|
•
|
In June 2018, we filed an application with the FERC with respect to
Corpus Christi Stage 3
, consisting of seven midscale liquefaction Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa and one LNG storage tank.
|
•
|
We entered into the following agreements:
|
◦
|
In December 2018, SPL entered into a 20-year SPA with PETRONAS LNG Ltd., subject to conditions precedent including FID of Train 6 of the
SPL Project
, for the sale of approximately 1.1 mtpa of LNG on a free on board (“FOB”) basis, with deliveries commencing following date of first commercial delivery for Train 6 of the
SPL Project
.
|
◦
|
In November 2018, we entered into a 24-year SPA with Polish state-owned oil and gas company Polskie Gornictwo Naftowe i Gazownictwo S.A. for the sale of approximately 1.45 mtpa of LNG on a delivered ex-ship (“DES”) basis. Deliveries will commence in 2019, with the full annual quantity commencing in 2023.
|
◦
|
In September 2018, we entered into a 15-year SPA with Vitol Inc. for the sale of approximately 0.7 mtpa of LNG beginning in 2018 on a FOB basis.
|
◦
|
In August 2018, we entered into a 25-year SPA with CPC Corporation, Taiwan for the sale of approximately 2.0 mtpa of LNG beginning in 2021 on a DES basis.
|
◦
|
In February 2018, we entered into two SPAs with PetroChina International Company Limited, a subsidiary of China National Petroleum Corporation, for the sale of approximately 1.2 mtpa of LNG through 2043 on both FOB and DES bases, with a portion of the supply beginning in 2018 and the balance beginning in 2023.
|
◦
|
In January 2018, we entered into a 15-year SPA with Trafigura Pte Ltd for the sale of approximately 1.0 mtpa of LNG beginning in 2019 on a FOB basis.
|
•
|
As of February 20, 2019, over
575
cumulative LNG cargoes have been produced, loaded and exported from the
SPL Project
and the
CCL Project
, with more than
270
cargoes in 2018 alone from the
SPL Project
, with deliveries to
32
countries and regions worldwide.
|
•
|
In November 2018 and December 2018, SPL and CCL commenced production and shipment of LNG commissioning cargoes from Train 5 of the
SPL Project
and Train 1 of the
CCL Project
, respectively.
|
•
|
We completed the following debt transactions:
|
◦
|
In December 2018, we amended and restated our existing revolving credit facility (“
Cheniere Revolving Credit Facility
”) to, among other changes, increase total commitments under the
Cheniere Revolving Credit Facility
to $1.25 billion, reduce the interest rate and extend the maturity date to December 2022. Borrowings will be used to fund the development of the
CCL Project
and, provided that certain conditions are met, for our general corporate purposes.
|
◦
|
In September 2018, Cheniere Partners issued an aggregate principal amount of $1.1 billion of 5.625% Senior Notes due 2026
(the “2026 CQP Senior Notes”)
. Net proceeds of the offering of approximately $1.1 billion, after deducting commissions, fees and expenses, were used to prepay all of the outstanding indebtedness under Cheniere Partners’ credit facilities
(the “CQP Credit Facilities”)
. As of
December 31, 2018
, only a $115 million revolving credit facility, which is currently undrawn, remains as part of the
CQP Credit Facilities
.
|
◦
|
In June 2018, CCH amended and restated its working capital facility
(“CCH Working Capital Facility”)
to increase total commitments under the
CCH Working Capital Facility
to
$1.2 billion
. Borrowings will be used for certain working capital requirements related to developing and placing the
CCL Project
into operations and for related business purposes.
|
◦
|
In May 2018, CCH amended and restated its existing credit facilities
(the “CCH Credit Facility”)
to increase total commitments under the
CCH Credit Facility
to $6.1 billion. Borrowings will be used to fund a portion of the costs of developing, constructing and placing into service the three Trains and the related facilities of the
CCL Project
and for related business purposes.
|
•
|
In September 2018, we closed the previously announced merger of Cheniere Holdings with our wholly owned subsidiary. As a result of the merger, all of the publicly-held shares of Cheniere Holdings not owned by us were canceled and shareholders received 0.4750 shares of our common stock for each publicly-held share of Cheniere Holdings.
|
•
|
We reached the following contractual milestones:
|
◦
|
In June 2018, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC
(“BG”)
relating to Train 3 of the
SPL Project
.
|
◦
|
In March 2018, the date of first commercial delivery was reached under the 20-year SPA with GAIL (India) Limited
(“GAIL”)
relating to Train 4 of the
SPL Project
.
|
•
|
SPL through project debt and borrowings and operating cash flows;
|
•
|
Cheniere Partners through operating cash flows from SPLNG, SPL and CTPL and debt or equity offerings;
|
•
|
CCH Group through project debt and borrowings and equity contributions from Cheniere; and
|
•
|
Cheniere through project financing, existing unrestricted cash, debt and equity offerings by us or our subsidiaries, operating cash flows, services fees from Cheniere Partners and our other subsidiaries and distributions from our investment in Cheniere Partners.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Cash and cash equivalents
|
$
|
981
|
|
|
$
|
722
|
|
Restricted cash designated for the following purposes:
|
|
|
|
||||
SPL Project
|
756
|
|
|
544
|
|
||
Cheniere Partners and cash held by guarantor subsidiaries
|
785
|
|
|
1,045
|
|
||
CCL Project
|
289
|
|
|
227
|
|
||
Other
|
345
|
|
|
75
|
|
||
Available commitments under the following credit facilities:
|
|
|
|
||||
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
|
775
|
|
|
470
|
|
||
CQP Credit Facilities
|
115
|
|
|
220
|
|
||
CCH Credit Facility
|
982
|
|
|
2,087
|
|
||
CCH Working Capital Facility
|
716
|
|
|
186
|
|
||
$1.25 billion Cheniere Revolving Credit Facility
|
1,250
|
|
|
750
|
|
|
|
SPL Train 5
|
|
Overall project completion percentage
|
|
99.7%
|
|
Completion percentage of:
|
|
|
|
Engineering
|
|
100%
|
|
Procurement
|
|
100%
|
|
Subcontract work
|
|
98.0%
|
|
Construction
|
|
99.6%
|
|
Date of expected substantial completion
|
|
1Q 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,
|
||||||
|
|
2018
|
|
2017
|
||||
Senior notes (1)
|
|
$
|
16,250
|
|
|
$
|
15,150
|
|
Credit facilities outstanding balance (2)
|
|
—
|
|
|
1,090
|
|
||
Letters of credit issued (3)
|
|
425
|
|
|
730
|
|
||
Available commitments under credit facilities (3)
|
|
775
|
|
|
470
|
|
||
Total capital resources from borrowings and available commitments (4)
|
|
$
|
17,450
|
|
|
$
|
17,440
|
|
|
(1)
|
Includes SPL’s 5.625% Senior Secured Notes due 2021, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026
(the “2026 SPL Senior Notes”)
, 5.00% Senior Secured Notes due 2027
(the “2027 SPL Senior Notes”)
, 4.200% Senior Secured Notes due 2028
(the “2028 SPL Senior Notes”)
and 5.00% Senior Secured Notes due 2037
(the “2037 SPL Senior Notes”)
(collectively, the “SPL Senior Notes”)
and Cheniere Partners’
2025 CQP Senior Notes
and
2026 CQP Senior Notes
.
|
(2)
|
Includes outstanding balance under the
SPL Working Capital Facility
and CTPL and SPLNG tranche term loans outstanding under the CQP Credit Facilities.
|
(3)
|
Consists of
SPL Working Capital Facility
. Does not include the letters of credit issued or available commitments under the
CQP Credit Facilities
, which are not specifically for the Sabine Pass LNG Terminal.
|
(4)
|
Does not include Cheniere’s additional borrowings from the
2021 Cheniere Convertible Unsecured Notes
and the
2045 Cheniere Convertible Senior Notes
, which may be used for the Sabine Pass LNG Terminal.
|
|
CCL Stage 1
|
|
CCL Stage 2
|
||
Overall project completion percentage
|
96.7%
|
|
42.0%
|
||
Completion percentage of:
|
|
|
|
|
|
Engineering
|
100%
|
|
87.0%
|
||
Procurement
|
100%
|
|
63.0%
|
||
Subcontract work
|
89.5%
|
|
8.5%
|
||
Construction
|
93.1%
|
|
11.7%
|
||
Expected date of substantial completion
|
Train 1
|
1Q 2019
|
|
Train 3
|
2H 2021
|
|
Train 2
|
2H 2019
|
|
|
|
•
|
CCL Project—
FTA countries
for a 25-year term and to
non-FTA countries
for a 20-year term up to a combined total of the equivalent of 767
Bcf/yr
(approximately 15 mtpa) of natural gas.
|
•
|
Corpus Christi Stage 3
—FTA countries for a 20-year term in an amount equivalent to 514 Bcf/yr (approximately 10 mtpa) of natural gas (the “Stage 3 FTA”). The application for authorization to export that same 514 Bcf/yr of domestically produced LNG by vessel to non-FTA countries is currently pending before the DOE (the “Stage 3 Non-FTA”).
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Senior notes (1)
|
|
$
|
4,250
|
|
|
$
|
4,250
|
|
11.0% Convertible Senior Secured Notes due 2025 (2)
|
|
1,000
|
|
|
1,000
|
|
||
Credit facilities outstanding balance (3)
|
|
5,324
|
|
|
2,485
|
|
||
Letters of credit issued (3)
|
|
316
|
|
|
164
|
|
||
Available commitments under credit facilities (3)
|
|
1,698
|
|
|
2,273
|
|
||
Total capital resources from borrowings and available commitments (4)
|
|
$
|
12,588
|
|
|
$
|
10,172
|
|
|
(1)
|
Includes CCH’s 7.000% Senior Secured Notes due 2024
(the “2024 CCH Senior Notes”)
, 5.875% Senior Secured Notes due 2025
(the “2025 CCH Senior Notes”)
and 5.125% Senior Secured Notes due 2027
(the “2027 CCH Senior Notes”)
(collectively, the “CCH Senior Notes”)
.
|
(2)
|
Aggregate original principal amount before debt discount and debt issuance costs.
|
(3)
|
Includes
CCH Credit Facility
and
CCH Working Capital Facility
.
|
(4)
|
Does not include Cheniere’s additional borrowings from
2021 Cheniere Convertible Unsecured Notes
,
2045 Cheniere Convertible Senior Notes
and
Cheniere Revolving Credit Facility
, which may be used for the
CCL Project
.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Operating cash flows
|
$
|
1,990
|
|
|
$
|
1,231
|
|
|
$
|
(404
|
)
|
Investing cash flows
|
(3,654
|
)
|
|
(3,381
|
)
|
|
(4,413
|
)
|
|||
Financing cash flows
|
2,207
|
|
|
2,936
|
|
|
4,908
|
|
|||
|
|
|
|
|
|
||||||
Net increase in cash, cash equivalents and restricted cash
|
543
|
|
|
786
|
|
|
91
|
|
|||
Cash, cash equivalents and restricted cash—beginning of period
|
2,613
|
|
|
1,827
|
|
|
1,736
|
|
|||
Cash, cash equivalents and restricted cash—end of period
|
$
|
3,156
|
|
|
$
|
2,613
|
|
|
$
|
1,827
|
|
•
|
issuance of an aggregate principal amount of $1.1 billion of the
2026 CQP Senior Notes
, which was used to prepay $1.1 billion of the outstanding borrowings under the
CQP Credit Facilities
;
|
•
|
$2.9 billion
of borrowings and
$281 million
in repayments under the
CCH Credit Facility
;
|
•
|
$188 million
of borrowings and
$20 million
in repayments under the
CCH Working Capital Facility
;
|
•
|
$71 million
of net borrowings related to our Cheniere Marketing trade financing facilities;
|
•
|
$66 million
of debt issuance costs related to up-front fees paid upon the closing of these transactions;
|
•
|
$17 million
in debt extinguishment costs related to the prepayments of the
CQP Credit Facilities
and the
CCH Credit Facility
;
|
•
|
$576 million
of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings;
|
•
|
$20 million
paid for tax withholdings for share-based compensation; and
|
•
|
$7 million of transaction costs to acquire additional interest of Cheniere Holdings.
|
•
|
issuances of SPL’s senior notes for an aggregate principal amount $2.15 billion;
|
•
|
$55 million of borrowings and $369 million of repayments made under the credit facilities SPL entered into in June 2015
(the “SPL Credit Facilities”)
;
|
•
|
$110 million of borrowings and $334 million of repayments made under the
SPL Working Capital Facility
;
|
•
|
$1.5 billion of borrowings under the
CCH Credit Facility
;
|
•
|
issuance of an aggregate principal amount of
$1.5 billion
of the
2027 CCH Senior Notes
, which was used to prepay $1.4 billion of outstanding borrowings under the
CCH Credit Facility
;
|
•
|
$24 million of borrowings and $24 million of repayments made under the
CCH 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
CQP Credit Facilities
;
|
•
|
$24 million in net repayments made under the Cheniere Marketing trade finance facilities;
|
•
|
$89 million
of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions;
|
•
|
$185 million
of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; and
|
•
|
$12 million
paid for tax withholdings for share-based compensation.
|
•
|
$2.6 billion of borrowings under the
CQP Credit Facilities
used to prepay the $400 million CTPL term loan facility and redeem and repay $2.1 billion of the senior notes previously issued by SPLNG;
|
•
|
$2.0 billion of borrowings under the
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
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
SPL Credit Facilities
and pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project;
|
•
|
$474 million of borrowings and $265 million of repayments made under the SPL Working Capital Facility;
|
•
|
$2.1 billion of borrowings under the
CCH Credit Facility
;
|
•
|
issuances of aggregate principal amounts of $1.25 billion of the 2024 CCH Senior Notes and $1.5 billion of the 2025 CCH Senior Notes in December 2016, which were used to prepay $2.4 billion of the outstanding borrowings under the
CCH Credit Facility
;
|
•
|
$24 million in net borrowings under the Cheniere Marketing trade finance facilities;
|
•
|
$172 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;
|
•
|
$80 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; and
|
•
|
$20 million paid for tax withholdings for share-based compensation.
|
|
|
Payments Due By Period (1)
|
||||||||||||||||||
|
|
Total
|
|
2019
|
|
2020 - 2021
|
|
2022 - 2023
|
|
Thereafter
|
||||||||||
Debt (2)
|
|
$
|
29,395
|
|
|
$
|
168
|
|
|
$
|
3,368
|
|
|
$
|
2,500
|
|
|
$
|
23,359
|
|
Interest payments (2)
|
|
10,258
|
|
|
1,480
|
|
|
3,102
|
|
|
2,776
|
|
|
2,900
|
|
|||||
Construction obligations (3)
|
|
1,525
|
|
|
980
|
|
|
545
|
|
|
—
|
|
|
—
|
|
|||||
Purchase obligations (4)
|
|
11,848
|
|
|
3,218
|
|
|
3,444
|
|
|
1,828
|
|
|
3,358
|
|
|||||
Capital lease obligations (5)
|
|
98
|
|
|
5
|
|
|
10
|
|
|
10
|
|
|
73
|
|
|||||
Operating lease obligations (6)
|
|
2,329
|
|
|
380
|
|
|
422
|
|
|
528
|
|
|
999
|
|
|||||
Obligations to related parties (7)
|
|
96
|
|
|
2
|
|
|
19
|
|
|
19
|
|
|
56
|
|
|||||
Other obligations (8)
|
|
286
|
|
|
20
|
|
|
63
|
|
|
74
|
|
|
129
|
|
|||||
Total
|
|
$
|
55,835
|
|
|
$
|
6,253
|
|
|
$
|
10,973
|
|
|
$
|
7,735
|
|
|
$
|
30,874
|
|
|
(1)
|
Agreements in force as of
December 31, 2018
that have terms dependent on project milestone dates are based on the estimated dates as of
December 31, 2018
.
|
(2)
|
Based on the total debt balance, scheduled maturities and interest rates in effect at
December 31, 2018
. See
Note 12—Debt
of our Notes to Consolidated Financial Statements.
|
(3)
|
Construction obligations primarily relate to the EPC contracts for the
SPL Project
and the
CCL Project
. The estimated remaining cost pursuant to our EPC contracts as of
December 31, 2018
is included for Trains with respect to which we have made an FID to commence construction; the EPC contract termination amount is included for Trains with respect to which we have not made an FID. A discussion of these obligations can be found at
Note 19—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
SPL Project
and the
CCL Project
. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly.
|
(5)
|
Capital lease obligations consist of tug leases related to the
CCL Project
, as further discussed in
Note 18—Leases
of our Notes to Consolidated Financial Statements.
|
(6)
|
Operating lease obligations primarily relate to LNG vessel time charters, land sites related to the
SPL Project
and the
CCL Project
and corporate office leases, and includes payments for certain non-lease components. A discussion of these obligations can be found in
Note 18—Leases
of our Notes to Consolidated Financial Statements.
|
(7)
|
Obligations to Midship Pipeline Company, LLC under CCL’s transportation precedent agreement to secure firm pipeline transportation capacity for the
CCL Project
.
|
(8)
|
Other obligations primarily relate to agreements with certain local taxing jurisdictions, and are based on estimated tax obligations as of
December 31, 2018
. Also included are payments for non-lease components related to our capital lease obligations.
|
|
Year Ended December 31, 2018
|
||||
(in TBtu)
|
Operational
|
|
Commissioning
|
||
Volumes loaded during the current period
|
955
|
|
|
20
|
|
Volumes loaded during the prior period but recognized during the current period
|
43
|
|
|
—
|
|
Less: volumes loaded during the current period and in transit at the end of the period
|
(25
|
)
|
|
(3
|
)
|
Total volumes recognized in the current period
|
973
|
|
|
17
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions)
|
2018
|
|
2017
|
|
Change
|
|
2016
|
|
Change
|
||||||||||
LNG revenues
|
$
|
7,572
|
|
|
$
|
5,317
|
|
|
$
|
2,255
|
|
|
$
|
1,016
|
|
|
$
|
4,301
|
|
Regasification revenues
|
261
|
|
|
260
|
|
|
1
|
|
|
259
|
|
|
1
|
|
|||||
Other revenues
|
142
|
|
|
21
|
|
|
121
|
|
|
8
|
|
|
13
|
|
|||||
Other—related party
|
12
|
|
|
3
|
|
|
9
|
|
|
—
|
|
|
3
|
|
|||||
Total revenues
|
$
|
7,987
|
|
|
$
|
5,601
|
|
|
$
|
2,386
|
|
|
$
|
1,283
|
|
|
$
|
4,318
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
LNG revenues
(in millions)
:
|
|
|
|
|
|
||||||
LNG from the SPL Project sold under SPL’s third party long-term SPAs
|
$
|
4,677
|
|
|
$
|
2,588
|
|
|
$
|
458
|
|
LNG from the SPL Project sold by our integrated marketing function
|
1,987
|
|
|
1,756
|
|
|
319
|
|
|||
LNG procured from third parties
|
745
|
|
|
981
|
|
|
236
|
|
|||
Other revenues and derivative gains (losses)
|
163
|
|
|
(8
|
)
|
|
3
|
|
|||
Total LNG revenues
|
$
|
7,572
|
|
|
$
|
5,317
|
|
|
$
|
1,016
|
|
|
|
|
|
|
|
||||||
Volumes sold as LNG revenues
(in TBtu)
:
|
|
|
|
|
|
||||||
LNG from the SPL Project sold under SPL’s third party long-term SPAs
|
750
|
|
|
427
|
|
|
85
|
|
|||
LNG from the SPL Project sold by our integrated marketing function
|
223
|
|
|
233
|
|
|
47
|
|
|||
LNG procured from third parties
|
84
|
|
|
98
|
|
|
26
|
|
|||
Total volumes sold as LNG revenues
|
1,057
|
|
|
758
|
|
|
158
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions)
|
2018
|
|
2017
|
|
Change
|
|
2016
|
|
Change
|
||||||||||
Cost of sales
|
$
|
4,597
|
|
|
$
|
3,120
|
|
|
$
|
1,477
|
|
|
$
|
582
|
|
|
$
|
2,538
|
|
Operating and maintenance expense
|
613
|
|
|
446
|
|
|
167
|
|
|
216
|
|
|
230
|
|
|||||
Development expense
|
7
|
|
|
10
|
|
|
(3
|
)
|
|
7
|
|
|
3
|
|
|||||
Selling, general and administrative expense
|
289
|
|
|
256
|
|
|
33
|
|
|
260
|
|
|
(4
|
)
|
|||||
Depreciation and amortization expense
|
449
|
|
|
356
|
|
|
93
|
|
|
174
|
|
|
182
|
|
|||||
Restructuring expense
|
—
|
|
|
6
|
|
|
(6
|
)
|
|
61
|
|
|
(55
|
)
|
|||||
Impairment expense and loss on disposal of assets
|
8
|
|
|
19
|
|
|
(11
|
)
|
|
13
|
|
|
6
|
|
|||||
Total operating costs and expenses
|
$
|
5,963
|
|
|
$
|
4,213
|
|
|
$
|
1,750
|
|
|
$
|
1,313
|
|
|
$
|
2,900
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions)
|
2018
|
|
2017
|
|
Change
|
|
2016
|
|
Change
|
||||||||||
Interest expense, net of capitalized interest
|
$
|
875
|
|
|
$
|
747
|
|
|
$
|
128
|
|
|
$
|
488
|
|
|
$
|
259
|
|
Loss on modification or extinguishment of debt
|
27
|
|
|
100
|
|
|
(73
|
)
|
|
135
|
|
|
(35
|
)
|
|||||
Derivative loss (gain), net
|
(57
|
)
|
|
(7
|
)
|
|
(50
|
)
|
|
10
|
|
|
(17
|
)
|
|||||
Other income
|
(48
|
)
|
|
(18
|
)
|
|
(30
|
)
|
|
—
|
|
|
(18
|
)
|
|||||
Total other expense
|
$
|
797
|
|
|
$
|
822
|
|
|
$
|
(25
|
)
|
|
$
|
633
|
|
|
$
|
189
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions)
|
2018
|
|
2017
|
|
Change
|
|
2016
|
|
Change
|
||||||||||
Income (loss) before income taxes and non-controlling interest
|
$
|
1,227
|
|
|
$
|
566
|
|
|
$
|
661
|
|
|
$
|
(663
|
)
|
|
$
|
1,229
|
|
Income tax provision
|
27
|
|
|
3
|
|
|
24
|
|
|
2
|
|
|
1
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Effective tax rate
|
2.2
|
%
|
|
0.5
|
%
|
|
|
|
(0.3
|
)%
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions)
|
2018
|
|
2017
|
|
Change
|
|
2016
|
|
Change
|
||||||||||
Net income (loss) attributable to non-controlling interest
|
$
|
729
|
|
|
$
|
956
|
|
|
$
|
(227
|
)
|
|
$
|
(55
|
)
|
|
$
|
1,011
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Fair Value
|
|
Change in Fair Value
|
|
Fair Value
|
|
Change in Fair Value
|
||||||||
Liquefaction Supply Derivatives
|
$
|
(42
|
)
|
|
$
|
6
|
|
|
$
|
55
|
|
|
$
|
5
|
|
LNG Trading Derivatives
|
(24
|
)
|
|
9
|
|
|
(8
|
)
|
|
2
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Fair Value
|
|
Change in Fair Value
|
|
Fair Value
|
|
Change in Fair Value
|
||||||||
CCH Interest Rate Derivatives
|
$
|
18
|
|
|
$
|
37
|
|
|
$
|
(32
|
)
|
|
$
|
44
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Fair Value
|
|
Change in Fair Value
|
|
Fair Value
|
|
Change in Fair Value
|
||||||||
FX Derivatives
|
$
|
15
|
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
|
|
|
|
|
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,
|
||||||
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
|
||||
Current assets
|
|
|
|
||||
Cash and cash equivalents
|
$
|
981
|
|
|
$
|
722
|
|
Restricted cash
|
2,175
|
|
|
1,880
|
|
||
Accounts and other receivables
|
581
|
|
|
369
|
|
||
Accounts receivable—related party
|
4
|
|
|
2
|
|
||
Inventory
|
316
|
|
|
243
|
|
||
Derivative assets
|
63
|
|
|
57
|
|
||
Other current assets
|
114
|
|
|
96
|
|
||
Total current assets
|
4,234
|
|
|
3,369
|
|
||
|
|
|
|
||||
Non-current restricted cash
|
—
|
|
|
11
|
|
||
Property, plant and equipment, net
|
27,245
|
|
|
23,978
|
|
||
Debt issuance costs, net
|
72
|
|
|
149
|
|
||
Non-current derivative assets
|
54
|
|
|
34
|
|
||
Goodwill
|
77
|
|
|
77
|
|
||
Other non-current assets, net
|
305
|
|
|
288
|
|
||
Total assets
|
$
|
31,987
|
|
|
$
|
27,906
|
|
|
|
|
|
||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
||
Current liabilities
|
|
|
|
|
|
||
Accounts payable
|
$
|
58
|
|
|
$
|
25
|
|
Accrued liabilities
|
1,169
|
|
|
1,078
|
|
||
Current debt
|
239
|
|
|
—
|
|
||
Deferred revenue
|
139
|
|
|
111
|
|
||
Derivative liabilities
|
128
|
|
|
37
|
|
||
Other current liabilities
|
9
|
|
|
—
|
|
||
Total current liabilities
|
1,742
|
|
|
1,251
|
|
||
|
|
|
|
||||
Long-term debt, net
|
28,179
|
|
|
25,336
|
|
||
Non-current capital lease obligations
|
57
|
|
|
—
|
|
||
Non-current derivative liabilities
|
22
|
|
|
19
|
|
||
Other non-current liabilities
|
58
|
|
|
60
|
|
||
|
|
|
|
||||
Commitments and contingencies (see Note 19)
|
|
|
|
|
|
||
|
|
|
|
||||
Stockholders’ equity
|
|
|
|
|
|
||
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued
|
—
|
|
|
—
|
|
||
Common stock, $0.003 par value
|
|
|
|
|
|||
Authorized: 480.0 million shares at December 31, 2018 and 2017
|
|
|
|
||||
Issued: 269.8 million shares and 250.1 million shares at December 31, 2018 and 2017, respectively
|
|
|
|
|
|
||
Outstanding: 257.0 million shares and 237.6 million shares at December 31, 2018 and 2017, respectively
|
1
|
|
|
1
|
|
||
Treasury stock: 12.8 million shares and 12.5 million shares at December 31, 2018 and 2017, respectively, at cost
|
(406
|
)
|
|
(386
|
)
|
||
Additional paid-in-capital
|
4,035
|
|
|
3,248
|
|
||
Accumulated deficit
|
(4,156
|
)
|
|
(4,627
|
)
|
||
Total stockholders’ deficit
|
(526
|
)
|
|
(1,764
|
)
|
||
Non-controlling interest
|
2,455
|
|
|
3,004
|
|
||
Total equity
|
1,929
|
|
|
1,240
|
|
||
Total liabilities and equity
|
$
|
31,987
|
|
|
$
|
27,906
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues
|
|
|
|
|
|
||||||
LNG revenues
|
$
|
7,572
|
|
|
$
|
5,317
|
|
|
$
|
1,016
|
|
Regasification revenues
|
261
|
|
|
260
|
|
|
259
|
|
|||
Other revenues
|
142
|
|
|
21
|
|
|
8
|
|
|||
Other—related party
|
12
|
|
|
3
|
|
|
—
|
|
|||
Total revenues
|
7,987
|
|
|
5,601
|
|
|
1,283
|
|
|||
|
|
|
|
|
|
||||||
Operating costs and expenses
|
|
|
|
|
|
||||||
Cost of sales (excluding depreciation and amortization expense shown separately below)
|
4,597
|
|
|
3,120
|
|
|
582
|
|
|||
Operating and maintenance expense
|
613
|
|
|
446
|
|
|
216
|
|
|||
Development expense
|
7
|
|
|
10
|
|
|
7
|
|
|||
Selling, general and administrative expense
|
289
|
|
|
256
|
|
|
260
|
|
|||
Depreciation and amortization expense
|
449
|
|
|
356
|
|
|
174
|
|
|||
Restructuring expense
|
—
|
|
|
6
|
|
|
61
|
|
|||
Impairment expense and loss on disposal of assets
|
8
|
|
|
19
|
|
|
13
|
|
|||
Total operating costs and expenses
|
5,963
|
|
|
4,213
|
|
|
1,313
|
|
|||
|
|
|
|
|
|
||||||
Income (loss) from operations
|
2,024
|
|
|
1,388
|
|
|
(30
|
)
|
|||
|
|
|
|
|
|
||||||
Other income (expense)
|
|
|
|
|
|
||||||
Interest expense, net of capitalized interest
|
(875
|
)
|
|
(747
|
)
|
|
(488
|
)
|
|||
Loss on modification or extinguishment of debt
|
(27
|
)
|
|
(100
|
)
|
|
(135
|
)
|
|||
Derivative gain (loss), net
|
57
|
|
|
7
|
|
|
(10
|
)
|
|||
Other income
|
48
|
|
|
18
|
|
|
—
|
|
|||
Total other expense
|
(797
|
)
|
|
(822
|
)
|
|
(633
|
)
|
|||
|
|
|
|
|
|
||||||
Income (loss) before income taxes and non-controlling interest
|
1,227
|
|
|
566
|
|
|
(663
|
)
|
|||
Income tax provision
|
(27
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|||
Net income (loss)
|
1,200
|
|
|
563
|
|
|
(665
|
)
|
|||
Less: net income (loss) attributable to non-controlling interest
|
729
|
|
|
956
|
|
|
(55
|
)
|
|||
Net income (loss) attributable to common stockholders
|
$
|
471
|
|
|
$
|
(393
|
)
|
|
$
|
(610
|
)
|
|
|
|
|
|
|
|
|
||||
Net income (loss) per share attributable to common stockholders—basic (1)
|
$
|
1.92
|
|
|
$
|
(1.68
|
)
|
|
$
|
(2.67
|
)
|
Net income (loss) per share attributable to common stockholders—diluted (1)
|
$
|
1.90
|
|
|
$
|
(1.68
|
)
|
|
$
|
(2.67
|
)
|
|
|
|
|
|
|
|
|
||||
Weighted average number of common shares outstanding—basic
|
245.6
|
|
|
233.1
|
|
|
228.8
|
|
|||
Weighted average number of common shares outstanding—diluted
|
248.0
|
|
|
233.1
|
|
|
228.8
|
|
|
|
|
|
|
(1)
|
Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.
|
|
Total Stockholders’ Equity
|
|
|
|
|||||||||||||||||||||||||
|
Common Stock
|
|
Treasury Stock
|
|
Additional Paid-in Capital
|
|
Accumulated Deficit
|
|
Non-controlling Interest
|
|
Total
Equity
|
||||||||||||||||||
|
Shares
|
|
Par Value Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
||||||||||||||||||
Balance at December 31, 2015
|
235.6
|
|
|
$
|
1
|
|
|
11.6
|
|
|
$
|
(354
|
)
|
|
$
|
3,076
|
|
|
$
|
(3,624
|
)
|
|
$
|
2,464
|
|
|
$
|
1,563
|
|
Issuances of restricted stock
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Issuance of stock to acquire additional interest in Cheniere Holdings
|
3.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
94
|
|
|
—
|
|
|
(94
|
)
|
|
—
|
|
||||||
Forfeitures of restricted stock
|
(0.4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
40
|
|
||||||
Shares repurchased related to share-based compensation
|
(0.6
|
)
|
|
—
|
|
|
0.6
|
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
||||||
Loss attributable to non-controlling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|
(55
|
)
|
||||||
Equity portion of convertible notes, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||
Distributions and dividends to non-controlling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(80
|
)
|
|
(80
|
)
|
||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(610
|
)
|
|
—
|
|
|
(610
|
)
|
||||||
Balance at December 31, 2016
|
238.0
|
|
|
1
|
|
|
12.2
|
|
|
(374
|
)
|
|
3,211
|
|
|
(4,234
|
)
|
|
2,235
|
|
|
839
|
|
||||||
Issuances of restricted stock
|
0.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Issuance of stock to acquire additional interest in Cheniere Holdings
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
||||||
Forfeitures of restricted stock
|
(0.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
—
|
|
|
—
|
|
|
34
|
|
||||||
Shares repurchased related to share-based compensation
|
(0.3
|
)
|
|
—
|
|
|
0.3
|
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
||||||
Net income attributable to non-controlling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
956
|
|
|
956
|
|
||||||
Equity portion of convertible notes, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||
Distributions and dividends to non-controlling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(185
|
)
|
|
(185
|
)
|
||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(393
|
)
|
|
—
|
|
|
(393
|
)
|
||||||
Balance at December 31, 2017
|
237.6
|
|
|
1
|
|
|
12.5
|
|
|
(386
|
)
|
|
3,248
|
|
|
(4,627
|
)
|
|
3,004
|
|
|
1,240
|
|
||||||
Vesting of restricted stock units
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Issuance of stock to acquire additional interest in Cheniere Holdings and other merger related adjustments
|
19.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
694
|
|
|
—
|
|
|
(702
|
)
|
|
(8
|
)
|
||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
90
|
|
|
—
|
|
|
—
|
|
|
90
|
|
||||||
Shares repurchased related to share-based compensation
|
(0.3
|
)
|
|
—
|
|
|
0.3
|
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
||||||
Net income attributable to non-controlling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
729
|
|
|
729
|
|
||||||
Equity portion of convertible notes, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||||
Distributions and dividends to non-controlling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(576
|
)
|
|
(576
|
)
|
||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
471
|
|
|
—
|
|
|
471
|
|
||||||
Balance at December 31, 2018
|
257.0
|
|
|
$
|
1
|
|
|
12.8
|
|
|
$
|
(406
|
)
|
|
$
|
4,035
|
|
|
$
|
(4,156
|
)
|
|
$
|
2,455
|
|
|
$
|
1,929
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
1,200
|
|
|
$
|
563
|
|
|
$
|
(665
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization expense
|
449
|
|
|
356
|
|
|
174
|
|
|||
Share-based compensation expense
|
113
|
|
|
91
|
|
|
101
|
|
|||
Non-cash interest expense
|
74
|
|
|
75
|
|
|
77
|
|
|||
Amortization of debt issuance costs, deferred commitment fees, premium and discount
|
69
|
|
|
69
|
|
|
62
|
|
|||
Loss on modification or extinguishment of debt
|
27
|
|
|
100
|
|
|
135
|
|
|||
Total losses (gains) on derivatives, net
|
51
|
|
|
62
|
|
|
(28
|
)
|
|||
Net cash provided by (used for) settlement of derivative instruments
|
17
|
|
|
(106
|
)
|
|
(45
|
)
|
|||
Impairment expense and loss on disposal of assets
|
8
|
|
|
19
|
|
|
13
|
|
|||
Other
|
(10
|
)
|
|
(4
|
)
|
|
4
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
Accounts and other receivables
|
(131
|
)
|
|
(139
|
)
|
|
(207
|
)
|
|||
Accounts receivable—related party
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|||
Inventory
|
(73
|
)
|
|
(73
|
)
|
|
(119
|
)
|
|||
Accounts payable and accrued liabilities
|
188
|
|
|
225
|
|
|
64
|
|
|||
Deferred revenue
|
26
|
|
|
34
|
|
|
42
|
|
|||
Other, net
|
(16
|
)
|
|
(39
|
)
|
|
(12
|
)
|
|||
Net cash provided by (used in) operating activities
|
1,990
|
|
|
1,231
|
|
|
(404
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities
|
|
|
|
|
|
||||||
Property, plant and equipment, net
|
(3,643
|
)
|
|
(3,357
|
)
|
|
(4,356
|
)
|
|||
Investment in equity method investment
|
(25
|
)
|
|
(41
|
)
|
|
—
|
|
|||
Other
|
14
|
|
|
17
|
|
|
(57
|
)
|
|||
Net cash used in investing activities
|
(3,654
|
)
|
|
(3,381
|
)
|
|
(4,413
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities
|
|
|
|
|
|
||||||
Proceeds from issuances of debt
|
4,285
|
|
|
6,854
|
|
|
12,865
|
|
|||
Repayments of debt
|
(1,391
|
)
|
|
(3,632
|
)
|
|
(7,671
|
)
|
|||
Debt issuance and deferred financing costs
|
(66
|
)
|
|
(89
|
)
|
|
(172
|
)
|
|||
Debt extinguishment costs
|
(17
|
)
|
|
—
|
|
|
(14
|
)
|
|||
Distributions and dividends to non-controlling interest
|
(576
|
)
|
|
(185
|
)
|
|
(80
|
)
|
|||
Payments related to tax withholdings for share-based compensation
|
(20
|
)
|
|
(12
|
)
|
|
(20
|
)
|
|||
Other
|
(8
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash provided by financing activities
|
2,207
|
|
|
2,936
|
|
|
4,908
|
|
|||
|
|
|
|
|
|
||||||
Net increase in cash, cash equivalents and restricted cash
|
543
|
|
|
786
|
|
|
91
|
|
|||
Cash, cash equivalents and restricted cash—beginning of period
|
2,613
|
|
|
1,827
|
|
|
1,736
|
|
|||
Cash, cash equivalents and restricted cash—end of period
|
$
|
3,156
|
|
|
$
|
2,613
|
|
|
$
|
1,827
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Cash and cash equivalents
|
$
|
981
|
|
|
$
|
722
|
|
Restricted cash
|
2,175
|
|
|
1,880
|
|
||
Non-current restricted cash
|
—
|
|
|
11
|
|
||
Total cash, cash equivalents and restricted cash
|
$
|
3,156
|
|
|
$
|
2,613
|
|
•
|
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,
|
||||||
|
|
2018
|
|
2017
|
||||
Current restricted cash
|
|
|
|
|
||||
SPL Project
|
|
$
|
756
|
|
|
$
|
544
|
|
Cheniere Partners and cash held by guarantor subsidiaries
|
|
785
|
|
|
1,045
|
|
||
CCL Project
|
|
289
|
|
|
227
|
|
||
Cash held by our subsidiaries restricted to Cheniere
|
|
345
|
|
|
64
|
|
||
Total current restricted cash
|
|
$
|
2,175
|
|
|
$
|
1,880
|
|
|
|
|
|
|
||||
Non-current restricted cash
|
|
|
|
|
||||
Other
|
|
$
|
—
|
|
|
$
|
11
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Trade receivables
|
|
|
|
|
||||
SPL
|
|
$
|
330
|
|
|
$
|
185
|
|
Cheniere Marketing
|
|
205
|
|
|
163
|
|
||
Other accounts receivable
|
|
46
|
|
|
21
|
|
||
Total accounts and other receivables
|
|
$
|
581
|
|
|
$
|
369
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Natural gas
|
|
$
|
30
|
|
|
$
|
17
|
|
LNG
|
|
24
|
|
|
44
|
|
||
LNG in-transit
|
|
173
|
|
|
130
|
|
||
Materials and other
|
|
89
|
|
|
52
|
|
||
Total inventory
|
|
$
|
316
|
|
|
$
|
243
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
LNG terminal costs
|
|
|
|
|
||||
LNG terminal and interconnecting pipeline facilities
|
|
$
|
13,386
|
|
|
$
|
12,687
|
|
LNG site and related costs
|
|
86
|
|
|
86
|
|
||
LNG terminal construction-in-process
|
|
14,864
|
|
|
11,932
|
|
||
Accumulated depreciation
|
|
(1,299
|
)
|
|
(882
|
)
|
||
Total LNG terminal costs, net
|
|
27,037
|
|
|
23,823
|
|
||
Fixed assets and other
|
|
|
|
|
|
|
||
Computer and office equipment
|
|
17
|
|
|
14
|
|
||
Furniture and fixtures
|
|
22
|
|
|
19
|
|
||
Computer software
|
|
100
|
|
|
92
|
|
||
Leasehold improvements
|
|
41
|
|
|
41
|
|
||
Land
|
|
59
|
|
|
59
|
|
||
Other
|
|
21
|
|
|
16
|
|
||
Accumulated depreciation
|
|
(111
|
)
|
|
(86
|
)
|
||
Total fixed assets and other, net
|
|
149
|
|
|
155
|
|
||
Assets under capital lease
|
|
|
|
|
||||
Tug vessels
|
|
60
|
|
|
—
|
|
||
Accumulated depreciation
|
|
(1
|
)
|
|
—
|
|
||
Total assets under capital lease, net
|
|
59
|
|
|
—
|
|
||
Property, plant and equipment, net
|
|
$
|
27,245
|
|
|
$
|
23,978
|
|
Components
|
|
Useful life (yrs)
|
LNG storage tanks
|
|
50
|
Natural gas pipeline facilities
|
|
40
|
Marine berth, electrical, facility and roads
|
|
35
|
Water pipelines
|
|
30
|
Regasification processing equipment
|
|
30
|
Sendout pumps
|
|
20
|
Liquefaction processing equipment
|
|
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”)
;
|
•
|
commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the
SPL Project
and the
CCL 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”)
;
|
•
|
financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG
(“LNG Trading Derivatives”)
; and
|
•
|
FX contracts to hedge exposure to currency risk associated with both LNG Trading Derivatives and operations in countries outside of the United States
(“FX Derivatives”)
.
|
|
Fair Value Measurements as of
|
||||||||||||||||||||||||||||||
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||||||||||
|
Quoted Prices in Active Markets
(Level 1) |
|
Significant Other Observable Inputs
(Level 2) |
|
Significant Unobservable Inputs
(Level 3) |
|
Total
|
|
Quoted Prices in Active Markets
(Level 1) |
|
Significant Other Observable Inputs
(Level 2) |
|
Significant Unobservable Inputs
(Level 3) |
|
Total
|
||||||||||||||||
CCH Interest Rate Derivatives asset (liability)
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
(32
|
)
|
|
$
|
—
|
|
|
$
|
(32
|
)
|
CQP Interest Rate Derivatives asset
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
21
|
|
||||||||
Liquefaction Supply Derivatives asset (liability)
|
6
|
|
|
(19
|
)
|
|
(29
|
)
|
|
(42
|
)
|
|
2
|
|
|
10
|
|
|
43
|
|
|
55
|
|
||||||||
LNG Trading Derivatives asset (liability)
|
1
|
|
|
(25
|
)
|
|
—
|
|
|
(24
|
)
|
|
(13
|
)
|
|
5
|
|
|
—
|
|
|
(8
|
)
|
||||||||
FX Derivatives asset (liability)
|
—
|
|
|
15
|
|
|
—
|
|
|
15
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
|
Net Fair Value Liability
(in millions)
|
|
Valuation Approach
|
|
Significant Unobservable Input
|
|
Significant Unobservable Inputs Range
|
Physical Liquefaction Supply Derivatives
|
|
$(29)
|
|
Market approach incorporating present value techniques
|
|
Basis Spread
|
|
$(0.980) - $0.085
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Balance, beginning of period
|
|
$
|
43
|
|
|
$
|
79
|
|
|
$
|
32
|
|
Realized and mark-to-market gains (losses):
|
|
|
|
|
|
|
||||||
Included in cost of sales (1)
|
|
(13
|
)
|
|
(37
|
)
|
|
48
|
|
|||
Purchases and settlements:
|
|
|
|
|
|
|
||||||
Purchases
|
|
(31
|
)
|
|
14
|
|
|
1
|
|
|||
Settlements (1)
|
|
(29
|
)
|
|
(12
|
)
|
|
(2
|
)
|
|||
Transfers out of Level 3 (2)
|
|
1
|
|
|
(1
|
)
|
|
—
|
|
|||
Balance, end of period
|
|
$
|
(29
|
)
|
|
$
|
43
|
|
|
$
|
79
|
|
Change in unrealized gains (losses) relating to instruments still held at end of period
|
|
$
|
(13
|
)
|
|
$
|
(37
|
)
|
|
$
|
49
|
|
|
(1)
|
Does not include the decrease in fair value of
$1 million
related to the realized gains capitalized during the year ended December 31, 2016.
|
(2)
|
Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.
|
|
|
Initial Notional Amount
|
|
Maximum Notional Amount
|
|
Effective Date
|
|
Maturity Date
|
|
Weighted Average Fixed Interest Rate Paid
|
|
Variable Interest Rate Received
|
CCH Interest Rate Derivatives
|
|
$29 million
|
|
$4.7 billion
|
|
May 20, 2015
|
|
May 31, 2022
|
|
2.30%
|
|
One-month LIBOR
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
|
|
CCH Interest Rate Derivatives
|
|
CQP Interest Rate Derivatives
|
|
Total
|
|
CCH Interest Rate Derivatives
|
|
CQP Interest Rate Derivatives
|
|
Total
|
||||||||||||
Consolidated Balance Sheet Location
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative assets
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
7
|
|
|
$
|
7
|
|
Non-current derivative assets
|
|
8
|
|
|
—
|
|
|
8
|
|
|
3
|
|
|
14
|
|
|
17
|
|
||||||
Total derivative assets
|
|
18
|
|
|
—
|
|
|
18
|
|
|
3
|
|
|
21
|
|
|
24
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
|
—
|
|
|
(20
|
)
|
||||||
Non-current derivative liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
(15
|
)
|
||||||
Total derivative liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(35
|
)
|
|
—
|
|
|
(35
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative asset (liability), net
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
(32
|
)
|
|
$
|
21
|
|
|
$
|
(11
|
)
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
CCH Interest Rate Derivatives gain (loss)
|
|
$
|
43
|
|
|
$
|
3
|
|
|
$
|
(16
|
)
|
CQP Interest Rate Derivatives gain
|
|
14
|
|
|
6
|
|
|
12
|
|
|||
SPL Interest Rate Derivatives loss
|
|
—
|
|
|
(2
|
)
|
|
(6
|
)
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
|
Liquefaction Supply Derivatives (1)
|
|
LNG Trading Derivatives (2)
|
|
Total
|
|
Liquefaction Supply Derivatives (1)
|
|
LNG Trading Derivatives (2)
|
|
Total
|
||||||||||||
Consolidated Balance Sheet Location
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative assets
|
$
|
13
|
|
|
$
|
24
|
|
|
$
|
37
|
|
|
$
|
41
|
|
|
$
|
9
|
|
|
$
|
50
|
|
Non-current derivative assets
|
46
|
|
|
—
|
|
|
46
|
|
|
17
|
|
|
—
|
|
|
17
|
|
||||||
Total derivative assets
|
59
|
|
|
24
|
|
|
83
|
|
|
58
|
|
|
9
|
|
|
67
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative liabilities
|
(79
|
)
|
|
(48
|
)
|
|
(127
|
)
|
|
—
|
|
|
(17
|
)
|
|
(17
|
)
|
||||||
Non-current derivative liabilities
|
(22
|
)
|
|
—
|
|
|
(22
|
)
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
||||||
Total derivative liabilities
|
(101
|
)
|
|
(48
|
)
|
|
(149
|
)
|
|
(3
|
)
|
|
(17
|
)
|
|
(20
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative asset (liability), net
|
$
|
(42
|
)
|
|
$
|
(24
|
)
|
|
$
|
(66
|
)
|
|
$
|
55
|
|
|
$
|
(8
|
)
|
|
$
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Notional amount, net (in TBtu) (3)
|
5,832
|
|
|
12
|
|
|
|
|
2,539
|
|
|
25
|
|
|
|
|
(1)
|
Does not include collateral calls of
$5 million
and
$1 million
for such contracts, which are included in
other current assets
in our Consolidated Balance Sheets as of
December 31, 2018
and
2017
, respectively.
|
(2)
|
Does not include collateral of
$9 million
and
$28 million
deposited for such contracts, which are included in
other current assets
in our Consolidated Balance Sheets as of
December 31, 2018
and
2017
, respectively.
|
(3)
|
SPL had secured up to approximately
3,464
TBtu and
2,214
TBtu and CCL had secured up to approximately
2,801
TBtu and
2,024
TBtu of natural gas feedstock through natural gas supply contracts as of
December 31, 2018
and
2017
, respectively.
|
|
Consolidated Statements of Operations Location (1)
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|||||||
LNG Trading Derivatives loss
|
LNG revenues
|
|
$
|
(25
|
)
|
|
$
|
(44
|
)
|
|
$
|
(4
|
)
|
Liquefaction Supply Derivatives loss (2)
|
LNG revenues
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Liquefaction Supply Derivatives gain (loss) (2)
|
Cost of sales
|
|
(100
|
)
|
|
(24
|
)
|
|
42
|
|
|
(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.
|
|
|
|
Fair Value Measurements as of
|
||||||
|
Consolidated Balance Sheet Location
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
FX Derivatives
|
Derivative assets
|
|
$
|
16
|
|
|
$
|
—
|
|
FX Derivatives
|
Derivative liabilities
|
|
(1
|
)
|
|
—
|
|
||
FX Derivatives
|
Non-current derivative liabilities
|
|
—
|
|
|
(1
|
)
|
|
|
|
Year Ended December 31,
|
||||||||||
|
Statement of Operations Location
|
|
2018
|
|
2017
|
|
2016
|
||||||
FX Derivatives gain (loss)
|
LNG revenues
|
|
$
|
18
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
FX Derivatives loss
|
Other income
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
|
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, 2018
|
|
|
|
|
|
|
||||||
CCH Interest Rate Derivatives
|
|
$
|
19
|
|
|
$
|
(1
|
)
|
|
$
|
18
|
|
Liquefaction Supply Derivatives
|
|
95
|
|
|
(36
|
)
|
|
59
|
|
|||
Liquefaction Supply Derivatives
|
|
(121
|
)
|
|
20
|
|
|
(101
|
)
|
|||
LNG Trading Derivatives
|
|
112
|
|
|
(88
|
)
|
|
24
|
|
|||
LNG Trading Derivatives
|
|
(92
|
)
|
|
44
|
|
|
(48
|
)
|
|||
FX Derivatives
|
|
30
|
|
|
(14
|
)
|
|
16
|
|
|||
FX Derivatives
|
|
(2
|
)
|
|
1
|
|
|
(1
|
)
|
|||
As of December 31, 2017
|
|
|
|
|
|
|
|
|||||
CCH Interest Rate Derivatives
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
3
|
|
CCH Interest Rate Derivatives
|
|
(35
|
)
|
|
—
|
|
|
(35
|
)
|
|||
CQP Interest Rate Derivatives
|
|
21
|
|
|
—
|
|
|
21
|
|
|||
Liquefaction Supply Derivatives
|
|
64
|
|
|
(6
|
)
|
|
58
|
|
|||
Liquefaction Supply Derivatives
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|||
LNG Trading Derivatives
|
|
9
|
|
|
—
|
|
|
9
|
|
|||
LNG Trading Derivatives
|
|
(37
|
)
|
|
20
|
|
|
(17
|
)
|
|||
FX Derivatives
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Advances made under EPC and non-EPC contracts
|
|
$
|
14
|
|
|
$
|
26
|
|
Advances made to municipalities for water system enhancements
|
|
90
|
|
|
97
|
|
||
Advances and other asset conveyances to third parties to support LNG terminals
|
|
54
|
|
|
48
|
|
||
Tax-related payments and receivables
|
|
21
|
|
|
29
|
|
||
Equity method investments
|
|
94
|
|
|
64
|
|
||
Other
|
|
32
|
|
|
24
|
|
||
Total other non-current assets, net
|
|
$
|
305
|
|
|
$
|
288
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Interest costs and related debt fees
|
|
$
|
233
|
|
|
$
|
397
|
|
Accrued natural gas purchases
|
|
610
|
|
|
298
|
|
||
LNG terminals and related pipeline costs
|
|
125
|
|
|
192
|
|
||
Compensation and benefits
|
|
117
|
|
|
141
|
|
||
Accrued LNG inventory
|
|
14
|
|
|
1
|
|
||
Other accrued liabilities
|
|
70
|
|
|
49
|
|
||
Total accrued liabilities
|
|
$
|
1,169
|
|
|
$
|
1,078
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Long-term debt:
|
|
|
|
|
||||
SPL
|
|
|
|
|
|
|||
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)
|
|
$
|
2,000
|
|
|
$
|
2,000
|
|
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)
|
|
1,000
|
|
|
1,000
|
|
||
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)
|
|
2,000
|
|
|
2,000
|
|
||
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)
|
|
2,000
|
|
|
2,000
|
|
||
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”)
|
|
1,350
|
|
|
1,350
|
|
||
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)
|
|
800
|
|
|
800
|
|
||
Cheniere Partners
|
|
|
|
|
||||
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)
|
|
1,100
|
|
|
—
|
|
||
CQP Credit Facilities
|
|
—
|
|
|
1,090
|
|
||
CCH
|
|
|
|
|
||||
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)
|
|
1,250
|
|
|
1,250
|
|
||
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
CCH Credit Facility
|
|
5,156
|
|
|
2,485
|
|
||
CCH HoldCo II
|
|
|
|
|
||||
11.0% Convertible Senior Secured Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)
|
|
1,455
|
|
|
1,305
|
|
||
Cheniere
|
|
|
|
|
||||
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”)
|
|
1,218
|
|
|
1,161
|
|
||
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”)
|
|
625
|
|
|
625
|
|
||
$1.25 billion Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)
|
|
—
|
|
|
—
|
|
||
Unamortized premium, discount and debt issuance costs, net
|
|
(775
|
)
|
|
(730
|
)
|
||
Total long-term debt, net
|
|
28,179
|
|
|
25,336
|
|
||
|
|
|
|
|
||||
Current debt:
|
|
|
|
|
||||
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
|
|
—
|
|
|
—
|
|
||
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)
|
|
168
|
|
|
—
|
|
||
Cheniere Marketing trade finance facilities
|
|
71
|
|
|
—
|
|
||
Total current debt
|
|
239
|
|
|
—
|
|
||
|
|
|
|
|
||||
Total debt, net
|
|
$
|
28,418
|
|
|
$
|
25,336
|
|
Years Ending December 31,
|
|
Principal Payments
|
||
2019
|
|
$
|
239
|
|
2020
|
|
—
|
|
|
2021
|
|
3,218
|
|
|
2022
|
|
1,000
|
|
|
2023
|
|
1,500
|
|
|
Thereafter
|
|
23,236
|
|
|
Total
|
|
$
|
29,193
|
|
|
|
SPL Working Capital Facility
|
|
CQP Credit Facilities
|
|
CCH Credit Facility
|
|
CCH Working Capital Facility
|
|
Cheniere Revolving Credit Facility
|
||||||||||
Original facility size
|
|
$
|
1,200
|
|
|
$
|
2,800
|
|
|
$
|
8,404
|
|
|
$
|
350
|
|
|
$
|
750
|
|
Incremental commitments
|
|
—
|
|
|
—
|
|
|
1,566
|
|
|
850
|
|
|
500
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Outstanding balance
|
|
—
|
|
|
—
|
|
|
5,156
|
|
|
168
|
|
|
—
|
|
|||||
Commitments prepaid or terminated
|
|
—
|
|
|
2,685
|
|
|
3,832
|
|
|
—
|
|
|
—
|
|
|||||
Letters of credit issued
|
|
425
|
|
|
—
|
|
|
—
|
|
|
316
|
|
|
—
|
|
|||||
Available commitment
|
|
$
|
775
|
|
|
$
|
115
|
|
|
$
|
982
|
|
|
$
|
716
|
|
|
$
|
1,250
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest rate
|
|
LIBOR plus 1.75% or base rate plus 0.75%
|
|
2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019
|
|
LIBOR plus 1.75% or base rate plus 0.75%
|
|
LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75%
|
|
LIBOR plus 1.75% - 2.50% or base rate plus 0.75% - 1.50%
|
||||||||||
Maturity date
|
|
December 31, 2020, with various terms for underlying loans
|
|
February 25, 2020
|
|
June 30, 2024
|
|
June 29, 2023
|
|
December 13, 2022
|
|
|
2021 Cheniere Convertible Unsecured Notes
|
|
2025 CCH HoldCo II Convertible Senior Notes
|
|
2045 Cheniere Convertible Senior Notes
|
||||||
Aggregate original principal
|
|
$
|
1,000
|
|
|
$
|
1,000
|
|
|
$
|
625
|
|
Debt component, net of discount and debt issuance costs
|
|
$
|
1,126
|
|
|
$
|
1,432
|
|
|
$
|
310
|
|
Equity component
|
|
$
|
209
|
|
|
$
|
—
|
|
|
$
|
194
|
|
Maturity date
|
|
May 28, 2021
|
|
|
May 13, 2025
|
|
|
March 15, 2045
|
|
|||
Contractual interest rate
|
|
4.875
|
%
|
|
11.0
|
%
|
|
4.25
|
%
|
|||
Effective interest rate (1)
|
|
8.4
|
%
|
|
11.9
|
%
|
|
9.4
|
%
|
|||
Remaining debt discount and debt issuance costs amortization period (2)
|
|
2.4 years
|
|
|
1.8 years
|
|
|
26.2 years
|
|
|
(1)
|
Rate to accrete the discounted carrying value of the convertible notes to the face value over the remaining amortization period.
|
(2)
|
We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity except for the
2025 CCH HoldCo II Convertible Senior Notes
, which are amortized through the date they are first convertible by holders into our common stock.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Interest cost on convertible notes:
|
|
|
|
|
|
||||||
Interest per contractual rate
|
$
|
237
|
|
|
$
|
219
|
|
|
$
|
202
|
|
Amortization of debt discount
|
35
|
|
|
29
|
|
|
31
|
|
|||
Amortization of debt issuance costs
|
9
|
|
|
7
|
|
|
5
|
|
|||
Total interest cost related to convertible notes
|
281
|
|
|
255
|
|
|
238
|
|
|||
Interest cost on capital lease
|
1
|
|
|
—
|
|
|
—
|
|
|||
Interest cost on debt excluding capital lease and convertible notes
|
1,396
|
|
|
1,271
|
|
|
1,063
|
|
|||
Total interest cost
|
1,678
|
|
|
1,526
|
|
|
1,301
|
|
|||
Capitalized interest
|
(803
|
)
|
|
(779
|
)
|
|
(813
|
)
|
|||
Total interest expense, net
|
$
|
875
|
|
|
$
|
747
|
|
|
$
|
488
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
|
Carrying
Amount |
|
Estimated
Fair Value |
|
Carrying
Amount |
|
Estimated
Fair Value |
||||||||
Senior notes (1)
|
|
$
|
19,466
|
|
|
$
|
19,901
|
|
|
$
|
18,350
|
|
|
$
|
20,075
|
|
2037 SPL Senior Notes (2)
|
|
791
|
|
|
817
|
|
|
790
|
|
|
871
|
|
||||
Credit facilities (3)
|
|
5,294
|
|
|
5,294
|
|
|
3,574
|
|
|
3,574
|
|
||||
2021 Cheniere Convertible Unsecured Notes (2)
|
|
1,126
|
|
|
1,236
|
|
|
1,040
|
|
|
1,136
|
|
||||
2025 CCH HoldCo II Convertible Senior Notes (2)
|
|
1,432
|
|
|
1,612
|
|
|
1,273
|
|
|
1,535
|
|
||||
2045 Cheniere Convertible Senior Notes (4)
|
|
310
|
|
|
431
|
|
|
309
|
|
|
447
|
|
|
(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
,
2025 CQP Senior Notes
,
2026 CQP Senior Notes
,
2024 CCH Senior Notes
,
2025 CCH Senior Notes
and
2027 CCH Senior Notes
. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
|
(2)
|
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
|
(3)
|
Includes
SPL Working Capital Facility
,
CQP Credit Facilities
,
CCH Credit Facility
,
CCH Working Capital Facility
,
Cheniere Revolving Credit Facility
and
Cheniere Marketing trade finance 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.
|
(4)
|
The Level 1 estimated fair value was based on unadjusted quoted prices in active markets for identical liabilities that we had the ability to access at the measurement date.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
LNG revenues
|
$
|
7,440
|
|
|
$
|
5,342
|
|
|
$
|
1,015
|
|
Regasification revenues
|
261
|
|
|
260
|
|
|
259
|
|
|||
Other revenues (1)
|
142
|
|
|
21
|
|
|
8
|
|
|||
Other—related party
|
12
|
|
|
3
|
|
|
—
|
|
|||
Total revenues from customers
|
7,855
|
|
|
5,626
|
|
|
1,282
|
|
|||
Gains (losses) from derivative instruments (2)
|
132
|
|
|
(25
|
)
|
|
1
|
|
|||
Total revenues
|
$
|
7,987
|
|
|
$
|
5,601
|
|
|
$
|
1,283
|
|
|
(1)
|
Includes
$101 million
in sub-chartering revenues for the year ended December 31, 2018.
|
(2)
|
Includes the realized value associated with a portion of derivative instruments that settle through physical delivery.
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Deferred revenues, beginning of period
|
$
|
111
|
|
|
$
|
78
|
|
Cash received but not yet recognized
|
139
|
|
|
111
|
|
||
Revenue recognized from prior period deferral
|
(111
|
)
|
|
(78
|
)
|
||
Deferred revenues, end of period
|
$
|
139
|
|
|
$
|
111
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||
|
|
Unsatisfied Transaction Price (in billions)
|
|
Weighted Average Recognition Timing (years) (1)
|
|
Unsatisfied Transaction Price (in billions)
|
|
Weighted Average Recognition Timing (years) (1)
|
||||
LNG revenues
|
|
$
|
106.6
|
|
|
11
|
|
$
|
83.7
|
|
|
11
|
Regasification revenues
|
|
2.6
|
|
|
6
|
|
2.9
|
|
|
6
|
||
Total revenues
|
|
$
|
109.2
|
|
|
|
|
$
|
86.6
|
|
|
|
|
(1)
|
The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
|
(1)
|
We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
|
(2)
|
We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately
56%
of our LNG revenues from contracts with a duration of over one year during each of the
years ended December 31, 2018 and 2017
and approximately
3%
and
2%
of our regasification revenues were related to variable consideration received from customers during the
years ended December 31, 2018 and 2017
, respectively.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
U.S.
|
|
$
|
997
|
|
|
$
|
30
|
|
|
$
|
(611
|
)
|
International
|
|
230
|
|
|
536
|
|
|
(52
|
)
|
|||
Total income (loss) before income taxes and non-controlling interest
|
|
$
|
1,227
|
|
|
$
|
566
|
|
|
$
|
(663
|
)
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Current:
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
|
2
|
|
|
—
|
|
|
—
|
|
|||
Foreign
|
|
30
|
|
|
6
|
|
|
—
|
|
|||
Total current
|
|
32
|
|
|
6
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
||||||
Deferred:
|
|
|
|
|
|
|
||||||
Federal
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
State
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Foreign
|
|
(5
|
)
|
|
(3
|
)
|
|
2
|
|
|||
Total deferred
|
|
(5
|
)
|
|
(3
|
)
|
|
2
|
|
|||
Total income tax provision
|
|
$
|
27
|
|
|
$
|
3
|
|
|
$
|
2
|
|
|
|
Year Ended December 31,
|
|||||||
|
|
2018
|
|
2017
|
|
2016
|
|||
U.S. federal statutory tax rate
|
|
21.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
Non-controlling interest
|
|
(11.4
|
)%
|
|
2.9
|
%
|
|
(2.1
|
)%
|
State tax rate
|
|
(0.4
|
)%
|
|
(0.2
|
)%
|
|
1.8
|
%
|
U.S. tax reform rate change
|
|
—
|
%
|
|
71.4
|
%
|
|
—
|
%
|
Share-based compensation
|
|
(0.5
|
)%
|
|
(6.2
|
)%
|
|
—
|
%
|
Nondeductible interest expense
|
|
2.6
|
%
|
|
8.5
|
%
|
|
(6.6
|
)%
|
Foreign earnings taxed in the U.S.
|
|
1.4
|
%
|
|
—
|
%
|
|
—
|
%
|
Foreign rate differential
|
|
(1.1
|
)%
|
|
(0.7
|
)%
|
|
(1.2
|
)%
|
Other
|
|
0.4
|
%
|
|
(0.5
|
)%
|
|
0.3
|
%
|
Valuation allowance
|
|
(9.8
|
)%
|
|
(109.7
|
)%
|
|
(27.5
|
)%
|
Effective tax rate
|
|
2.2
|
%
|
|
0.5
|
%
|
|
(0.3
|
)%
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Deferred tax assets
|
|
|
|
|
||||
Net operating loss carryforwards and credits
|
|
|
|
|
||||
Federal
|
|
$
|
848
|
|
|
$
|
936
|
|
Foreign
|
|
7
|
|
|
6
|
|
||
State
|
|
189
|
|
|
184
|
|
||
Federal and state tax credits
|
|
28
|
|
|
22
|
|
||
Disallowed business interest expense carryforward
|
|
19
|
|
|
—
|
|
||
Deferred gain
|
|
46
|
|
|
46
|
|
||
Other
|
|
50
|
|
|
77
|
|
||
Less: valuation allowance
|
|
(686
|
)
|
|
(806
|
)
|
||
Total deferred tax assets
|
|
501
|
|
|
465
|
|
||
|
|
|
|
|
||||
Deferred tax liabilities
|
|
|
|
|
|
|
||
Investment in limited partnership
|
|
(375
|
)
|
|
(391
|
)
|
||
Convertible debt
|
|
(59
|
)
|
|
(65
|
)
|
||
Property, plant and equipment
|
|
(48
|
)
|
|
(6
|
)
|
||
Other
|
|
(11
|
)
|
|
—
|
|
||
Total deferred tax liabilities
|
|
(493
|
)
|
|
(462
|
)
|
||
|
|
|
|
|
||||
Net deferred tax assets
|
|
$
|
8
|
|
|
$
|
3
|
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Balance at beginning of the year
|
$
|
62
|
|
|
$
|
103
|
|
Additions based on tax positions related to current year
|
—
|
|
|
—
|
|
||
Additions for tax positions of prior years
|
—
|
|
|
—
|
|
||
Reductions for tax positions of prior years
|
(1
|
)
|
|
(1
|
)
|
||
Settlements
|
—
|
|
|
—
|
|
||
U.S. tax reform rate change
|
—
|
|
|
(40
|
)
|
||
Balance at end of the year
|
$
|
61
|
|
|
$
|
62
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Share-based compensation costs, pre-tax:
|
|
|
|
|
|
||||||
Equity awards
|
$
|
89
|
|
|
$
|
34
|
|
|
$
|
41
|
|
Liability awards
|
48
|
|
|
80
|
|
|
76
|
|
|||
Total share-based compensation
|
137
|
|
|
114
|
|
|
117
|
|
|||
Capitalized share-based compensation
|
(24
|
)
|
|
(23
|
)
|
|
(16
|
)
|
|||
Total share-based compensation expense
|
$
|
113
|
|
|
$
|
91
|
|
|
$
|
101
|
|
Tax benefit associated with share-based compensation expense
|
$
|
6
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
Unrecognized Compensation Cost
(in millions)
|
Recognized over a weighted average period
(years)
|
||
Restricted Stock Share Awards
|
$
|
2
|
|
0.3
|
Restricted Share Unit and Performance Stock Unit Awards
|
$
|
136
|
|
1.7
|
Phantom Units Awards
|
$
|
11
|
|
1.4
|
|
|
Shares
|
|
Weighted Average Grant Date Fair Value Per Share
|
|||
Non-vested at January 1, 2018
|
|
2.2
|
|
|
$
|
24.29
|
|
Granted
|
|
—
|
|
|
—
|
|
|
Vested
|
|
(2.1
|
)
|
|
24.03
|
|
|
Forfeited
|
|
—
|
|
|
—
|
|
|
Non-vested at December 31, 2018
|
|
0.1
|
|
|
$
|
45.77
|
|
|
|
Units
|
|
Weighted Average Grant Date Fair Value Per Unit
|
|||
Non-vested at January 1, 2018
|
|
1.3
|
|
|
$
|
47.18
|
|
Granted (1)
|
|
2.6
|
|
|
59.50
|
|
|
Vested
|
|
(0.4
|
)
|
|
48.40
|
|
|
Forfeited
|
|
(0.1
|
)
|
|
53.92
|
|
|
Non-vested at December 31, 2018
|
|
3.4
|
|
|
$
|
56.29
|
|
|
(1)
|
This number excludes
0.2 million
performance stock units, which represent the maximum number of common units that would be issued if the maximum level of performance under the target awards amount is achieved.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Units issued (in millions)
|
|
2.6
|
|
|
1.4
|
|
|
—
|
|
|||
Weighted average grant date fair value per unit
|
|
$
|
59.50
|
|
|
$
|
47.16
|
|
|
$
|
—
|
|
Fair value of units vested (in millions)
|
|
$
|
22
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
|
Units
|
|
Non-vested at January 1, 2018
|
|
1.8
|
|
Granted
|
|
—
|
|
Vested
|
|
(1.5
|
)
|
Forfeited
|
|
—
|
|
Non-vested at December 31, 2018
|
|
0.3
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Weighted average common shares outstanding:
|
|
|
|
|
|
|
||||||
Basic
|
|
245.6
|
|
|
233.1
|
|
|
228.8
|
|
|||
Dilutive unvested stock
|
|
2.4
|
|
|
—
|
|
|
—
|
|
|||
Diluted
|
|
248.0
|
|
|
233.1
|
|
|
228.8
|
|
|||
|
|
|
|
|
|
|
||||||
Basic net income (loss) per share attributable to common stockholders
|
|
$
|
1.92
|
|
|
$
|
(1.68
|
)
|
|
$
|
(2.67
|
)
|
Diluted net income (loss) per share attributable to common stockholders
|
|
$
|
1.90
|
|
|
$
|
(1.68
|
)
|
|
$
|
(2.67
|
)
|
|
Year Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Unvested stock (1)
|
0.8
|
|
|
3.4
|
|
|
0.6
|
|
Convertible notes (2)
|
17.5
|
|
|
16.9
|
|
|
16.3
|
|
Total potentially dilutive common shares
|
18.3
|
|
|
20.3
|
|
|
16.9
|
|
|
(1)
|
Does not include
0.4 million
shares,
0.2 million
shares and
5.0 million
shares for each of the
years ended December 31, 2018, 2017 and 2016
, of unvested stock because the performance conditions had not yet been satisfied as of
December 31, 2018
,
2017
and 2016, respectively.
|
(2)
|
Includes number of shares in aggregate issuable upon conversion of the
2021 Cheniere Convertible Unsecured Notes
and the
2045 Cheniere Convertible Senior Notes
. There were
no
shares included in the computation of diluted
net income (loss)
per share for the
2025 CCH HoldCo II Convertible Senior Notes
because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of
December 31, 2018
.
|
Years Ending December 31,
|
Operating Leases (1)
|
||
2019 (2)
|
$
|
380
|
|
2020
|
184
|
|
|
2021
|
238
|
|
|
2022
|
264
|
|
|
2023
|
264
|
|
|
Thereafter
|
999
|
|
|
Total
|
$
|
2,329
|
|
|
(1)
|
Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components
.
|
(2)
|
Does not include
$43 million
in aggregate payments we will receive from our LNG vessel time charter subleases.
|
Years Ending December 31,
|
Capital Leases
|
||
2019
|
$
|
5
|
|
2020
|
5
|
|
|
2021
|
5
|
|
|
2022
|
5
|
|
|
2023
|
5
|
|
|
Thereafter
|
73
|
|
|
Total minimum lease payments (1)
|
98
|
|
|
Less: amount representing imputed interest
|
(39
|
)
|
|
Present value of minimum lease payment
|
59
|
|
|
Less: current portion of capital lease obligations
|
(2
|
)
|
|
Non-current portion of capital lease obligations
|
$
|
57
|
|
|
(1)
|
Does not include payments for non-lease components of
$98 million
.
|
|
(1)
|
Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread
.
Amounts included are based on prices and basis spreads as of
December 31, 2018
.
|
|
Percentage of Total Revenues from External Customers
|
|
Percentage of Accounts Receivable from External Customers
|
|||||||
|
|
Year Ended December 31,
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
Customer A
|
|
18%
|
|
24%
|
|
39%
|
|
21%
|
|
28%
|
Customer B
|
|
14%
|
|
14%
|
|
*
|
|
14%
|
|
16%
|
Customer C
|
|
19%
|
|
14%
|
|
—%
|
|
18%
|
|
14%
|
Customer D
|
|
13%
|
|
*
|
|
*
|
|
*
|
|
—%
|
Customer E
|
|
*
|
|
17%
|
|
—%
|
|
—%
|
|
—%
|
Customer F
|
|
*
|
|
*
|
|
*
|
|
*
|
|
15%
|
Customer G
|
|
*
|
|
*
|
|
*
|
|
10%
|
|
—%
|
Customer H
|
|
*
|
|
*
|
|
13%
|
|
—%
|
|
—%
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Cash paid during the period for interest, net of amounts capitalized
|
|
$
|
707
|
|
|
$
|
305
|
|
|
$
|
66
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
||||||
Issuance of stock to acquire additional interest in Cheniere Holdings
|
|
702
|
|
|
2
|
|
|
94
|
|
|||
Contribution of assets to equity method investee
|
|
—
|
|
|
14
|
|
|
—
|
|
|||
Acquisition of assets under capital lease
|
|
60
|
|
|
—
|
|
|
—
|
|
Standard
|
|
Description
|
|
Expected Date of Adoption
|
|
Effect on our Consolidated Financial Statements or Other Significant Matters
|
ASU 2016-02,
Leases (Topic 842)
, and subsequent amendments thereto
|
|
This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and may be adopted using either a modified retrospective approach to apply the standard at the beginning of the earliest period presented in the financial statements or an optional transition approach to apply the standard at the date of adoption with no retrospective adjustments to prior periods. Certain additional practical expedients are also available.
|
|
January 1, 2019
|
|
We will adopt this standard on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard will result in the recognition of right-of-use assets and lease liabilities for operating leases of approximately $550 million on our Consolidated Balance Sheets, with no material impact on our Consolidated Statements of Operations or Consolidated Statements of Cash Flows. The adoption of this standard will also result in additional disclosures including the significant judgments and assumptions used in applying the standard. When we adopt this standard we will elect the practical expedients to (1) carryforward prior conclusions related to lease identification and classification for existing leases, (2) combine lease and non-lease components of an arrangement for all classes of leased assets, (3) omit short-term leases with a term of 12 months or less from recognition on the balance sheet and (4) carryforward our existing accounting for land easements not previously accounted for as leases.
|
Standard
|
|
Description
|
|
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 adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported Consolidated Financial Statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See
Note 13—Revenues from Contracts with Customers
for additional disclosures.
|
ASU 2016-16,
Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
|
|
This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.
|
|
January 1, 2018
|
|
The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
Year ended December 31, 2018:
|
|
|
|
|
|
|
|
|
||||||||
Revenues
|
|
$
|
2,242
|
|
|
$
|
1,543
|
|
|
$
|
1,819
|
|
|
$
|
2,383
|
|
Income from operations
|
|
747
|
|
|
336
|
|
|
425
|
|
|
516
|
|
||||
Net income
|
|
600
|
|
|
150
|
|
|
227
|
|
|
223
|
|
||||
Net income (loss) attributable to common stockholders
|
|
357
|
|
|
(18
|
)
|
|
65
|
|
|
67
|
|
||||
Net income (loss) per share attributable to common stockholders—basic (1)
|
|
1.52
|
|
|
(0.07
|
)
|
|
0.26
|
|
|
0.26
|
|
||||
Net income (loss) per share attributable to common stockholders—diluted (1)
|
|
1.50
|
|
|
(0.07
|
)
|
|
0.26
|
|
|
0.26
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Year ended December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenues
|
|
$
|
1,211
|
|
|
$
|
1,241
|
|
|
$
|
1,403
|
|
|
$
|
1,746
|
|
Income from operations
|
|
376
|
|
|
274
|
|
|
297
|
|
|
441
|
|
||||
Net income
|
|
172
|
|
|
21
|
|
|
90
|
|
|
280
|
|
||||
Net income (loss) attributable to common stockholders
|
|
54
|
|
|
(285
|
)
|
|
(289
|
)
|
|
127
|
|
||||
Net income (loss) per share attributable to common stockholders—basic and diluted (1)
|
|
0.23
|
|
|
(1.23
|
)
|
|
(1.24
|
)
|
|
0.54
|
|
|
|
|
|
|
(1)
|
The sum of the quarterly net income (loss) per share—basic and diluted may not equal the full year amount as the computations of the weighted average common shares outstanding for basic and diluted shares 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 15.
|
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|
(a)
|
Financial Statements, Schedules and Exhibits
|
(1)
|
Financial Statements—Cheniere Energy, Inc. and Subsidiaries:
|
(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
|
|
|
3.1
|
|
|
3.2
|
|
Exhibit No.
|
|
Description
|
3.3
|
|
|
3.4
|
|
|
3.5
|
|
|
3.6
|
|
|
3.7
|
|
|
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
|
|
Exhibit No.
|
|
Description
|
4.20
|
|
|
4.21
|
|
|
4.22
|
|
|
4.23
|
|
|
4.24
|
|
|
4.25
|
|
|
4.26
|
|
|
4.27
|
|
|
4.28
|
|
|
4.29
|
|
|
4.30
|
|
|
4.31
|
|
|
4.32
|
|
|
4.33
|
|
|
4.34
|
|
|
4.35
|
|
|
4.36
|
|
|
4.37
|
|
|
4.38
|
|
|
4.39
|
|
|
10.1
|
|
|
10.2
|
|
Exhibit No.
|
|
Description
|
10.3
|
|
|
10.4
|
|
|
10.5
|
|
|
10.6
|
|
|
10.7
|
|
|
10.8
|
|
|
10.9
|
|
|
10.10
|
|
|
10.11
|
|
|
10.12
|
|
|
10.13
|
|
|
10.14
|
|
|
10.15†
|
|
|
10.16†
|
|
|
10.17†
|
|
|
10.18†
|
|
|
10.19†
|
|
|
10.20†
|
|
|
10.21†
|
|
Exhibit No.
|
|
Description
|
10.22†
|
|
|
10.23†
|
|
|
10.24†
|
|
|
10.25†
|
|
|
10.26†
|
|
|
10.27†
|
|
|
10.28†
|
|
|
10.29†
|
|
|
10.30†
|
|
|
10.31†
|
|
|
10.32†
|
|
|
10.33†
|
|
|
10.34†
|
|
|
10.35*†
|
|
|
10.36†
|
|
|
10.37†
|
|
|
10.38†
|
|
|
10.39†
|
|
|
10.40†
|
|
Exhibit No.
|
|
Description
|
10.41†
|
|
|
10.42†
|
|
|
10.43†
|
|
|
10.44†
|
|
|
10.45†
|
|
|
10.46†
|
|
|
10.47†
|
|
|
10.48†
|
|
|
10.49†
|
|
|
10.50†
|
|
|
10.51
|
|
|
10.52
|
|
|
10.53
|
|
|
10.54
|
|
|
10.55
|
|
Exhibit No.
|
|
Description
|
10.56
|
|
|
10.57
|
|
|
10.58
|
|
|
10.59
|
|
|
10.60*
|
|
|
10.61
|
|
|
10.62*
|
|
|
10.63
|
|
|
10.64
|
|
|
10.65
|
|
|
10.66
|
|
|
10.67
|
|
Exhibit No.
|
|
Description
|
10.68
|
|
|
10.69
|
|
|
10.70
|
|
|
10.71
|
|
|
10.72
|
|
|
10.73
|
|
|
10.74
|
|
|
10.75
|
|
|
10.76
|
|
|
10.77
|
|
|
10.78
|
|
|
10.79
|
|
Exhibit No.
|
|
Description
|
10.80
|
|
|
10.81
|
|
|
10.82
|
|
|
10.83
|
|
|
10.84
|
|
|
10.85
|
|
|
10.86
|
|
|
10.87
|
|
|
10.88
|
|
Exhibit No.
|
|
Description
|
10.89
|
|
|
10.90
|
|
|
10.91
|
|
|
10.92
|
|
|
10.93
|
|
|
10.94
|
|
|
10.95
|
|
|
10.96*
|
|
Exhibit No.
|
|
Description
|
10.97
|
|
|
10.98
|
|
|
10.99
|
|
|
10.100
|
|
|
10.101
|
|
|
10.102
|
|
Exhibit No.
|
|
Description
|
10.103
|
|
|
10.104
|
|
|
10.105
|
|
|
10.106
|
|
|
10.107
|
|
|
10.108
|
|
|
10.109
|
|
Exhibit No.
|
|
Description
|
10.110
|
|
|
10.111
|
|
|
10.112
|
|
|
10.113
|
|
|
10.114*
|
|
|
10.115
|
|
|
10.116
|
|
Exhibit No.
|
|
Description
|
10.117*
|
|
|
10.118
|
|
|
10.119
|
|
|
10.120
|
|
|
10.121
|
|
|
10.122
|
|
|
10.123
|
|
|
10.124
|
|
|
10.125
|
|
|
10.126
|
|
|
10.127
|
|
|
10.128
|
|
|
10.129
|
|
|
10.130
|
|
|
10.131
|
|
Exhibit No.
|
|
Description
|
10.132
|
|
|
10.133
|
|
|
10.134
|
|
|
10.135
|
|
|
10.136
|
|
|
10.137
|
|
|
10.138
|
|
|
10.139
|
|
|
10.140
|
|
|
10.141
|
|
|
10.142
|
|
|
10.143
|
|
|
10.144
|
|
|
10.145
|
|
|
21.1*
|
|
|
23.1*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1**
|
|
Exhibit No.
|
|
Description
|
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,
|
||||||
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
|
|
|||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash
|
—
|
|
|
—
|
|
||
Other current assets
|
1
|
|
|
—
|
|
||
Property, plant and equipment, net
|
14
|
|
|
15
|
|
||
Debt issuance and deferred financing costs, net
|
21
|
|
|
12
|
|
||
Investments in affiliates
|
883
|
|
|
(435
|
)
|
||
Total assets
|
$
|
919
|
|
|
$
|
(408
|
)
|
|
|
|
|
||||
LIABILITIES AND STOCKHOLDERS’ DEFICIT
|
|
|
|
||||
Current liabilities
|
$
|
9
|
|
|
$
|
8
|
|
|
|
|
|
||||
Long-term debt, net
|
1,436
|
|
|
1,348
|
|
||
|
|
|
|
||||
Stockholders’ deficit
|
(526
|
)
|
|
(1,764
|
)
|
||
Total liabilities and stockholders’ deficit
|
$
|
919
|
|
|
$
|
(408
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
General and administrative expense
|
$
|
8
|
|
|
$
|
7
|
|
|
$
|
6
|
|
|
|
|
|
|
|
||||||
Other income (expense)
|
|
|
|
|
|
||||||
Interest expense, net
|
(128
|
)
|
|
(118
|
)
|
|
(104
|
)
|
|||
Interest expense, net—affiliates
|
—
|
|
|
—
|
|
|
(7
|
)
|
|||
Interest income—affiliates
|
—
|
|
|
—
|
|
|
24
|
|
|||
Equity income (loss) of affiliates
|
607
|
|
|
(268
|
)
|
|
(517
|
)
|
|||
Total other income (expense)
|
479
|
|
|
(386
|
)
|
|
(604
|
)
|
|||
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders
|
$
|
471
|
|
|
$
|
(393
|
)
|
|
$
|
(610
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Net cash provided by (used in) operating activities
|
$
|
48
|
|
|
$
|
(4
|
)
|
|
$
|
(102
|
)
|
|
|
|
|
|
|
||||||
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|||
Investments in affiliates
|
568
|
|
|
209
|
|
|
202
|
|
|||
Net cash provided by investing activities
|
568
|
|
|
209
|
|
|
202
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|||
Debt issuance and deferred financing costs
|
(13
|
)
|
|
(15
|
)
|
|
—
|
|
|||
Distribution and dividends to non-controlling interest
|
(576
|
)
|
|
(185
|
)
|
|
(80
|
)
|
|||
Payments related to tax withholdings for share-based compensation
|
(20
|
)
|
|
(12
|
)
|
|
(20
|
)
|
|||
Other
|
(7
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash used in financing activities
|
(616
|
)
|
|
(212
|
)
|
|
(100
|
)
|
|||
|
|
|
|
|
|
||||||
Net decrease in cash, cash equivalents and restricted cash
|
—
|
|
|
(7
|
)
|
|
—
|
|
|||
Cash, cash equivalents and restricted cash—beginning of period
|
—
|
|
|
7
|
|
|
7
|
|
|||
Cash, cash equivalents and restricted cash—end of period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7
|
|
|
December 31
|
||||||
|
2018
|
|
2017
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash
|
—
|
|
|
—
|
|
||
Total cash, cash equivalents and restricted cash
|
$
|
—
|
|
|
$
|
—
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Long-term debt:
|
|
|
|
|
||||
4.875% Convertible Unsecured Notes due 2021
|
|
$
|
1,218
|
|
|
$
|
1,161
|
|
4.25% Convertible Senior Notes due 2045
|
|
625
|
|
|
625
|
|
||
$1.25 billion Cheniere Revolving Credit Facility
|
|
—
|
|
|
—
|
|
||
Unamortized premium, discount and debt issuance costs, net
|
|
(407
|
)
|
|
(438
|
)
|
||
Total long-term debt, net
|
|
$
|
1,436
|
|
|
$
|
1,348
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Cash paid during the period for interest, net of amounts capitalized
|
|
$
|
32
|
|
|
$
|
31
|
|
|
$
|
20
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
||||||
Non-cash capital distribution (contributions) (1)
|
|
607
|
|
|
(268
|
)
|
|
(517
|
)
|
|||
Issuance of stock to acquire additional interest in Cheniere Holdings
|
|
702
|
|
|
2
|
|
|
94
|
|
|||
Non-cash capital contribution from subsidiaries for forgiveness of debt
|
|
—
|
|
|
—
|
|
|
151
|
|
|||
Non-cash capital distribution to subsidiaries for forgiveness of debt
|
|
—
|
|
|
—
|
|
|
(868
|
)
|
|
(1)
|
Amounts represent equity income (losses) of affiliates.
|
ITEM 16.
|
FORM 10-K SUMMARY
|
|
CHENIERE ENERGY, INC.
|
|
|
(Registrant)
|
|
|
|
|
|
By:
|
/s/ Jack A. Fusco
|
|
|
Jack A. Fusco
|
|
|
President and Chief Executive Officer
(Principal Executive Officer) |
|
Date:
|
February 25, 2019
|
Signature
|
Title
|
Date
|
|
|
|
/s/ Jack A. Fusco
|
President and Chief Executive Officer and Director
(Principal Executive Officer) |
February 25, 2019
|
Jack A. Fusco
|
||
|
|
|
/s/ Michael J. Wortley
|
Executive Vice President and Chief Financial Officer
(Principal Financial Officer) |
February 25, 2019
|
Michael J. Wortley
|
||
|
|
|
/s/ Leonard E. Travis
|
Vice President and Chief Accounting Officer
(Principal Accounting Officer) |
February 25, 2019
|
Leonard E. Travis
|
||
|
|
|
/s/ G. Andrea Botta
|
Chairman of the Board
|
February 25, 2019
|
G. Andrea Botta
|
||
|
|
|
/s/ Vicky A. Bailey
|
Director
|
February 25, 2019
|
Vicky A. Bailey
|
||
|
|
|
/s/ Nuno Brandolini
|
Director
|
February 25, 2019
|
Nuno Brandolini
|
||
|
|
|
/s/ Andrew Langham
|
Director
|
February 25, 2019
|
Andrew Langham
|
||
|
|
|
/s/ David I. Foley
|
Director
|
February 25, 2019
|
David I. Foley
|
||
|
|
|
/s/ David B. Kilpatrick
|
Director
|
February 25, 2019
|
David B. Kilpatrick
|
||
|
|
|
/s/ Courtney R. Mather
|
Director
|
February 25, 2019
|
Courtney R. Mather
|
||
|
|
|
/s/ Donald F. Robillard, Jr.
|
Director
|
February 25, 2019
|
Donald F. Robillard, Jr.
|
||
|
|
|
/s/ Neal A. Shear
|
Director
|
February 25, 2019
|
Neal A. Shear
|
||
|
|
|
COMPANY:
|
|
|
|
CHENIERE ENERGY, INC
|
|
|
|
|
|
By:
|
|
|
|
|
Title: Chief Human Resources Officer
|
PARTICIPANT:
|
|
|
|
|
|
By:
|
|
|
Name:
|
CHENIERE CORPUS CHRISTI
|
|
HOLDINGS, LLC,
as the Borrower
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa Cohen
|
|
Title: Treasurer
|
|
|
|
CORPUS CHRISTI LIQUEFACTION,
|
|
LLC,
as Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
CHENIERE CORPUS CHRISTI
|
|
PIPELINE, L.P.,
as Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
CORPUS CHRISTI PIPELINE GP, LLC,
|
|
as Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa Cohen
|
|
Title: Treasurer
|
SOCIÉTÉ GÉNÉRALE,
|
|
as Intercreditor Agent on behalf of itself and
|
|
each Facility Agent
|
|
|
|
|
|
By:
|
/s/ Ellen Turkel
|
Name: Ellen Turkel
|
|
Title: Director
|
CHENIERE CORPUS CHRISTI
|
|
HOLDINGS, LLC,
as the Company
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa Cohen
|
|
Title: Treasurer
|
|
|
|
CORPUS CHRISTI LIQUEFACTION,
|
|
LLC,
as Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
CHENIERE CORPUS CHRISTI
|
|
PIPELINE, L.P.,
as Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa Cohen
|
|
Title: Treasurer
|
|
|
|
|
|
CORPUS CHRISTI PIPELINE GP, LLC,
|
|
as Guarantor
|
|
|
|
|
|
By:
|
/s/ Lisa C. Cohen
|
Name: Lisa Cohen
|
|
Title: Treasurer
|
SOCIÉTÉ GÉNÉRALE,
|
|
as Security Trustee
|
|
|
|
|
|
By:
|
/s/ Ellen Turkel
|
Name: Ellen Turkel
|
|
Title: Director
|
SOCIÉTÉ GÉNÉRALE,
|
|
as Intercreditor Agent, on its own behalf and
|
|
on behalf of the Intercreditor Parties, solely for
|
|
purposes of consenting to the Security
|
|
Trustee’s execution of the amendment
|
|
pursuant to Section 7.2(a)(i) of the Common
|
|
Security and Account Agreement
|
|
|
|
|
|
By:
|
/s/ Ellen Turkel
|
Name: Ellen Turkel
|
|
Title: 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-00037
DATE OF CHANGE ORDER:
November 29, 2018
|
1.
|
The value of the Soils Preparation Provisional Sum incorporated into the Agreement in Change Order CO-00021, executed September 13, 2017, was $86,954,513. Parties agree to close this Provisional Sum. The Actual Cost for the Soils Preparation Provisional Sum is $84,850,512. The contract price will be decreased by $2,104,001 which reflects the closure of this Provisional Sum.
|
2.
|
The Provisional Sum breakdown is described as follows:
|
a.
|
This Change Order will decrease the Soils Preparation Provisional Sum specified in Article 2.1 of Attachment EE, Schedule EE-2, by $86,954,513. The new value of the Soils Preparation Provisional Sum will be $0.
|
b.
|
The Aggregate Provisional Sum specified in Article 7.1A of the Agreement prior to this Change Order was $291,338,848. This Change Order will decrease the Aggregate Provisional Sum amount by $86,954,513 and the new value shall be $204,384,334.
|
3.
|
The overall cost breakdown for this decrease in the Soils Preparation Provisional Sum is provided in Exhibit A.
|
4.
|
Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.
|
The original Contract Price was........................................................................................................................
|
$
|
2,987,000,000
|
|
Net change by previously authorized Change Orders (#00001-00036)............................................................
|
$
|
74,458,500
|
|
The Contract Price prior to this Change Order was..........................................................................................
|
$
|
3,061,458,500
|
|
The Contract Price will be increased by this Change Order in the amount of..................................................
|
$
|
(2,104,001
|
)
|
The new Contract Price including this Change Order will be..........................................................................
|
$
|
3,059,354,499
|
|
/s/ David Craft
|
|
/s/ Maurissa Douglas Rogers
|
Owner
|
|
Contractor
|
David Craft
|
|
Maurissa Douglas Rogers
|
Name
|
|
Name
|
SVP E&C
|
|
Senior Project Manager, PVP
|
Title
|
|
Title
|
December 14, 2018
|
|
November 28, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Corpus Christi Stage 1 Liquefaction Facility
OWNER:
Corpus Christi Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: December 6, 2013
|
CHANGE ORDER NUMBER:
CO-00040
DATE OF CHANGE ORDER:
April 5, 2018
|
1.
|
Contractor shall implement schedule acceleration efforts to recover from the impacts of Hurricane Harvey by performing certain Work on Subproject 1 on selected Saturdays, if agreed by Owner in accordance with this Change Order. Owner will compensate Contractor for overtime premium amounts for craft and field labor and other additional resources reasonably required to support the Work incurred on those Saturdays, up to an aggregate not-to-exceed amount of Eight Million U.S. Dollars (U.S.$8,000,000) under this Change Order, as further described herein.
|
2.
|
The following date ranges represent those time periods (“Release Periods”) in which Contractor shall, if requested by Owner in writing, undertake such schedule acceleration efforts:
|
3.
|
No later than seven (7) Days prior to the commencement of a Release Period, Contractor and Owner shall meet and Contractor shall provide:
|
•
|
A written report of the progress and outcome of acceleration efforts in the preceding Release Period, including any schedule recovery.
|
•
|
A proposed scope for any Work for the following Release Period.
|
4.
|
No later than five (5) Days prior to the commencement of a Release Period, Contractor shall provide to Owner Contractor’s proposed lump sum amount that will be payable by Owner for the following Release Period, including the agreed-upon modified scope of Work, for each Saturday to be worked and the expected acceleration services to be performed. Contractor shall describe in reasonable detail the overtime premium amounts for craft and field labor and other additional resources necessary to complete the Work that are included in the proposed lump sum amount. Upon the Parties’ written agreement on the lump sum amount, such amount shall be referred to as the “Recovery Payment” for such Release Period.
|
5.
|
No later than two (2) Days prior to a Release Period, Owner shall inform Contractor in writing whether Owner desires Contractor to perform acceleration efforts pursuant to such Release Period. Such election shall be at Owner’s sole and absolute discretion, and in no event shall Contractor be entitled to the Recovery Payment if Owner elects not to proceed with any Release Period(s) or if Contractor does not complete the agreed-upon scope of Work.
|
6.
|
Except for cost to Owner for Release Period #1 (which shall be invoiced in the Project monthly invoice coinciding with the month of full execution of this Change Order); if Owner elects for Contractor to perform acceleration efforts for a Release Period, Contractor shall invoice Owner by including Release Period cost in the Project monthly invoice coinciding with the month of the beginning of such Release Period. With respect to such invoice, Owner shall remit payment to Contractor in an amount equal the Recovery Payment payable for all Saturdays projected to be worked during the applicable Release Period.
|
7.
|
If, Contractor is unable to work all or a portion of a projected Saturday during the course of a Release Period, the Recovery Payment paid by Owner for such Saturday shall be credited for all or for the unworked portion (as applicable) for the subsequent Release Period provided in accordance with the section 6 above.
|
8.
|
Upon Contractor’s completion of all acceleration efforts under this Change Order, if the approved acceleration efforts by Contractor is less than Eight Million U.S. Dollars (U.S.$8,000,000), Owner shall be entitled to a Change Order reducing the Contract Price by such difference.
|
9.
|
Notwithstanding anything to the contrary herein, Owner shall have no obligation to pay any amounts in excess of Eight Million U.S. Dollars (U.S.$8,000,000) pursuant to this Change Order.
|
The original Contract Price was.........................................................................................................................
|
$
|
7,080,830,000
|
|
Net change by previously authorized Change Orders (0001-00039).................................................................
|
$
|
683,567,743
|
|
The Contract Price prior to this Change Order was...........................................................................................
|
$
|
7,764,397,743
|
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
7,772,397,743
|
|
The original Aggregate Equipment Price was...................................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00039).................................................................
|
$
|
***
|
The Aggregate Equipment Price prior to this Change Order was......................................................................
|
$
|
***
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
The new Aggregate Equipment Price including this Change Order will be .....................................................
|
$
|
***
|
The original Aggregate Labor and Skills Price was..........................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00039).................................................................
|
$
|
***
|
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................
|
$
|
***
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
***
|
The original Aggregate Provisional Sum was....................................................................................................
|
$
|
950,561,351
|
|
Net change by previously authorized Change Orders (0001-00039).................................................................
|
$
|
(812,283,979
|
)
|
The Aggregate Provisional Sum prior to this Change Order was......................................................................
|
$
|
138,277,372
|
|
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................
|
$
|
—
|
|
The new Aggregate Provisional Sum including this Change Order will be......................................................
|
$
|
138,277,372
|
|
/s/ Ed Lehotsky
|
|
/s/ Sergio Buoncristiano
|
Owner
|
|
Contractor
|
Ed Lehotsky
|
|
Sergio Buoncristiano
|
Name
|
|
Name
|
SVP E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
April 26, 2018
|
|
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Corpus Christi Stage 1 Liquefaction Facility
OWNER:
Corpus Christi Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: December 6, 2013
|
CHANGE ORDER NUMBER:
CO-00046
DATE OF CHANGE ORDER:
September 12, 2018
|
•
|
Component 00A-4024 O&M Control Building (excluding north end control room, I/O room, training rooms, and telecommunications rooms) - a portion of System 040-01 by August 22, 2018.
|
•
|
Component 00A-4034 Maintenance Building - a portion of System 040-22 by September 4, 2018
|
•
|
Component 00A-4046 Warehouse 2 Building - a portion of System 040-22 by September 4, 2018.
|
•
|
Component 00A-4045 Jetty Security Building - a portion of System 040-27 by September 11, 2018.
|
•
|
Component 00A-4026 Guard House - a portion of System 040-27 by September 11, 2018.
|
•
|
Component 00A-4047 Auxiliary Materials Building - a portion of System 040-22 by September 11, 2018.
|
•
|
Component 00A-4002 Outside Operator Building - a portion of System 040-02 by September 11, 2018.
|
1)
|
“Phase 1” means the time period beginning upon the date this Change Order is executed and ending on the date a Building is turned over to Owner.
|
2)
|
“Phase 2” means the time period beginning the date a Building is turned over to Owner and ending on the date of Substantial Completion of Subproject 1.
|
3)
|
During Phase 1:
|
a)
|
Contractor shall perform Work to complete the Building in accordance with the Agreement so that the Building is ready for full occupancy and shall obtain a Certificate of Occupancy for each of the Building according to the Project Schedule.
|
b)
|
Contractor shall perform preventive maintenance on the Building and its systems according to the operating and maintenance manuals.
|
c)
|
On or before the date a Building is to be turned over to Owner, Owner and Contractor shall jointly inspect the Building to determine and record the whether the Work for the Building is completed, other than punchlist items that may be completed after turnover to Owner (such punchlist items that may be completed after turnover is hereinafter referred to as “Remaining Work”). The Parties shall agree on the Remaining Work needed to be completed or corrected as a result of such inspection. Contractor shall complete the Work on the Building other than the agreed upon Remaining Work.
|
d)
|
On or before the date a Building is to be turned over to Owner, Contractor shall deliver to Owner the keys to the Building and Owner shall maintain access control and security to and inside the Building. Upon such turnover, Contractor will install a barricade around the Building with access points for Owner and its subcontractors to enter the Building.
|
4)
|
During Phase 2:
|
a)
|
Owner shall have the right to occupy and use the Building.
|
b)
|
Owner shall provide Contractor with reasonable access to complete all Remaining Work so long as such access does
|
c)
|
Contractor shall continue to provide utilities (temporary and permanent) to the Building.
|
d)
|
Owner will transport its personnel to the Building.
|
e)
|
Owner will perform preventive maintenance on the Building.
|
5)
|
Upon turnover of a Building, Owner shall bear the full risk of physical loss and damage to the Building;
provided, however,
notwithstanding the foregoing, Contractor shall remain fully responsible and liable to Owner for its Warranty and Corrective Work obligations under the Agreement.
|
6)
|
The Defect Correction Period for a Building shall commence upon the commencement of Phase 2 and end eighteen (18) months thereafter, as may be extended pursuant to Section 12.3 of the Agreement.
|
7)
|
Contractor shall maintain in full force and effect until turnover of a Building all coverage under Attachment O of the Agreement. Owner’s operational insurance shall cover a Building upon commencement of Phase 2.
|
8)
|
Owner shall manage Environmental, Safety & Health incidents involving Owner’s work within a Building, with Contractor’s reasonable assistance as needed on a cost reimbursable basis.
|
9)
|
The Parties selection of item [A] on page 2 of this Change Order, which states this Change Order
shall
constitute full and final settlement and accord of all effects of the change reflected in this Change Order upon the Changed Criteria and
shall
be deemed to compensate Contractor fully for such change, shall not prejudice Contractor’s right to a Change Order in accordance with Section 6.2A.2 and 8.2C(ii) arising from Owner’s occupation or use of the Buildings.
|
The original Contract Price was.........................................................................................................................
|
$
|
7,080,830,000
|
|
Net change by previously authorized Change Orders (0001-00045).................................................................
|
$
|
703,558,100
|
|
The Contract Price prior to this Change Order was...........................................................................................
|
$
|
7,784,388,100
|
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
—
|
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
—
|
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
7,784,388,100
|
|
The original Aggregate Equipment Price was...................................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00045).................................................................
|
$
|
***
|
The Aggregate Equipment Price prior to this Change Order was......................................................................
|
$
|
***
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
The new Aggregate Equipment Price including this Change Order will be .....................................................
|
$
|
***
|
The original Aggregate Labor and Skills Price was..........................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00045).................................................................
|
$
|
***
|
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................
|
$
|
***
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
***
|
The original Aggregate Provisional Sum was....................................................................................................
|
$
|
950,561,351
|
|
Net change by previously authorized Change Orders (0001-00045).................................................................
|
$
|
(812,283,979
|
)
|
The Aggregate Provisional Sum prior to this Change Order was......................................................................
|
$
|
138,277,372
|
|
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................
|
$
|
—
|
|
The new Aggregate Provisional Sum including this Change Order will be......................................................
|
$
|
138,277,372
|
|
/s/ Ed Lehotsky
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
Ed Lehotsky
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
September 28, 2018
|
|
September 13, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Corpus Christi Stage 1 Liquefaction Facility
OWNER:
Corpus Christi Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: December 6, 2013
|
CHANGE ORDER NUMBER:
CO-00047
DATE OF CHANGE ORDER:
October 3, 2018
|
1)
|
Pursuant to Article 6 of the Agreement, Parties agree Contractor will develop inspection isometric drawings and isometric through length tables.
|
2)
|
The scope of this Change Order is detailed in Exhibit 1 of this Change Order.
|
3)
|
The cost breakdown for the scope of this Change Order is detailed in Exhibit 2 of this Change Order. These costs are as detailed in Trend S1-2074.
|
4)
|
Schedule C-1
(Milestone Payment Schedule) of
Attachment C
of the Agreement will be amended by including the Milestone(s) listed in Exhibit 3 of this Change Order.
|
The original Contract Price was.........................................................................................................................
|
$
|
7,080,830,000
|
|
Net change by previously authorized Change Orders (0001-00046).................................................................
|
$
|
703,558,100
|
|
The Contract Price prior to this Change Order was...........................................................................................
|
$
|
7,784,388,100
|
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
7,785,265,107
|
|
The original Aggregate Equipment Price was...................................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00046).................................................................
|
$
|
***
|
The Aggregate Equipment Price prior to this Change Order was......................................................................
|
$
|
***
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
The new Aggregate Equipment Price including this Change Order will be .....................................................
|
$
|
***
|
The original Aggregate Labor and Skills Price was..........................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00046).................................................................
|
$
|
***
|
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................
|
$
|
***
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
***
|
The original Aggregate Provisional Sum was....................................................................................................
|
$
|
950,561,351
|
|
Net change by previously authorized Change Orders (0001-00046).................................................................
|
$
|
(812,283,979
|
)
|
The Aggregate Provisional Sum prior to this Change Order was......................................................................
|
$
|
138,277,372
|
|
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................
|
$
|
—
|
|
The new Aggregate Provisional Sum including this Change Order will be......................................................
|
$
|
138,277,372
|
|
/s/ David Craft
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
David Craft
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
October 15, 2018
|
|
October 3, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Corpus Christi Stage 1 Liquefaction Facility
OWNER:
Corpus Christi Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: December 6, 2013
|
CHANGE ORDER NUMBER:
CO-00048
DATE OF CHANGE ORDER:
November 13, 2018
|
•
|
West Jetty Marine Facility —Systems 024-06, 024-07, 024-10, 024-12, 024-14, 056-01, 040-16
|
•
|
LNG Tank A — System 024-01
|
•
|
Marine Flare — System 019-11
|
1)
|
“Phase 1” means the time period beginning upon the date this Change Order is executed and ending on the date a Facility is turned over to Owner.
|
2)
|
“Phase 2” means the time period beginning the date a Facility is turned over to Owner and ending on the date of Substantial Completion of Subproject 1.
|
3)
|
During Phase 1:
|
a)
|
Contractor shall perform Work to complete the Facility in accordance with the Agreement so that the Facility is ready for full occupancy and use and, to the extent required, and shall obtain a Certificate of Occupancy for each Facility.
|
b)
|
Contractor shall perform preventive maintenance on the Facility and its systems according to the operating and maintenance manuals.
|
c)
|
On or before the date a Facility is to be turned over to Owner, Owner and Contractor shall jointly inspect the Facility to determine and record whether the Work for the Facility is completed, other than Punchlist items that may be completed after turnover to Owner (such Punchlist items that may be completed after turnover is hereinafter referred to as “Remaining Work”). The Parties shall agree on the Remaining Work needed to be completed or corrected as a result of such inspection. Contractor shall complete the Work on the Facility prior to the commencement of Phase 2 other than the agreed upon Remaining Work.
|
d)
|
On or before the date a Facility is to be turned over to Owner, Contractor shall complete the Work for the Facility other than the Remaining Work and deliver to Owner the keys to the Facility as required. Upon such turnover, Owner shall maintain access control and security to and inside the Facility. Upon such turn over, Owner shall immediately take care, custody and control of the Facility.
|
4)
|
During Phase 2:
|
a)
|
Owner shall have the right to occupy and use the Facility.
|
b)
|
Owner shall provide Contractor with reasonable access to complete all Remaining Work so long as such access does not materially interfere with Owner’s use of the Facility. Such Remaining Work shall be conducted under Owner’s Permit to Work system.
|
c)
|
Owner will transport its personnel to the Facility.
|
d)
|
Owner will perform preventive maintenance on the Facility.
|
e)
|
Contractor shall continue to provide utilities (temporary and permanent) to the Facility as required.
|
5)
|
Upon commencement of Phase 2, Owner shall bear the full risk of physical loss and damage to the Facility;
provided, however,
notwithstanding the foregoing, Contractor shall remain fully responsible and liable to Owner for its Warranty and Corrective Work obligations under the Agreement.
|
6)
|
The Defect Correction Period for a Facility shall commence upon turnover at Phase 2 and end eighteen (18) months thereafter, as may be extended pursuant to Section 12.3 of the Agreement; provided however, for Equipment tied to Commissioning Tests (
e.g.
loading arms, related valves and piping, instrumentation, and PLC), the Defect Correction Period shall commence upon the achievement of each such Commissioning Test and Substantial Completion of Subproject 1 shall not be achieved until the achievement of each such Commissioning Test. Owner shall provide Contractor with access to the turned-over Facility sufficient to perform any Corrective Work and subject to any reasonable security or safety requirements of Owner.
|
7)
|
Contractor shall maintain in full force and effect all coverage under Attachment O of the Agreement; provided however, after completion of Phase 1, Contractor shall not be required to maintain Marine Terminal Operators Liability within the Marine General Liability coverage. Contractor’s builder’s risk insurance shall continue to cover all Facilities during Phase 2; provided, however, that Owner shall be responsible for the per occurrence deductible under Contractor’s builder’s risk policy to the extent damage to a turned-over Facility is caused by Owner Group. Owner’s operational insurance shall cover a Facility after the end of Phase 2.
|
8)
|
Owner shall maintain a marine terminal operator’s liability policy with limits of not less than $200,000,000 naming Contractor as additional insured and including an insurer’s waiver of subrogation in favor of Contractor.
|
9)
|
Owner shall manage Environmental, Safety & Health incidents involving Owner’s work within a Facility, with Contractor’s reasonable assistance as needed on a cost reimbursable basis.
|
10)
|
The Parties selection of item [A] on page 4 of this Change Order, which states this Change Order
shall
constitute full and final settlement and accord of all effects of the change reflected in this Change Order upon the Changed Criteria
shall
be deemed to compensate Contractor fully for such change, but shall not prejudice Contractor’s right to a Change Order in accordance with Section 6.2A.2 and 8.2C arising from Owner’s occupation or use of the Facilities.
|
The original Contract Price was.........................................................................................................................
|
$
|
7,080,830,000
|
|
Net change by previously authorized Change Orders (0001-00047).................................................................
|
$
|
704,435,107
|
|
The Contract Price prior to this Change Order was...........................................................................................
|
$
|
7,785,265,107
|
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
—
|
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
—
|
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
7,785,265,107
|
|
The original Aggregate Equipment Price was...................................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00047).................................................................
|
$
|
***
|
The Aggregate Equipment Price prior to this Change Order was......................................................................
|
$
|
***
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
The new Aggregate Equipment Price including this Change Order will be .....................................................
|
$
|
***
|
The original Aggregate Labor and Skills Price was..........................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00047).................................................................
|
$
|
***
|
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................
|
$
|
***
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
***
|
The original Aggregate Provisional Sum was....................................................................................................
|
$
|
950,561,351
|
|
Net change by previously authorized Change Orders (0001-00047).................................................................
|
$
|
(812,283,979
|
)
|
The Aggregate Provisional Sum prior to this Change Order was......................................................................
|
$
|
138,277,372
|
|
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................
|
$
|
—
|
|
The new Aggregate Provisional Sum including this Change Order will be......................................................
|
$
|
138,277,372
|
|
/s/ David Craft
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
David Craft
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
November 14, 2018
|
|
November 13, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Corpus Christi Stage 1 Liquefaction Facility
OWNER:
Corpus Christi Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: December 6, 2013
|
CHANGE ORDER NUMBER:
CO-00049
DATE OF CHANGE ORDER:
December 7, 2018
|
•
|
Water Treatment Plant — Systems 36-01, 36-02, 36-03, 36-04, 36-05, 36-08, 36-12, 36-13, 36-14 and 40-08
|
•
|
Sanitary System — Systems 29-05 and 29-11
|
•
|
Diesel/Gasoline System — Systems 21-01 and 21-02
|
•
|
Component 031-06R of the Electrical System
|
1)
|
“Phase 1” means the time period beginning upon the date this Change Order is executed and ending on the date a Facility is turned over to Owner.
|
2)
|
“Phase 2” means the time period beginning the date a Facility is turned over to Owner and ending on the date of Substantial Completion of Subproject 1.
|
3)
|
During Phase 1:
|
a)
|
Contractor shall perform Work to complete the Facility in accordance with the Agreement so that the Facility is ready for full occupancy and use and, to the extent required, and shall obtain a Certificate of Occupancy for each Facility.
|
b)
|
Contractor shall perform preventive maintenance on the Facility and its systems according to the operating and maintenance manuals.
|
c)
|
On or before the date a Facility is to be turned over to Owner, Owner and Contractor shall jointly inspect the Facility to determine and record whether the Work for the Facility is completed, other than Punchlist items that may be completed after turnover to Owner (such Punchlist items that may be completed after turnover is hereinafter referred to as “Remaining Work”). The Parties shall agree on the Remaining Work needed to be completed or corrected as a result of such inspection. Contractor shall complete the Work on the Facility prior to the commencement of Phase 2 other than the agreed upon Remaining Work.
|
d)
|
On or before the date a Facility is to be turned over to Owner, Contractor shall complete the Work for the Facility other than the Remaining Work and deliver to Owner the keys to the Facility as required. Upon such turnover, Owner shall maintain access control and security to and inside the Facility. Upon such turn over, Owner shall immediately take care, custody and control of the Facility.
|
4)
|
During Phase 2:
|
a)
|
Owner shall have the right to occupy and use the Facility.
|
b)
|
Owner shall provide Contractor with reasonable access to complete all Remaining Work so long as such access does not materially interfere with Owner’s use of the Facility. Such Remaining Work shall be conducted under Owner’s Permit to Work system.
|
c)
|
Owner will transport its personnel to the Facility.
|
d)
|
Owner will perform preventive maintenance on the Facility.
|
e)
|
Contractor shall continue to provide utilities (temporary and permanent) to the Facility as required.
|
5)
|
Upon commencement of Phase 2, Owner shall bear the full risk of physical loss and damage to the Facility;
provided, however,
notwithstanding the foregoing, Contractor shall remain fully responsible and liable to Owner for its Warranty and Corrective Work obligations under the Agreement.
|
6)
|
The Defect Correction Period for a Facility shall commence upon turnover at Phase 2 and end eighteen (18) months thereafter, as may be extended pursuant to Section 12.3 of the Agreement Owner shall provide Contractor with access to the turned-over Facility sufficient to perform any Corrective Work and subject to any reasonable security or safety requirements of Owner.
|
7)
|
Contractor shall maintain in full force and effect all coverage under Attachment O of the Agreement. Contractor’s builder’s risk insurance shall continue to cover all Facilities during Phase 2; provided, however, that Owner shall be responsible for the per occurrence deductible under Contractor’s builder’s risk policy to the extent damage to a turned-over Facility is caused by Owner Group. Owner’s operational insurance shall cover a Facility after the end of Phase 2.
|
8)
|
Owner shall manage Environmental, Safety & Health incidents involving Owner’s work within a Facility, with Contractor’s reasonable assistance as needed on a cost reimbursable basis.
|
9)
|
The Parties selection of item [A] on page 4 of this Change Order, which states this Change Order
shall
constitute full and final settlement and accord of all effects of the change reflected in this Change Order upon the Changed Criteria
shall
be deemed to compensate Contractor fully for such change, but shall not prejudice Contractor’s right to a Change Order in accordance with Section 6.2A.2 and 8.2C arising from Owner’s occupation or use of the Facilities.
|
The original Contract Price was.........................................................................................................................
|
$
|
7,080,830,000
|
|
Net change by previously authorized Change Orders (0001-00048).................................................................
|
$
|
704,435,107
|
|
The Contract Price prior to this Change Order was...........................................................................................
|
$
|
7,785,265,107
|
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
—
|
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
—
|
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
7,785,265,107
|
|
The original Aggregate Equipment Price was...................................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00048).................................................................
|
$
|
***
|
The Aggregate Equipment Price prior to this Change Order was......................................................................
|
$
|
***
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
The new Aggregate Equipment Price including this Change Order will be .....................................................
|
$
|
***
|
The original Aggregate Labor and Skills Price was..........................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00048).................................................................
|
$
|
***
|
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................
|
$
|
***
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
***
|
The original Aggregate Provisional Sum was....................................................................................................
|
$
|
950,561,351
|
|
Net change by previously authorized Change Orders (0001-00048).................................................................
|
$
|
(812,283,979
|
)
|
The Aggregate Provisional Sum prior to this Change Order was......................................................................
|
$
|
138,277,372
|
|
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................
|
$
|
—
|
|
The new Aggregate Provisional Sum including this Change Order will be......................................................
|
$
|
138,277,372
|
|
/s/ David Craft
|
|
/s/ Hatem Goucha
|
For Owner
|
|
For Contractor
|
David Craft
|
|
Hatem Goucha
|
Name
|
|
Name
|
SVP E&C
|
|
Project Manager
|
Title
|
|
Title
|
December 14, 2018
|
|
December 7, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Corpus Christi Stage 2 Liquefaction Facility
OWNER:
Corpus Christi Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: December 12, 2017
|
CHANGE ORDER NUMBER:
00007
DATE OF CHANGE ORDER:
October 15, 2018
|
1)
|
Pursuant to Article 6 of the Agreement, Parties agree Contractor will implement changes to incorporate revisions for tell-tale signs for leak detection and repair for Subproject 3.
|
2)
|
Pursuant to Article 6 of the Agreement, Parties agree Contractor will provide additional tie-ins at the East/West Jetty transition point and an additional tie-in in close proximity to Train 3. This Change Order is based on the work being performed under Greenfield conditions and not under Owner’s permit to work system.
|
3)
|
Pursuant to Article 6 of the Agreement, Parties agree Contractor will develop inspection isometric drawings and isometric through length tables for Subproject 3.
|
4)
|
The scope of this Change Order is detailed in Exhibit 1 of this Change Order.
|
5)
|
The cost breakdown for the scope of this Change Order is detailed in Exhibit 2 of this Change Order.
|
6)
|
Schedules C-1 and C-3
(Milestone Payment Schedules) of
Attachment C
of the Agreement will be amended by including the Milestone(s) listed in Exhibit 3 of this Change Order.
|
The original Contract Price was.........................................................................................................................
|
$
|
2,360,000,000
|
|
Net change by previously authorized Change Orders (0001-00006).................................................................
|
$
|
5,356,684
|
|
The Contract Price prior to this Change Order was...........................................................................................
|
$
|
2,365,356,684
|
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
2,370,262,606
|
|
The original Aggregate Equipment Price was...................................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00006).................................................................
|
$
|
***
|
The Aggregate Equipment Price prior to this Change Order was......................................................................
|
$
|
***
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
The new Aggregate Equipment Price including this Change Order will be .....................................................
|
$
|
***
|
The original Aggregate Labor and Skills Price was..........................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00006).................................................................
|
$
|
***
|
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................
|
$
|
***
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
***
|
The original Aggregate Provisional Sum was....................................................................................................
|
$
|
295,549,906
|
|
Net change by previously authorized Change Orders (0001-00006).................................................................
|
$
|
(1,463,531
|
)
|
The Aggregate Provisional Sum prior to this Change Order was......................................................................
|
$
|
294,086,375
|
|
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................
|
$
|
—
|
|
The new Aggregate Provisional Sum including this Change Order will be......................................................
|
$
|
294,086,375
|
|
/s/ David Craft
|
|
/s/ Bhupesh Thakkar
|
For Owner
|
|
Contractor
|
David Craft
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
October 25, 2018
|
|
October 15, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Corpus Christi Stage 2 Liquefaction Facility
OWNER:
Corpus Christi Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: December 12, 2017
|
CHANGE ORDER NUMBER:
00008
DATE OF CHANGE ORDER:
November 19, 2018
|
1.
|
Pursuant to the instructions in Section 2.3.B of Attachment EE, Schedule EE-2 of the Agreement, this Change Order amends the Insurance Provisional Sum amount to the Anticipated Actual Insurance Cost.
|
2.
|
The Insurance Provisional Sum in Section 2.3 of Attachment EE, Schedule EE-2 of the Agreement prior to this Change Order was Sixty Three Million, Six Hundred Fifty Three Thousand, Four Hundred Sixty Four U.S. Dollars (U.S. $63,653,464). The Insurance Provisional Sum is hereby decreased by Sixteen Million, Eight Hundred Nine Thousand, Two Hundred Twenty Six U. S. Dollars (U.S. $16,809,226) and the new value as amended by this Change Order shall be Forty Six Million, Eight Hundred Forty Four Thousand, Two Hundred Thirty Eight U.S. Dollars (U.S. $46,844,238).
|
3.
|
The cost breakdown for this Change Order is detailed in Exhibit 1 of this Change Order.
|
4.
|
Schedules C-2 Aggregate Labor and Skills Price Monthly Payment Schedule of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 2 of this Change Order.
|
5.
|
The final adjustment to the Insurance Provisional Sum will be made in accordance with Section 2.3.C of Attachment EE, Schedule EE-2 of the Agreement.
|
The original Contract Price was.........................................................................................................................
|
$
|
2,360,000,000
|
|
Net change by previously authorized Change Orders (0001-00007).................................................................
|
$
|
10,262,606
|
|
The Contract Price prior to this Change Order was...........................................................................................
|
$
|
2,370,262,606
|
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
2,353,453,380
|
|
The original Aggregate Equipment Price was...................................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00007).................................................................
|
$
|
***
|
The Aggregate Equipment Price prior to this Change Order was......................................................................
|
$
|
***
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
The new Aggregate Equipment Price including this Change Order will be .....................................................
|
$
|
***
|
The original Aggregate Labor and Skills Price was..........................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00007).................................................................
|
$
|
***
|
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................
|
$
|
***
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
***
|
The original Aggregate Provisional Sum was....................................................................................................
|
$
|
295,549,906
|
|
Net change by previously authorized Change Orders (0001-00007).................................................................
|
$
|
(1,463,531
|
)
|
The Aggregate Provisional Sum prior to this Change Order was......................................................................
|
$
|
294,086,375
|
|
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................
|
$
|
(16,809,226
|
)
|
The new Aggregate Provisional Sum including this Change Order will be......................................................
|
$
|
277,277,149
|
|
/s/ David Craft
|
|
/s/ Bhupesh Thakkar
|
For Owner
|
|
Contractor
|
David Craft
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
November 27, 2018
|
|
November 19, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Corpus Christi Stage 2 Liquefaction Facility
OWNER:
Corpus Christi Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: December 12, 2017
|
CHANGE ORDER NUMBER:
00009
DATE OF CHANGE ORDER:
November 28, 2018
|
1.
|
Pursuant to Article 6 of the Agreement, Parties agree Contractor will be compensated for costs associated with the Department of Transportation’s Federal Motor Carrier Safety Administration requirement for inland freight companies to incorporate the installation of Electronic Logging Devices resulting in increased costs by trucking companies.
|
2.
|
The cost breakdown for this Change Order is detailed in Exhibit 1 of this Change Order. Costs are further detailed in approved trend S2-0023.
|
3.
|
Schedule C-2 Aggregate Equipment Price Milestone Payment Schedule of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit 2 of this Change Order.
|
The original Contract Price was.........................................................................................................................
|
$
|
2,360,000,000
|
|
Net change by previously authorized Change Orders (0001-00008).................................................................
|
$
|
(6,546,620
|
)
|
The Contract Price prior to this Change Order was...........................................................................................
|
$
|
2,353,453,380
|
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
2,356,296,369
|
|
The original Aggregate Equipment Price was...................................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00008).................................................................
|
$
|
***
|
The Aggregate Equipment Price prior to this Change Order was......................................................................
|
$
|
***
|
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................
|
$
|
***
|
The new Aggregate Equipment Price including this Change Order will be .....................................................
|
$
|
***
|
The original Aggregate Labor and Skills Price was..........................................................................................
|
$
|
***
|
Net change by previously authorized Change Orders (0001-00008).................................................................
|
$
|
***
|
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................
|
$
|
***
|
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................
|
$
|
***
|
The new Contract Price including this Change Order will be...........................................................................
|
$
|
***
|
The original Aggregate Provisional Sum was....................................................................................................
|
$
|
295,549,906
|
|
Net change by previously authorized Change Orders (0001-00008).................................................................
|
$
|
(18,272,757
|
)
|
The Aggregate Provisional Sum prior to this Change Order was......................................................................
|
$
|
277,277,149
|
|
The Aggregate Provisional Sum will be unchanged by this Change Order in the amount of...........................
|
$
|
—
|
|
The new Aggregate Provisional Sum including this Change Order will be......................................................
|
$
|
277,277,149
|
|
/s/ David Craft
|
|
/s/ Bhupesh Thakkar
|
For Owner
|
|
Contractor
|
David Craft
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
November 28, 2018
|
|
November 28, 2018
|
Date of Signing
|
|
Date of Signing
|
Entity Name
|
|
Jurisdiction of Incorporation
|
Caldera LNG Holdings SpA
|
|
Chile
|
Cheniere Cares, Inc.
|
|
Texas
|
Cheniere Chile SpA
|
|
Chile
|
Cheniere CCH HoldCo I, LLC
|
|
Delaware
|
Cheniere CCH HoldCo II, LLC
|
|
Delaware
|
Cheniere Corpus Christi Holdings, LLC
|
|
Delaware
|
Cheniere Corpus Christi Pipeline, L.P.
|
|
Delaware
|
Cheniere Creole Trail Pipeline, L.P.
|
|
Delaware
|
Cheniere Energy Investments, LLC
|
|
Delaware
|
Cheniere Energy Operating Co., Inc.
|
|
Delaware
|
Cheniere Energy Partners GP, LLC
|
|
Delaware
|
Cheniere Energy Partners LP Holdings, LLC
|
|
Delaware
|
Cheniere Energy Partners, L.P.
|
|
Delaware
|
Cheniere Energy Shared Services, Inc.
|
|
Delaware
|
Cheniere Field Services, LLC
|
|
Delaware
|
Cheniere GP Holding Company, LLC
|
|
Delaware
|
Cheniere Ingleside Marine Terminal, LLC
|
|
Delaware
|
Cheniere International Investments Holdings, S.à.r.l
|
|
Luxembourg
|
Cheniere International Investments, S.à.r.l
|
|
Luxembourg
|
Cheniere Land Holdings, LLC
|
|
Delaware
|
Cheniere Liquids, LLC
|
|
Delaware
|
Cheniere LNG Holdings GP, LLC
|
|
Delaware
|
Cheniere LNG O&M Services, LLC
|
|
Delaware
|
Cheniere LNG Terminals, LLC
|
|
Delaware
|
Cheniere Major Project Development, LLC
|
|
Delaware
|
Cheniere Marketing International HoldCo I, L.P.
|
|
Bermuda
|
Cheniere Marketing International HoldCo II, Ltd.
|
|
Bermuda
|
Cheniere Marketing International, LLP
|
|
United Kingdom
|
Cheniere Marketing, LLC
|
|
Delaware
|
Cheniere Marketing, Ltd.
|
|
United Kingdom
|
Cheniere Marketing PTE Ltd.
|
|
Singapore
|
Cheniere Midship Holdings, LLC
|
|
Delaware
|
Cheniere Midstream Holdings, Inc.
|
|
Delaware
|
Cheniere Pipeline GP Interests, LLC
|
|
Delaware
|
Cheniere Pipeline Holdings, LLC
|
|
Delaware
|
Cheniere San Patricio Processing Hub, LLC
|
|
Delaware
|
Cheniere Southern Trail GP, Inc.
|
|
Delaware
|
Cheniere SPH Pipeline, LLC
|
|
Delaware
|
Cheniere Supply & Marketing, Inc.
|
|
Delaware
|
Concepción LNG Holding SpA
|
|
Chile
|
Corpus Christi Liquefaction, LLC
|
|
Delaware
|
Entity Name
|
|
Jurisdiction of Incorporation
|
Corpus Christi Liquefaction Stage II, LLC
|
|
Delaware
|
Corpus Christi Liquefaction Stage III, LLC
|
|
Delaware
|
Corpus Christi Liquefaction Stage IV, LLC
|
|
Delaware
|
Corpus Christi LNG, LLC
|
|
Delaware
|
Corpus Christi Pipeline GP, LLC
|
|
Delaware
|
Corpus Christi Tug Services, LLC
|
|
Delaware
|
CQH Holdings Company, LLC
|
|
Delaware
|
CUI I, LLC
|
|
Delaware
|
Live Oak LNG Holdings, LLC
|
|
Delaware
|
Louisiana LNG Holdings, LLC
|
|
Delaware
|
Midship Holdings, LLC
|
|
Delaware
|
Midship Pipeline Company, LLC
|
|
Delaware
|
Nordheim Eagle Ford Gathering, 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, Inc.;
|
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, Inc.
|
1.
|
I have reviewed this
annual report on Form 10-K
of Cheniere Energy, Inc.;
|
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, Inc.
|
(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 Company.
|
/s/ Jack A. Fusco
|
Jack A. Fusco
Chief Executive Officer of |
Cheniere Energy, Inc.
|
(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 Company.
|
/s/ Michael J. Wortley
|
Michael J. Wortley
Chief Financial Officer of |
Cheniere Energy, Inc.
|