CHENIERE
ENERGY
PARTNERS, L.P.
2015 ANNUAL REPORT
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NOTE REGARDING FORWARD-LOOKING STATEMENTS
The Chairman’s Letter, Cheniere Partners at a Glance and 2015 Highlights sections contain forward-looking statements relating to, among other things, business strategy,
performance and expectations for project development. The reader is cautioned not to rely on these statements and should review the section “Cautionary Statement
Regarding Forward-Looking Statements” on page iv of this Annual Report for important information about these statements, including the risks, uncertainties and other factors
that could cause actual results to vary materially from the assumptions, expectations, and projections expressed in any forward-looking statements. These forward-looking
statements speak only as of the date made, and other than as required by law, we under take no obligation to publicly update or revise any forward-looking statement, whether
as a result of new information, future events or developments or otherwise.
DEAR UNITHOLDERS,
2015 was a pivotal year for Cheniere Energy Partners, L.P. (Cheniere Partners), leading to the
achievement of our most significant milestone yet - the export of the first commissioning cargo
with liquefied natural gas (LNG) produced from our Sabine Pass liquefaction project (the SPL Project)
located in Cameron Parish, Louisiana.
The LNG carrier Asia Vision departed from Sabine Pass in late February 2016, marking the first LNG cargo to be exported with
domestically produced LNG from the Lower 48 in over 50 years. This historic event opens a new chapter for U.S. energy trade, with
the U.S. expected to become one of the top three global LNG suppliers by 2020; and for Cheniere Partners, which has begun its
transformation from a development company into an LNG operator, with an LNG platform under construction that has an expected
aggregate nominal production capacity of 22.5 mtpa of LNG. This capacity is expected to represent over a third of the U.S. export
capacity by 2020.
To date we have contracted approximately 88% of the expected aggregate nominal production capacity for Trains 1 through 5
of the SPL Project under long-term sale and purchase agreements (SPAs) with third-party investment grade customers, totaling
approximately $2.9 billion in annual fixed fees once these trains are operational. Construction on the first train of the SPL Project is
complete and it is expected to reach substantial completion shortly. The other four trains are under construction and are expected
to reach substantial completion on a staggered basis.
The energy industry is weathering a protracted decline in prices as a result of surging oil supply, macroeconomic concerns and
geopolitical uncertainty. Brent oil prices fell from approximately $55 per barrel at the start of 2015 to below $30 per barrel in
January 2016, the lowest price level in 13 years. Oil markets have been pressured by worries over the economic outlook in key
consuming markets amid robust global supplies. U.S. oil production has remained particularly resilient despite a sharp contraction
in investment and drilling. As a result, softening global oil prices have depressed values across the energy complex, including
prices for natural gas and LNG. Low LNG and natural gas prices are stimulating incremental price-sensitive natural gas demand
and opening up new LNG markets eager to take advantage of the affordable, cleaner burning fuel. This is particularly apparent in
the power sector, where affordable natural gas has the opportunity to displace coal and fuel oil in power generation as well as act
as a catalyst for bringing cleaner-burning power to emerging economies. Additionally, as demonstrated in 2015, floating storage
and regasification units (FSRUs) can be rapidly deployed, facilitating the opening of new markets and accelerating LNG demand.
Early on, Cheniere Partners differentiated itself in the LNG market by offering global LNG buyers more attractive features and
contract terms, including (1) an alternative pricing mechanism, basing LNG prices on a natural gas index as opposed to a traditional
crude-based index, (2) destination flexibility, allowing customers to determine delivery points, as opposed to the traditionally
restricted delivery locations and (3) the option to take delivery or not, provided required notice is given. In comparison to other
LNG facilities being developed in the U.S., Cheniere Partners is procuring natural gas and selling LNG to customers at the tailgate
of the plant versus offering a tolling model whereby the customer has to procure its own feedstock and is just paying for the
liquefaction process.
We believe our business model and favorable contract features will enable us to successfully navigate a cyclical commodity
environment and support long-term value creation for our unitholders. We have substantially limited our exposure to LNG price
volatility by contracting a significant portion of the expected aggregate nominal production capacity of the five trains currently
under construction or completed under 20-year SPAs with a portion of the LNG contract sales price based on a fixed fee. Under the
SPAs, our LNG pricing includes two components - 115% of the final settlement price for the NYMEX Henry Hub index for the month
in which a cargo is scheduled, plus a fixed fee. This fee is expected to cover Cheniere Partners’ costs and unitholders’ return. We
expect to generate a significant amount of predictable, stable cash flows annually, over the lives of the contracts, as the fixed fees
are required to be paid even if customers elect to cancel or suspend deliveries of LNG cargoes. Our SPAs are with investment-grade
off-takers featuring the parents as counterparties or guarantors. Additionally, unlike many traditional global LNG agreements, our
contracts do not have price re-openers, so we do not have the same risk of contract re-negotiation as some other LNG suppliers.
Nations continue to seek access to abundant, reliable and environmentally clean energy sources to meet increases in energy demand
and/or more environmentally friendly fuel sources to reduce their carbon footprint. The global demand potential for natural gas
was underscored by the historic international agreement reached at the 2015 Paris Climate Conference. Over 185 countries have
pledged to limit or reduce their greenhouse gas emissions to minimize future climate impacts. Although implementation plans
remain to be worked out, natural gas is expected to have a key role in the policy options to reduce emissions.
Today the LNG market comprises about 10% of the global natural gas market, equivalent to about 33 Bcf/d. Approximately 20% of
the global natural gas market is currently supplied by international pipelines. Natural gas demand is expected to increase due to
fuel displacement and incremental power generation demand. Additionally, new LNG sources will be needed as supply from some
of the traditional producing basins declines. As a result, global LNG demand is expected to nearly double from 2015 to 2030 and to
account for up to 15% of the global natural gas market.
LNG/Global Gas Market
2014 global gas
consumption (328 bcf/d)
LNG as a share of global gas
nal trade ~ 3
0 %
10%
LNG
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19%
Pipeline
71%
Domestic
consumption
0
7
9
1
5
7
9
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8
9
1
5
8
9
1
0
9
9
1
5
9
9
1
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0
0
2
5
0
0
2
0
1
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2
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5
2
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3
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16%
14%
12%
10%
8%
6%
4%
2%
0%
Current forecasts suggest that
LNG will account for up to 13% of
all natural gas consumed by 2020
and up to 15% by 2030
Source: Actuals 2014: BP Statistical Review of World Energy June 2015
Actuals 1970-2010: CEDIGAZ (2011) Outlook: IHS and Wood Mackenzie data (2015)
Beginning early next decade, the gap between LNG demand and supply is expected to continue to widen and approximately 190
mtpa of incremental LNG supply is projected to be needed by 2030. Assuming industry average utilization rates, this equates to
approximately 230 mtpa of incremental production capacity, or 45 LNG trains (with production capacity similar to ours) required
to reach a final investment decision (FID) by 2025 in order to meet forecasted demand by 2030. While current market perception
appears to be that there is an oversupply of LNG, we believe this to be temporary and that additional projects need to start reaching
FID within the next year or two in order to meet the expected demand growth in the coming years.
Global LNG Trade
An estimated 190 mtpa of
additional LNG supply will
be needed by 2030 to meet
projected market demands
Sources: Cheniere interpretation of Wood Mackenzie data (Q4 2015)
We believe the U.S. continues to be a compelling option for global LNG buyers given existing infrastructure, a favorable regulatory
environment and low cost of natural gas supply. The domestic energy industry is deploying fewer resources to produce more
natural gas than ever before, highlighting the dramatic productivity gains that have underpinned the U.S. unconventional energy
boom of the last decade. The U.S. Energy Information Administration (EIA) estimates marketed U.S. natural gas production of 28.88
trillion cubic feet in 2015, a level that would mark a new high and the
fifth consecutive year that U.S. natural gas production has eclipsed
historical records. This achievement is remarkable given that gas-
directed drilling in 2015 fell to an all-time low based on rig data dating
from 1987, according to Baker Hughes. We believe domestic natural
gas supply will continue to be abundant and produced at a low cost.
Industry consultant IHS recently estimated that the U.S. Lower 48
and Canada hold approximately 800 Tcf of recoverable natural gas
resources, or approximately 25 years of supply at 2015 production
levels, which can be produced at $3/MMBtu or less.
North America is a low-cost
supplier, ~800 Tcf of natural
gas reserves can be produced
at $3/MMBtu or less in
Lower 48 and Canada
Against this backdrop, we are currently developing an LNG platform with six trains, or 27 mtpa of expected aggregate nominal
production capacity of LNG. We plan to continue our strategy of contracting a substantial portion of the expected nominal
production capacity with long-term SPAs before commencing construction. We expect to have two trains operating in 2016 as
the second train of the SPL Project is expected to commence operations and reach substantial completion in the second half of
the year.
Our priorities remain focused on executing construction of the trains, which continues to progress on budget and ahead of
contractual schedules, and on the transition of Cheniere Partners into an operating company. I believe that strong governance and
corporate culture are important factors for a successful transition, and in my role as interim CEO I am working with the management
team to ensure that we continue to strive for best practices. Additionally, the board is actively engaged in looking for the ideal CEO
candidate, one whom we expect to have operational experience coupled with a disciplined approach to future growth, and I will
continue to serve in this role until the new CEO is on board.
Sincerely,
Neal Shear
Chairman of the Board and Interim CEO
CHENIERE PARTNERS AT A GLANCE:
FIRST MOVER IN U.S. LNG EXPORTS
2016 marks the commencement of operations as we begin our transition to a significant global
LNG supplier.
LNG TERMINAL
Our world-class SPL Project is strategically situated along the Gulf of
Mexico, one of the most prolific gas and crude oil producing regions
in the U.S.
We have completed one
liquefaction train and are currently
constructing four more, with a total expected aggregate nominal
production capacity of 22.5 mtpa of LNG, which represents around 6%(1)
of the total expected global LNG market by 2020. Construction of our
facility is several years ahead of other U.S. LNG projects, providing us
with a significant first- mover advantage. We have a balanced portfolio
approach, with approximately 88% of this capacity already sold under
long-term SPAs based on fixed fees, substantially limiting our exposure
to LNG price volatility in the global energy markets.
Our business model differs from other U.S. LNG projects in that we will
procure the natural gas supply used for feedstock and the liquefaction
process. Once the natural gas is liquefied, the customer takes delivery
at the tailgate of the terminal. As a result, Cheniere Partners is expected
to become one of the largest U.S. buyers of natural gas once our facility
is operational. We have built a world-class operation to advantageously
acquire feedstock for the SPL Project. Our gas procurement business
has secured long-term transportation capacity on many pipelines
connected to and upstream of our facility. We have redundant capacity
from multiple pipelines to ensure reliable gas deliverability and diverse
access to multiple producing basins. We have also entered into several
supply arrangements to purchase natural gas from suppliers at prices
discounted to applicable market indices. In addition to our favorable
location, we have a competitive advantage in that we offer pricing
indexed to Henry Hub, destination flexibility, and the option to take
delivery of the LNG.
FUTURE DEVELOPMENTS
Our core competencies, scale and first-mover advantage create a
leading platform to capitalize on new opportunities in energy. Our
LNG platform will enable opportunistic investments for integration
into midstream or downstream markets. We are currently developing
five trains with 22.5 mtpa of expected aggregate nominal production
capacity of LNG.
(1) Source: Woodmac Q1 2016 outlook = 369 mtpa of global LNG demand in 2020
(2) of expected aggregate nominal production capacity of LNG
Competitive advantage
• Price indexed to Henry Hub
• Destination flexibility
• Customer has option to lift LNG
• Natural gas procurement
Platform capacity
~6% of expected global
LNG market by 2020
• 22.5 mtpa(2) currently under construction
~88% of LNG volumes
contracted
• 20-year contracts with fixed fees
• Parent as counterparty or guarantor
~$2.9 billion in aggregate
annual fixed fees
• Stable cash flows anticipated
underpinned by investment grade
counterparties
A RESPONSIBLE CORPORATE LEADER
We are a responsible corporate leader in the communities where we operate and our employees live.
Our commitment is demonstrated through programs like the Cheniere Community Investment Councils. The Councils consist of
local employees who identify needs within their communities and target philanthropy where action is most impactful. In 2015, the
Councils donated to schools, universities and civic organizations. Their efforts helped support local senior citizen groups, a shelter
for at-risk women, sustenance for the less fortunate, and research to end life-threatening diseases, among many other causes.
Cheniere Partners empowers our people to connect with their communities. Through the Cheniere Ambassador Grant program,
every employee has the opportunity to direct a corporate contribution to a charity of his or her choice. In 2015, the program
contributed to nearly 90 charities and civic organizations. This year, nearly 50 employees joined together to donate to the Shriners
Hospital in Galveston, Texas, to support reconstructive and rehabilitative care for children with acute burns and other skin conditions.
We are also investing in youth and education by expanding our Youth Leadership Enrichment and Development (LEAD) program
to engage our next generation of local community leaders in public service. We provided funding to each LEAD Council to help
identify, fund and organize local community service projects. In 2015, LEAD Councils installed classroom equipment at high schools
in Cameron Parish, Louisiana and donated gifts to the local elderly.
Cheniere Partners is engaged in community service across the Gulf Coast. In 2015, we funded renovations to the Johnson Bayou
Rural Health Clinic in southwestern Louisiana and contributed to local law enforcement and first responders. We also supported the
National Hurricane Museum and Science Center in Lake Charles, Louisiana.
We are honored to be a part of the fabric of the Gulf Coast and look forward to building upon our tradition of service and
responsible citizenship.
CREATING JOBS AND OPPORTUNITIES
Cheniere Partners is creating jobs and helping communities across the Gulf Coast prepare for
tomorrow’s job opportunities.
Our SPL Project is expected to create 640 permanent jobs and support approximately 100,000 indirect jobs when operational.
A study by Loren Scott & Associates estimates that the SPL Project construction will support over 30,000 jobs nationwide, including
nearly 6,400 jobs in Louisiana – representing more employment than in 14 parishes in the state.
We are helping Gulf Coast communities seize this opportunity by developing programs that foster proficiency in technical training
like welding, process technology, instrumentation and industrial automation.
Cheniere Partners’ Values in Action (VIA) program provides scholarships and internship opportunities to technical school students
enrolled in process technology programs located near our projects. The success of our VIA candidates demonstrates the untapped
potential in local labor markets.
In 2015, Cheniere Partners established a Craft Development program to help workers gain advanced industrial skills valuable to
our projects. The Craft Development program is helping both graduating high school students and military veterans. We provide
welding training through partnering colleges, technical schools and U.S. Army installations and advanced training at a Cheniere-
sponsored facility. Our military partnership is one of the first of its kind for the U.S. Army. Graduates of the 6 - 18 month Craft
Development curriculum depart with the specialized skills required to build advanced industrial projects. Some of the first graduates
are now employed as welders on our SPL Project.
2015 HIGHLIGHTS
Sabine Pass Terminal: 6 Train Development
Construction continues on an accelerated schedule and on budget.
Liquefaction Trains Completed/Under Construction
•
•
•
•
•
SPL
Project
Commence
Operations
Status
Train 2
Train 1
Commissioning
Construction of Train 1 was completed in 2015, and the first LNG
commissioning cargo was launched in February 2016. We expect
to reach substantial completion and commence commercial
operations in 1H 2016.
Commissioning has begun on Train 2 and based on our current
schedule, we anticipate reaching substantial completion and
commencing commercial operations in 2H 2016.
Construction on Trains 3 and 4 began in May 2013, and as of
March 2016, the overall project completion percentage was approximately 84%. We expect these trains to commence
operations in 2017.
Train 5 is under construction with operations expected to commence in 2019.
Train 6 will reach FID upon entering into an EPC contract, entering into acceptable commercial arrangements and
obtaining adequate financing.
Under Construction
Under Construction
Under Construction
Commissioning
2H 2019
1H 2017
2H 2016
1H 2016
2H 2017
Train 3
Train 5
Train 4
An LNG carrier at the Sabine Pass Terminal - March 2016
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 001-33366
Cheniere Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware
20-5913059
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
700 Milam Street, Suite 1900
Houston, Texas
(Address of principal executive offices)
77002
(Zip Code)
Registrant’s telephone number, including area code: (713) 375-5000
Securities registered pursuant to Section 12(b) of the Act:
Common Units Representing Limited Partner Interests
(Title of Class)
NYSE MKT
(Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter
period that the registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and
will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Accelerated filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
The aggregate market value of the registrant’s common units held by non-affiliates of the registrant was approximately $1.4 billion as of June 30, 2015.
The registrant had 57,102,848 common units, 145,333,334 Class B units and 135,383,831 subordinated units outstanding as of February 12, 2016.
Documents incorporated by reference: None
CHENIERE ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Items 1. and 2. Business and Properties
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosure
PART I
PART II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 10. Directors, Executive Officers of Our General Partner and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Unitholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
PART III
Item 14. Principal Accountant Fees and Services
Item 15. Exhibits and Financial Statement Schedules
Signatures
PART IV
1
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123
i
As commonly used in the liquefied natural gas industry, to the extent applicable and as used in this annual report, the terms
listed below have the following meanings:
DEFINITIONS
Common Industry and Other Terms
Bcf/d
Bcf/yr
Bcfe
DOE
EPC
FERC
FTA countries
GAAP
Henry Hub
LIBOR
LNG
MMBtu
mtpa
non-FTA countries
SEC
SPA
Train
TUA
billion cubic feet per day
billion cubic feet per year
billion cubic feet equivalent
U.S. Department of Energy
engineering, procurement and construction
Federal Energy Regulatory Commission
countries with which the United States has a free trade agreement providing for national treatment for
trade in natural gas
generally accepted accounting principles in the United States
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
London Interbank Offered Rate
liquefied natural gas, a product of natural gas consisting primarily of methane (CH4) that is in liquid
form at near atmospheric pressure
million British thermal units, an energy unit
million tonnes per annum
countries without a free trade agreement providing for national treatment for trade in natural gas and
with which trade is permitted
Securities and Exchange Commission
LNG sale and purchase agreement
An industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into
LNG
terminal use agreement
ii
Abbreviated Organizational Structure
The following diagram depicts our abbreviated organizational structure as of December 31, 2015, including our
ownership of certain subsidiaries, and the references to these entities used in this annual report:
Unless the context requires otherwise, references to “Cheniere Partners,” “the Partnership,” “we,” “us” and “our” refer to
Cheniere Energy Partners, L.P. (NYSE MKT: CQP) and its consolidated subsidiaries, including SPLNG, SPL and CTPL.
References to “Blackstone Group” refer to The Blackstone Group, L.P. References to “Blackstone CQP Holdco” refer to
Blackstone CQP Holdco LP. References to “Blackstone” refer to Blackstone Group and Blackstone CQP Holdco.
iii
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All
statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking
statements.” Included among “forward-looking statements” are, among other things:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
statements regarding our ability to pay distributions to our unitholders;
statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL;
statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities,
pipeline facilities or other projects, or any expansions 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 ability to enter into such transactions;
statements relating to the construction of our Trains, including statements concerning the engagement of any EPC
contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor,
and anticipated costs related thereto;
statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including
any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total
LNG regasification, liquefaction or storage capacities that are, or may become, subject to contracts;
statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
statements regarding our planned development and construction of additional Trains, including the financing of such
Trains;
statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts,
projections, or objectives, including anticipated revenues and capital expenditures, any or all of which are subject to
change;
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals,
requirements, permits, applications, filings, investigations, proceedings or decisions; and
(cid:129)
any other statements that relate to non-historical or future information.
All of these types of statements, other than statements of historical fact, are forward-looking statements. In some cases,
forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,”
“intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or
other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations,
which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment
based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are
inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to
be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future
performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual
results may differ materially from those anticipated or implied in forward-looking statements due to factors described in this annual
report and in the other reports and other information that we file with the SEC. These forward-looking statements speak only as
of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking
statement, whether as a result of new information, future events or otherwise.
iv
ITEMS 1. AND 2.
BUSINESS AND PROPERTIES
General
PART I
We are a publicly traded Delaware limited partnership formed by Cheniere in 2006. Through our wholly owned subsidiary,
SPLNG, we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine-Neches Waterway
less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage
tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000
cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We are developing and constructing natural
gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification
facilities through our wholly owned subsidiary, SPL. We are constructing five Trains and developing a sixth Train, each of which
is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. We also own a 94-mile pipeline that
interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through our
wholly owned subsidiary, CTPL.
LNG is 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. The liquefaction of natural gas into LNG allows it to be shipped economically from
areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and
infrastructure exist to justify economically the use of LNG. LNG is transported using large oceangoing LNG tankers specifically
constructed for this purpose. LNG regasification facilities offload LNG from LNG tankers, store the LNG prior to processing,
heat the LNG to return it to a gaseous state and deliver the resulting natural gas into pipelines for transportation to market. Although
results are consolidated for financial reporting, Cheniere Partners, SPL, SPLNG and CTPL operate with independent capital
structures.
The following diagram depicts our abbreviated capital structure as of December 31, 2015:
1
Our Business Strategy
Our primary business strategy is to develop, construct and operate assets supported by long-term, fixed fee contracts. We
plan to implement our strategy by:
(cid:129)
(cid:129)
completing construction and commencing operation of the first five Trains of the Liquefaction Project;
obtaining the requisite long-term commercial contracts and financing to reach a final investment decision (“FID”)
regarding Train 6 of the Liquefaction Project;
(cid:129)
developing and operating our Trains safely, efficiently and reliably;
(cid:129) making LNG available to our long-term SPA customers to generate steady and reliable revenues and operating cash flows;
(cid:129)
(cid:129)
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safely maintaining and operating the Sabine Pass LNG terminal and the Creole Trail Pipeline;
developing business relationships for the marketing of additional long-term and short-term agreements for additional
LNG volumes at the Sabine Pass LNG terminal; and
expanding our existing asset base through acquisitions from Cheniere or third parties or our own development of the
Liquefaction Project or complementary businesses or assets such as other LNG facilities, midstream assets, natural gas
storage assets and natural gas pipelines.
Our Business
We have constructed and are operating regasification facilities at the Sabine Pass LNG terminal and are developing and
constructing the Liquefaction Project.
Regasification Facilities
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG
storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG
terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed
monthly fees, whether or not they use the LNG terminal. Each of Total Gas & Power North America, Inc. (“Total”) and Chevron
U.S.A. Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity
payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009. Total S.A. has
guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has
guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.
The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make
monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after
SPL delivers its first commercial cargo at the Liquefaction Project. SPL entered into a partial TUA assignment agreement with
Total, whereby SPL will progressively gain access to Total’s capacity and other services provided under Total’s TUA with SPLNG.
This agreement will provide SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used
to accommodate the development of Trains 5 and 6, provide increased flexibility in managing LNG cargo loading and unloading
activity starting with the commencement of commercial operations of Train 3 and permit SPL to more flexibly manage its LNG
storage capacity with the commencement of Train 1. Notwithstanding any arrangements between Total and SPL, payments required
to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.
Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.
Liquefaction Facilities
The Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal adjacent to the existing
regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We
commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in
August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In June 2015, we commenced
construction of Train 5 and the related facilities.
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The DOE has authorized the export of up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of
domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries for a 30-year term and to non-FTA
countries for a 20-year term. The DOE further issued an order authorizing SPL to export up to the equivalent of approximately
203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period. SPL’s
application for authorization to export that same 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal
to non-FTA countries is currently pending at the DOE. Additionally, the DOE issued orders authorizing SPL to export up to a
combined total of 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries and non-FTA
countries for a 20-year term. A party to the proceeding requested a rehearing of the non-FTA order pertaining to the 503.3 Bcf/
yr, and the DOE has not yet issued a final ruling on the rehearing request. In each case, the terms of these authorizations begin
on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 5 to 10 years
from the date the order was issued. Furthermore, the DOE issued an order authorizing SPL to export up to 600 Bcf in total of
domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-
year period commencing on January 15, 2016.
As of December 31, 2015, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction
Project were approximately 97.4% and 79.5%, respectively. As of December 31, 2015, the overall project completion percentage
for Train 5 of the Liquefaction Project was approximately 14.9% with engineering, procurement and construction approximately
41.9%, 20.5% and 0.1% complete, respectively. As of December 31, 2015, the overall project completion of each of our Trains
was ahead of the contractual schedule. We produced our first LNG from Train 1 of the Liquefaction Project in February 2016.
Based on our current construction schedule, we anticipate that Train 2 will produce LNG as early as mid-2016 and Trains 3 through
5 are expected to commence operations on a staggered basis thereafter.
The following table summarizes significant milestones and anticipated completion dates in the development of the
Liquefaction Project:
Milestone
DOE export authorization
Definitive commercial agreements
BG Gulf Coast LNG, LLC
Gas Natural Aprovisionamientos SDG S.A.
Korea Gas Corporation
GAIL (India) Limited
Total
Centrica plc
EPC contracts
Financing
FERC authorization
Issue Notice to Proceed
Commence operations
Customers
Target Date
Trains 1 - 5
Received
Completed
19.75 mtpa
5.5 mtpa
3.5 mtpa
3.5 mtpa
3.5 mtpa
2.0 mtpa
1.75 mtpa
Completed
Completed
Completed
Completed
2016 - 2019
SPL has entered into six fixed price, 20-year SPAs with third parties that in the aggregate equate to approximately 19.75
mtpa of LNG, which is approximately 88% of the expected aggregate nominal production capacity of Trains 1 through 5, that
commence with the date of first commercial delivery for Trains 1 through 5. Under these SPAs, the customers will purchase LNG
from SPL for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers
may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee
with respect to the contracted volumes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for
inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the
term of each SPA commences upon the start of operations of a specified Train. As of December 31, 2015, SPL had the following
third-party SPAs:
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(cid:129) BG Gulf Coast LNG, LLC (“BG”) has entered into an SPA that commences upon the date of first commercial delivery
for Train 1 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $2.25 per MMBtu
and includes additional annual contract quantities of 36,500,000 MMBtu, 34,000,000 MMBtu and 33,500,000 MMBtu
upon the date of first commercial delivery for Trains 2, 3 and 4, respectively, with a fixed fee of $3.00 per MMBtu. The
total expected annual contracted cash flow from BG from fixed fees is approximately $723 million. In addition, SPL has
agreed to make up to 500,000 MMBtu/d of LNG available to BG to the extent that Train 1 becomes commercially operable
prior to the beginning of the first delivery window with a fixed fee of $2.25 per MMBtu, if produced. The obligations
of BG are guaranteed by BG Energy Holdings Limited, a company organized under the laws of England and Wales.
(cid:129) Gas Natural Aprovisionamientos SDG S.A. (“Gas Natural Fenosa”) has entered into an SPA that commences upon the
date of first commercial delivery for Train 2 and includes an annual contract quantity of 182,500,000 MMBtu of LNG
with a fixed fee of $2.49 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately
$454 million. In addition, SPL has agreed to make up to 285,000 MMBtu/d of LNG available to Gas Natural Fenosa to
the extent that Train 2 becomes commercially operable prior to the beginning of the first delivery window with a fixed
fee of $2.49 per MMBtu, if produced. The obligations of Gas Natural Fenosa are guaranteed by Gas Natural SDG S.A.,
a company organized under the laws of Spain.
(cid:129) Korea Gas Corporation (“KOGAS”) has entered into an SPA that commences upon the date of first commercial delivery
for Train 3 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu,
equating to expected annual contracted cash flow from fixed fees of approximately $548 million. KOGAS is organized
under the laws of the Republic of Korea.
(cid:129) GAIL (India) Limited (“GAIL”) has entered into an SPA that commences upon the date of first commercial delivery for
Train 4 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu,
equating to expected annual contracted cash flow from fixed fees of approximately $548 million. GAIL is organized
under the laws of India.
(cid:129) Total has entered into an SPA that commences upon the date of first commercial delivery for Train 5 and includes an
annual contract quantity of 104,750,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected
annual contracted cash flow from fixed fees of approximately $314 million. The obligations of Total are guaranteed by
Total S.A., a company organized under the laws of France.
(cid:129) Centrica plc (“Centrica”) has entered into an SPA that commences upon the date of first commercial delivery for Train
5 and includes an annual contract quantity of 91,250,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating
to expected annual contracted cash flow from fixed fees of approximately $274 million. Centrica is organized under the
laws of England and Wales.
In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion annually for
Trains 1 through 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable
Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of
Trains 1 through 5, respectively.
In addition, Cheniere Marketing has entered into an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG
produced by SPL in excess of that required for other customers.
Natural Gas Transportation and Supply
To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into
transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies.
SPL has also entered into enabling agreements and natural gas purchase agreements with third parties in order to secure natural
gas feedstock for the Liquefaction Project. As of December 31, 2015, SPL has secured up to approximately 2,154.2 million MMBtu
of natural gas feedstock through natural gas purchase agreements.
Natural Gas Storage Services
For SPL’s natural gas storage requirements, SPL has entered into firm storage services agreements with third parties. The
storage services agreements will assist SPL in managing volatility in natural gas needs for the Liquefaction Project.
4
Construction
SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering,
procurement and construction of Trains 1 through 5, under which Bechtel charges a lump sum for all work performed and generally
bears project cost risk unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or
SPL agrees with Bechtel to a change order.
The total contract prices of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC contract
for Train 5 of the Liquefaction Project are approximately $4.1 billion, $3.8 billion and $3.0 billion, respectively, reflecting amounts
incurred under change orders through December 31, 2015. Total expected capital costs for Trains 1 through 5 are estimated to be
between $12.5 billion and $13.5 billion before financing costs and between $17.0 billion and $18.0 billion after financing costs,
including, in each case, estimated owner’s costs and contingencies.
Pipeline Facilities
During the third quarter of 2015, CTPL completed construction of certain modifications to allow the Creole Trail Pipeline
to be able to transport natural gas to the Sabine Pass LNG terminal.
Final Investment Decision on Train 6
We will contemplate making an FID to commence construction of Train 6 of the Liquefaction Project based upon, among
other things, entering into an EPC contract, entering into acceptable commercial arrangements and obtaining adequate financing
to construct the Train.
Governmental Regulation
The Sabine Pass LNG terminal is subject to extensive regulation under federal, state and local statutes, rules, regulations
and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and
maintain applicable permits and other authorizations. This regulatory requirement increases our cost of operations and construction,
and failure to comply with such laws could result in substantial penalties.
Federal Energy Regulatory Commission
The design, construction and operation of our liquefaction facilities and the export of LNG and the transportation of natural
gas through the Creole Trail Pipeline are highly regulated activities. In order to site and construct the Sabine Pass LNG terminal,
we received and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938 (“NGA”).
The FERC’s approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and
permits, are required in order to site, construct and operate our liquefaction facilities.
The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive
authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except
as specifically provided in the EPAct, nothing in the EPAct is intended to affect otherwise applicable law related to any other
federal agency’s authorities or responsibilities related to LNG terminals. The FERC issued final orders in April and July 2012
approving our application for an order under Section 3 of the NGA authorizing the siting, construction and operation of Trains 1
through 4 of the Liquefaction Project. Subsequently, the FERC issued written approval to commence site preparation work for
Trains 1 through 4. In October 2012, we applied to amend the FERC approval to reflect certain modifications to the Liquefaction
Project, and in August 2013, the FERC issued an order approving the modifications. In October 2013, we applied to further amend
the FERC approval, requesting authorization to increase the total LNG production capacity of Trains 1 through 4 from the currently
authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity. In
February 2014, the FERC issued an order approving the October 2013 application (the “February 2014 Order”). A party to the
proceeding requested a rehearing of the February 2014 Order, and in September 2014, the FERC denied rehearing. The party
petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the February 2014 Order and the FERC Order
Denying Rehearing, and that appeal is still pending. In September 2013, we filed an application with the FERC for authorization
to add Trains 5 and 6 to the Liquefaction Project, which was granted by the FERC in April 2015.
5
In order to construct, own, operate and maintain the Creole Trail Pipeline, CTPL received a certificate of public convenience
and necessity from the FERC under Section 7 of the NGA. The FERC’s approval under Section 7 of the NGA, as well as several
other material governmental and regulatory approvals and permits, may be required prior to making any modifications to the Creole
Trail Pipeline as it is a regulated, interstate natural gas pipeline. The FERC also approved CTPL’s application for authorization
to construct, own, operate and maintain certain new facilities in order to enable bi-directional natural gas flow on the Creole Trail
Pipeline system to allow for the delivery of up to 1,530,000 Dthd of feed gas to the Liquefaction Project. In November 2013,
CTPL received approval from the Louisiana Department of Environmental Quality (“LDEQ”) for the proposed modifications and,
with subsequent final FERC clearance, construction was completed in 2015.
Several other material governmental and regulatory approvals and permits will be required prior to construction and operation
of our liquefaction projects. In addition, the FERC authorization requires us to obtain certain additional FERC approvals as
construction progresses. To date, we have been able to obtain these approvals as needed and the need for these approvals has not
materially affected our construction progress. Throughout the life of our LNG terminals, we will be subject to regular reporting
requirements to the FERC, the U.S. Department of Transportation and applicable state regulatory agencies regarding the operation
and maintenance of our facilities.
In addition to the siting and construction authority with respect to the LNG terminals under the NGA, the FERC has authority
to approve, and if necessary, set “just and reasonable rates” for the transportation or sale of natural gas in interstate commerce. In
addition, under the NGA, our pipelines are not permitted to unduly discriminate or grant undue preference as to rates or the terms
and conditions of service. The FERC has the authority to grant certificates allowing construction and operation of facilities used
in interstate gas transportation and authorizing the provision of services. Under the NGA, the FERC’s jurisdiction generally extends
to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate
consumption for domestic, commercial, industrial or any other use and to natural gas companies engaged in such transportation
or sale. However, the FERC’s jurisdiction does not extend to the production, gathering or local distribution of natural gas.
In general, the FERC’s authority to regulate interstate natural gas pipelines and the services that they provide includes:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
rates and charges for natural gas transportation and related services;
the certification and construction of new facilities;
the extension and abandonment of services and facilities;
the maintenance of accounts and records;
the acquisition and disposition of facilities;
the initiation and discontinuation of services; and
various other matters.
The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that
engages in marketing functions. Interstate pipelines must treat all transmission customers on a not unduly discriminatory basis.
The general principles of the Standards of Conduct are: (1) independent functioning, which requires transmission function
employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission
function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue
preference. CTPL has established the required policies and procedures to comply with the FERC’s Standards of Conduct and is
subject to audit by the FERC to review compliance, policies and its training programs.
In 2002, the FERC concluded that it would apply light-handed regulation over the rates, terms and conditions agreed to by
parties for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at
non-discriminatory rates or maintain a tariff or rate schedule on file with the FERC, as distinguished from the requirements applied
to our FERC-regulated natural gas pipelines. The EPAct codified the FERC’s policy, but those provisions expired on January 1,
2015. Nonetheless, we see no indication that the FERC intends to modify its longstanding policy of light-handed regulation of
LNG terminals.
DOE Export License
The DOE has authorized the export of up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of
domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries for a 30-year term and to non-FTA
6
countries for a 20-year term. The DOE further issued an order authorizing SPL to export up to the equivalent of approximately
203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period. SPL’s
application for authorization to export that same 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal
to non-FTA countries is currently pending at the DOE. Additionally, the DOE issued orders authorizing SPL to export up to a
combined total of 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries and non-FTA
countries for a 20-year term. A party to the proceeding requested a rehearing of the non-FTA order pertaining to the 503.3 Bcf/
yr, and the DOE has not yet issued a final ruling on the rehearing request. In each case, the terms of these authorizations begin
on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 5 to 10 years
from the date the order was issued. Furthermore, the DOE issued an order authorizing SPL to export up to 600 Bcf in total of
domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-
year period commencing on January 15, 2016.
Exports of natural gas to FTA countries are “deemed to be consistent with the public interest” and authorization to export
LNG to FTA countries shall be granted by the DOE without “modification or delay.” FTA countries which import LNG now or
will do so by 2016 include Chile, Mexico, Singapore, South Korea and the Dominican Republic. Exports of natural gas to non-
FTA countries are considered by the DOE in the context of a comment period whereby interveners are provided the opportunity
to assert that such authorization would not be consistent with the public interest.
Pipelines
The Creole Trail Pipeline is also subject to regulation by the U.S. Department of Transportation (“DOT”), under the Pipeline
and Hazardous Material Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating
to the design, installation, testing, construction, operation, replacement and management of pipeline facilities.
The Pipeline Safety Improvement Act of 2002, as amended (“PSIA”), which is administered by the PHMSA Office of
Pipeline Safety, governs the areas of testing, education, training and communication. The PSIA requires pipeline companies to
perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as
“high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings
are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well
as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing,
or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification
program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs
for gas transportation pipelines, which requires pipeline operators to 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 preventive and mitigation actions.
In 2010, the PHMSA issued a final rule (known as “Control Room Management/Human Factors Rule”) requiring pipeline
operators to write and institute certain control room procedures that address human factors and fatigue management. In August
2011, the PHMSA issued an advanced notice of proposed rulemaking addressing whether changes are needed to the regulations
governing the safety of gas transmission pipelines. Specifically, PHMSA is considering whether integrity management requirements
should be changed, including whether the definition of “high consequence area” should be revised and whether additional
restrictions should be placed on the use of specific pipeline assessment methods. The PHMSA is also considering whether to
revise requirements for non-integrity management issues, such as mainline valves, corrosion control issues and the safety of
gathering lines. This advanced notice of proposed rulemaking is still pending at the PHMSA.
In March 2015, the PHMSA issued a final rule amending the pipeline safety regulations to update and clarify certain
regulatory requirements, including who can perform post-construction inspections on transmission pipelines. In May 2015, the
PHMSA issued a notice of proposed rulemaking proposing to amend gas pipeline safety regulations regarding plastic piping
systems used in gas services, including the installation of plastic pipe used for gas transmission lines. In July 2015, the PHMSA
issued a notice of proposed rulemaking proposing to add a specific timeframe for operators’ notification of accidents or incidents,
as well as amending the safety regulations regarding operator qualification requirements by expanding the requirements to include
new construction and certain previously excluded operation and maintenance tasks, requiring a program effectiveness review and
adding new recordkeeping requirements. These notices of proposed rulemaking are still pending at the PHMSA.
7
Natural Gas Pipeline Safety Act of 1968 (“NGPSA”)
Louisiana and Texas administer federal pipeline safety standards under the NGPSA, which requires certain pipelines to
comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure
to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies.
Pipeline Safety, Regulatory Certainty and Jobs Creation Act of 2011
The Creole Trail Pipeline is also subject to the Pipeline Safety, Regulatory Certainty and Jobs Creation Act of 2011, which
regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities.
Under the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, PHMSA has civil penalty authority up to $200,000
per day (increased from the prior $100,000), with a maximum of $2 million for any related series of violations (increased from
the prior $1 million).
Other Governmental Permits, Approvals and Authorizations
The construction and operation of the Sabine Pass LNG terminal are subject to additional federal permits, orders, approvals
and consultations required by other federal agencies, including the DOE, Advisory Council on Historic Preservation, U.S. Army
Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the
Interior, U.S. Fish and Wildlife Service, Environmental Protection Agency (the “EPA”) and U.S. Department of Homeland Security.
Three significant permits are the USACE Section 404 of the Clean Water Act/Section 10 of the Rivers and Harbors Act
Permit (the “Section 10/404 Permit”), the Clean Air Act Title V (“Title V”) Operating Permit and the Prevention of Significant
Deterioration (“PSD”) Permit, the latter two permits being issued by the LDEQ.
The application for revision of the Sabine Pass LNG terminal’s Section 10/404 Permit to authorize construction of Train 1
through Train 4 was submitted in January 2011. The process included a public comment period which commenced in March 2011
and closed in April 2011. The revised Section 10/404 Permit was received from the USACE in March 2012. An application for
a further revision to the Section 10/404 Permit, to address wetlands impacted by the construction of Trains 5 and 6, was received
from the USACE in June 2015. The USACE acted in the capacity as a cooperating agency in the FERC’s NEPA review process.
In addition, a Section 10/404 permit application is pending with respect to the expansion of the Creole Trail Pipeline. These permits
will require us to provide mitigation to compensate for the wetlands impacted by the respective projects. The application to amend
the Sabine Pass LNG terminal’s existing Title V and PSD permits to authorize construction of Train 1 through Train 4 was initially
submitted in December 2010 and revised in March 2011. The process included a public comment period from June 2011 to August
2011 and a public hearing in August 2011. The final revised Title V and PSD permits were issued by the LDEQ in December
2011. Although these permits are final, a petition with the EPA has been filed pursuant to the Clean Air Act requesting that the
EPA object to the Title V permit. The EPA has not ruled on this petition. In June 2012, we applied to the LDEQ for a further
amendment to the Title V and PSD permits to reflect proposed modifications to the Liquefaction Project that were filed with the
FERC in October 2012. The LDEQ issued the amended PSD and Title V permits in March 2013. These permits are final. In
September 2013, Cheniere Partners applied to the LDEQ for another amendment to its PSD and Title V permits seeking approval
to, among other things, construct and operate Trains 5 and 6. The LDEQ issued the amended PSD and Title V permits in June
2015. These permits are final.
CTPL was issued new Title V and PSD permits for the proposed modifications to the Creole Trail Pipeline system by the
LDEQ in November 2013.
In August 2014, the Sabine Pass LNG terminal’s existing wastewater discharge permit was modified by LDEQ to authorize
the discharge of wastewaters from the liquefaction facilities, including wastewaters generated with respect to the anticipated
operations of Trains 5 and 6.
The Sabine Pass LNG terminal is subject to DOT safety regulations and standards for the transportation and storage of LNG
and regulations of the U.S. Coast Guard relating to maritime safety and facility security.
8
Commodity Futures Trading Commission (“CFTC”)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for federal regulation
of the over-the-counter derivatives market and entities, such as us, that participate in that market. The regulatory regime created
by the Dodd-Frank Act is designed primarily to (1) regulate certain participants in the swaps markets, including entities falling
within the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of certain classes
of swaps as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping
requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared
and, in certain cases, uncleared swaps, (5) establish position limits on certain swaps and futures products, and (6) otherwise enhance
the rulemaking and enforcement authority of the CFTC and the SEC regarding the derivatives markets. As required by the Dodd-
Frank Act, the CFTC, the SEC and other regulators have been promulgating rules and regulations implementing the regulatory
provisions of the Dodd-Frank Act, although neither the CFTC nor the SEC has yet adopted or implemented all of the rules required
by the Dodd-Frank Act. In addition, the CFTC and its staff regularly issue rule amendments and guidance, policy statements and
letters interpreting or taking no-action positions, including time-limited no action positions, regarding the derivatives provisions
of the Dodd-Frank Act and the rules of the CFTC under these provisions.
A provision of the Dodd-Frank Act requires the CFTC, in order to diminish or prevent excessive speculation in commodity
markets, to adopt rules imposing new position limits on futures contracts, options contracts and economically equivalent physical
commodity swaps traded on registered swap trading platforms and on over-the-counter swaps that perform a significant price
discovery function with respect to certain markets. In that regard, the CFTC has proposed position limits rules that would modify
and expand the applicability of position limits on the amounts of certain core futures contracts and economically equivalent futures
contracts, options contracts and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market
participants may hold, subject to limited exemptions for certain bona fide hedging and other types of transactions. It is uncertain
at this time when and in what form the CFTC’s proposed new position limits rules may become final and effective.
Pursuant to rules adopted by the CFTC, six classes of over-the-counter (“OTC”) interest rate and credit default swaps must
be cleared through a derivatives clearing organization and executed on an exchange or swap execution facility. The CFTC has
not yet proposed to designate any other classes of swaps, including swaps relating to physical commodities, for mandatory clearing,
but could do so in the future. Although we expect to qualify for the “end-user exception” from the mandatory clearing and exchange-
trading requirements applicable to any swaps that we enter into to hedge our commercial risks, the mandatory clearing and exchange-
trading requirements may apply to other market participants, including our counterparties (who may be registered as Swap Dealers),
with respect to other swaps, and the application of such rules may change the cost and availability of the swaps that we use for
hedging.
As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require
Swap Dealers and Major Swap Participants, including those that are regulated financial institutions, to collect initial and variation
margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major
swap participants. These rules do not require collection of margin from commercial end users who qualify for the end user exception
from the mandatory clearing requirement or certain other counterparties. We expect to qualify as such a commercial end user with
respect to the swaps that we enter into to hedge our commercial risks. The Dodd-Frank Act’s swaps regulatory provisions and the
related rules may also adversely affect our existing derivative contracts and restrict our ability to monetize such contracts, cause
us to restructure certain contracts, reduce the availability of derivatives to protect against risks or to optimize assets, adversely
affect our ability to execute our hedging strategies and impact the liquidity of certain swaps products, all of which could increase
our business costs.
Under the Commodity Exchange Act as amended by the Dodd-Frank Act, the CFTC is directed generally to prevent
manipulation, including by fraudulent or deceptive practices, in two markets: (1) physical commodities traded in interstate
commerce, including physical energy and other commodities, as well as (2) financial instruments, such as futures, options and
swaps. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation and anti-disruptive trading practices
regulations that prohibit, among other things, manipulative or deceptive schemes in the physical commodities, futures, options
and swaps markets. Should we violate these laws and regulations, we could be subject to a CFTC enforcement action and material
penalties, possibly resulting in changes in the rates we can charge.
9
Environmental Regulation
The Sabine Pass LNG terminal is subject to various federal, state and local laws and regulations relating to the protection
of the environment and natural resources. These environmental laws and regulations may impose substantial penalties for
noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities
and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and
penalties for non-compliance.
Clean Air Act (“CAA”)
The Sabine Pass LNG terminal is subject to the federal CAA and comparable state and local laws. We may be required to
incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining
or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the
construction and operation of our liquefaction facilities, will be materially and adversely affected by any such requirements.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule for multiple sections of the
economy. This rule requires mandatory reporting of greenhouse gas (“GHG”) emissions from stationary fuel combustion sources
as well as all fugitive emissions throughout LNG terminals. From time to time, Congress has considered proposed legislation
directed at reducing GHG emissions, and the EPA has defined GHG emissions thresholds for requiring certain permits for new
and existing industrial sources. In addition, many states have already taken regulatory action to monitor and/or reduce emissions
of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not
possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However,
future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material
adverse effect on our business, financial position, operating results and cash flows.
Coastal Zone Management Act (“CZMA”)
The Sabine Pass LNG terminal is subject to the review and possible requirements of the CZMA throughout the construction
of facilities located within the coastal zone. The CZMA is administered by the states (in Louisiana, by the Department of Natural
Resources, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are
consistent with the intent of the CZMA to manage the coastal areas.
Clean Water Act (“CWA”)
The Sabine Pass LNG terminal is subject to the federal CWA and analogous state and local laws. The CWA imposes strict
controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm
water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into
state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ).
Resource Conservation and Recovery Act (“RCRA”)
The federal RCRA and comparable state statutes govern the disposal of solid and hazardous wastes. In the event such
wastes are generated in connection with our facilities, we will be subject to regulatory requirements affecting the handling,
transportation, treatment, storage and disposal of such wastes
Endangered Species Act
The Sabine Pass LNG terminal may be restricted by requirements under the Endangered Species Act, which seeks to protect
endangered or threatened animal, fish and plant species and designated habitats.
Market Factors and Competition
SPLNG currently does not experience competition for its terminal capacity because the entire approximately 4.0 Bcf/d of
regasification capacity that is available at the Sabine Pass LNG terminal has been fully contracted. If and when SPLNG has to
replace any TUAs, it will compete with other then-existing LNG terminals for customers.
10
The Liquefaction Project currently does not experience competition with respect to Trains 1 through 5. SPL has entered
into six fixed price, 20-year SPAs with third parties that will utilize substantially all of the liquefaction capacity available from
these Trains. Each customer will be required to pay an escalating fixed fee for its annual contract quantity even if it elects not to
purchase any LNG from us.
If and when SPL needs to replace any existing SPA or enter into new SPAs, SPL will compete on the basis of price per
contracted volume of LNG with other natural gas liquefaction projects throughout the world. Cheniere is currently developing a
natural gas liquefaction facility near Corpus Christi, Texas and has entered into eight fixed price, 20-year third-party SPAs for the
sale of LNG from this natural gas liquefaction facility, and may continue to enter into commercial agreements with respect to this
natural gas liquefaction facility that might otherwise have been entered into with respect to Train 6. Revenues associated with
any incremental volumes of the Liquefaction Project, including those under the Cheniere Marketing SPA discussed above, will
also be subject to market-based price competition.
Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sell any quantities of
LNG available under the SPAs with Cheniere Marketing, or develop new projects is subject to market factors, including changes
in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and
substitute products in North America and international markets, economic growth in developing countries, investment in energy
infrastructure, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and access to capital markets.
We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable
and environmentally cleaner fuel alternatives to oil and coal. Global demand for natural gas is projected by the International
Energy Agency to grow by approximately 23 Tcf between 2013 and 2025, with LNG increasing its current share of approximately
ten percent of the global market. Wood Mackenzie forecasts that global demand for LNG will increase by 72%, from approximately
245 mtpa, or 11.9 Tcf, in 2015, to 421 mtpa, or 20.5 Tcf, in 2025 and that LNG production from existing facilities and new facilities
already under construction will be able to supply the market with 365 mtpa in 2025, resulting in a market need for construction
of additional facilities capable of producing an incremental 56 mtpa of LNG. We believe our new project that does not already
have capacity sold under long-term contracts is competitive and well-positioned to capture a portion of this incremental market
need.
We have limited exposure, particularly in the LNG terminal business for our five Trains under construction, to the decline
in oil prices, even if it persists for more than 12 months, as we have contracted a significant portion of our LNG production capacity
under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the
customers elect to cancel or suspend delivery of LNG cargoes. To date, we have contracted approximately 19.75 mtpa of aggregate
production capacity for Trains 1 through 5 of the Liquefaction Project with third-party customers. Train 6 has not been contracted
to date. As of January 31, 2016, oil and gas futures prices indicate that LNG exported from the U.S. continues to be competitively
priced, supporting the opportunity for U.S. LNG to fill uncontracted future demand through the execution of long-term, medium-
term and short-term contracting of LNG from our terminal.
Subsidiaries
Our assets are generally held by or under our subsidiaries. We conduct most of our business through these subsidiaries,
including the development, construction and operation of our LNG terminal business.
Employees
We have no employees. We rely on our general partner to manage all aspects of the development, construction, operation
and maintenance of the Sabine Pass LNG terminal and the Liquefaction Project and to conduct our business. Because our general
partner has no employees, it relies on subsidiaries of Cheniere to provide the personnel necessary to allow it to meet its management
obligations to us, SPLNG, SPL and CTPL. As of January 31, 2016, Cheniere and its subsidiaries had 888 full-time employees,
including 488 employees who directly supported the Sabine Pass LNG terminal operations. See Note 11—Related Party
Transactions of our Notes to Consolidated Financial Statements for a discussion of the services agreements pursuant to which
general and administrative services are provided to Cheniere Partners, SPLNG, SPL and CTPL.
11
Available Information
Our common units have been publicly traded since March 21, 2007 and are traded on the NYSE MKT under the symbol
“CQP.” Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone
number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form
10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably
practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act of 1934,
as amended (the “Exchange Act”). These reports may be accessed free of charge through our internet website. We make our
website content available for informational purposes only. The website should not be relied upon for investment purposes and is
not incorporated by reference into this Form 10-K.
We will also make available to any unitholder, without charge, copies of our annual report on Form 10-K as filed with the
SEC. For copies of this, or any other filing, please contact: Cheniere Energy Partners, L.P, Investor Relations Department, 700
Milam Street, Suite 1900, Houston, Texas 77002 or call (713) 375-5000. In addition, the public may read and copy any materials
we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The public
may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains
an internet site (www.sec.gov) that contains reports and other information regarding issuers, like us, that file electronically with
the SEC.
ITEM 1A.
RISK FACTORS
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks
to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The following
are some of the important factors that could affect our financial performance or could cause actual results to differ materially from
estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described
below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair
or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
(cid:129) Risks Relating to Our Financial Matters;
(cid:129) Risks Relating to Our Business;
(cid:129) Risks Relating to Our Cash Distributions;
(cid:129) Risks Relating to an Investment in Us and Our Common Units; and
(cid:129) Risks Relating to Tax Matters.
Risks Relating to Our Financial Matters
Our significant debt could materially and adversely affect our business, financial condition and prospects.
As of December 31, 2015, we had $11.8 billion of total debt outstanding on a consolidated basis (before debt discounts and
debt premiums), excluding $135.2 million of outstanding letters of credit. We incur, and will incur, significant interest expense
relating to the assets at the Sabine Pass LNG terminal and we anticipate needing to incur substantial additional debt and issue
equity to finance the construction of Train 6 of the Liquefaction Project. Our ability to fund our capital expenditures and refinance
our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets.
A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic
conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital
market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets. Our financing costs could
increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to
pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to
fund our capital expenditures. If any of the lenders in the syndicates backing these facilities were unable to perform on its
commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more
limited amounts or on more expensive or otherwise unfavorable terms.
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We have not been profitable historically. We may not achieve profitability or generate positive operating cash flow in the future.
We had net losses of $318.9 million, $410.0 million and $258.1 million for the years ended December 31, 2015, 2014 and
2013, respectively. We will continue to incur significant capital and operating expenditures while we develop and construct the
Liquefaction Project. We currently expect that we will not begin to receive cash flows from operations under any SPA until early
2016, at the earliest. Any delays beyond the expected development period for Train 1 would prolong, and could increase the level
of, operating losses and negative cash flows. Our future liquidity may also be affected by the timing of construction financing
availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under
SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our
control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and
breaches of agreements. Our ability to generate any significant positive operating cash flow and achieve profitability in the future
is dependent on our ability to successfully and timely complete the applicable Train.
We may sell equity or equity-related securities, including additional common units. Such sales could dilute our unitholders’
proportionate indirect interests in our assets, business operations, Liquefaction Project and other projects, and could adversely
affect the market price of our common units.
We have pursued and are pursuing a number of alternatives in order to finance the construction of Train 6, including potential
issuances and sales of additional equity or equity-related securities. Such sales, in one or more transactions, could dilute our
unitholders’ proportionate indirect interests in our assets, business operations and proposed projects, including the Liquefaction
Project. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common units.
Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we
have entered into, and we could be materially and adversely affected if any customer fails to perform its contractual obligations
for any reason.
Our future results and liquidity are substantially dependent upon performance by Chevron and Total, each of which has
entered into a TUA with SPLNG and agreed to pay SPLNG approximately $125 million annually, and upon satisfaction of the
conditions precedent to payment thereunder, by six third-party customers that have entered into SPAs with SPL and agreed to pay
SPL an aggregate of $2.9 billion annually in fixed fees. We are dependent on each customer’s continued willingness and ability
to perform its obligations under its SPA. We are also exposed to the credit risk of any guarantor of these customers’ obligations
under their respective TUA or SPA in the event that we must seek recourse under a guaranty. If any customer fails to perform its
obligations under its TUA or SPA, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects
could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its
guarantor for a breach of the TUA or SPA.
Each of our customer contracts is subject to termination under certain circumstances.
Each of SPLNG’s long-term TUAs contains various termination rights. For example, each customer may terminate its TUA
if the Sabine Pass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount
of natural gas in accordance with the customer’s redelivery nominations or fails to accept and unload a specified number of the
customer’s proposed LNG cargoes. SPLNG may not be able to replace these TUAs on desirable terms, or at all, if they are
terminated.
Each of SPL’s SPAs contains various termination rights allowing our customers to terminate their SPAs, including, without
limitation: (1) upon the occurrence of certain events of force majeure; (2) if we fail to make available specified scheduled cargo
quantities; and (3) delays in the commencement of commercial operations. We may not be able to replace these SPAs on desirable
terms, or at all, if they are terminated.
Our use of hedging arrangements may adversely affect our future operating results or liquidity.
To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we
use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange,
or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would
expose us to risk of financial loss in some circumstances, including when:
(cid:129)
expected supply is less than the amount hedged;
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(cid:129)
(cid:129)
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 use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital
when commodity prices change.
The swaps regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations
could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal
regulation of the over-the-counter (“OTC”) derivatives market and made other amendments to the Commodity Exchange Act that
are relevant to our business. The provisions of Title VII of the Dodd-Frank Act and the rules adopted thereunder by the Commodity
Futures Trading Commission (“CFTC”), the SEC and other federal regulators may adversely affect our ability to manage certain
of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies
with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory
and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminals and to secure
natural gas feedstock for our Liquefaction Project.
The CFTC has proposed new rules setting limits on the positions in certain core futures contracts, economically equivalent
futures contracts, options contracts and swaps for or linked to certain physical commodities, including Henry Hub natural gas,
held by market participants, with limited exemptions for certain bona fide hedging and other types of transactions. Under the
CFTC’s proposed rules regarding aggregation of positions, a party that controls the trading of, or owns 10% or more of the equity
interests in, another party will have to aggregate the positions of the controlled party with its own positions for purposes of
determining compliance with position limits unless an exemption applies. Upon the adoption and effectiveness of final CFTC
position limits and aggregation rules, our ability to execute our hedging strategies described above could be limited. It is uncertain
at this time whether, when and in what form the CFTC’s proposed new position limits and aggregation rules may become final
and effective.
Under the Dodd-Frank Act and the rules adopted thereunder, we may be required to clear through a derivatives clearing
organization any swaps into which we enter that fall within a class of swaps designated by the CFTC for mandatory clearing and
we could have to execute trades in such swaps on certain trading platforms. The CFTC has designated six classes of interest rate
swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any other classes of swaps,
including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the
mandatory clearing and trade execution requirements for our swaps entered into to hedge our commercial risks, if we fail to qualify
for that exception as to any swap we enter into and have to clear that swap through a derivatives clearing organization, we could
be required to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and we
would not enjoy the same flexibility with the cleared swaps that we enjoy with the uncleared OTC swaps we enter. Moreover, the
application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may
change the cost and availability of the swaps that we use for hedging.
As required by the Dodd-Frank Act, the CFTC and the federal banking regulators have adopted rules requiring certain
market participants to collect margin with respect to uncleared swaps from their counterparties that are financial end users and
certain registered swap dealers and major swap participants. The requirements of those rules are to be phased in commencing on
September 1, 2016. Although we believe we will qualify as a non-financial end user for purposes of these rules, were we not to
do so and have to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be
increased. Our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase
the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, require
us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital
costs to maintain those swaps on their balance sheets.
The Dodd-Frank Act also imposes regulatory requirements on swaps market participants, including swap dealers and other
swaps entities as well as certain regulations on end users of swaps, including regulations relating to swap documentation, reporting
and recordkeeping, and certain business conduct rules applicable to swap dealers and other swaps entities. Together with the Basel
III capital requirements on certain swaps market participants, these regulations could significantly increase the cost of derivative
contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce
14
the availability of derivatives to protect against certain risks that we encounter, reduce our ability to monetize or restructure our
existing derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above,
we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our
operating results and cash flows may become more volatile and could be otherwise adversely affected.
Risks Relating to Our Business
Operation of the Sabine Pass LNG terminal, the Liquefaction Project and other facilities that we may construct involves
significant risks.
As more fully discussed in these Risk Factors, the Sabine Pass LNG terminal, the Liquefaction Project and our other existing
and proposed LNG facilities face operational risks, including the following:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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
(cid:129) weather-related interruptions of operations.
We may not be successful in implementing our proposed business strategy to provide liquefaction capabilities at the Sabine
Pass LNG terminal adjacent to the existing regasification facilities.
It will take several years to construct the Liquefaction Project, and even if successfully constructed, the Liquefaction Project
would be subject to the operating risks described herein. Accordingly, there are many risks associated with the Liquefaction
Project, and if we are not successful in implementing our business strategy, we may not be able to generate cash flows, which
could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and
prospects.
Cost overruns and delays in the completion of one or more Trains, as well as difficulties in obtaining sufficient financing to
pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating
results, cash flow, liquidity and prospects.
The actual construction costs of the Trains may be significantly higher than our current estimates as a result of many factors,
including change orders under existing or future EPC contracts resulting from the occurrence of certain specified events that may
give Bechtel the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We do
not have any prior experience in constructing liquefaction facilities, and no liquefaction facilities have been constructed and placed
in service in the United States in over 40 years. As construction progresses, we may decide or be forced to submit change orders
to our contractor that could result in longer construction periods, higher construction costs or both.
Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to
the EPC contracts with Bechtel or any future EPC contract related to additional Trains, could increase the cost of completion
beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until
the Liquefaction Project is constructed (which could cause further delays). Our ability to obtain financing that may be needed to
provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not
be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to
accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
Delays in the completion of one or more Trains could lead to reduced revenues or termination of one or more of the SPAs by
our counterparties.
Any delay in completion of a Train could cause a delay in the receipt of revenues projected therefrom or cause a loss of one
or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could
have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
15
Our ability to complete development of Train 6 will be contingent on our ability to obtain additional funding. If we are unable
to obtain sufficient funding, we may be unable to complete our business plan and our business may ultimately be unsuccessful.
We will require significant additional funding to be able to commence construction of Train 6, which we may not be able
to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in
the development of Train 6, and we may not be able to complete our business plan. Even if we are able to obtain funding, the
funding may be inadequate to cover any increases in costs or delays in completion of Train 6, which may cause a delay in the
receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. As a result,
any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial
condition, operating results, cash flow, liquidity and prospects.
To maintain the cryogenic readiness of the Sabine Pass LNG terminal, SPLNG may need to purchase and process LNG.
SPLNG’s TUA customers, including SPL, have the obligation to procure LNG if necessary for the Sabine Pass LNG terminal
to maintain its cryogenic state. If they fail to do so, SPLNG may need to procure such LNG.
SPLNG needs to maintain the cryogenic readiness of the Sabine Pass LNG terminal. Together with SPL, the two third-
party TUA customers have the obligation to maintain minimum inventory levels, and, under certain circumstances, to procure
LNG to maintain the cryogenic readiness of the terminal. In the event that aggregate minimum inventory levels are not maintained,
SPLNG has the right to procure a cryogenic readiness cargo to cure a minimum inventory condition, and to be reimbursed by each
TUA customer for their allocable share of the LNG acquisition costs. If SPLNG is not able to obtain financing on acceptable
terms, it will need to maintain sufficient working capital for such a purchase until it receives reimbursement for the allocable costs
of the LNG from its TUA customers or sells the regasified LNG.
SPLNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG terminal, which would increase
operating costs and could have a material adverse effect on our operating results.
SPLNG’s TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG terminal, which it
uses primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. There
is a risk that this 2% in-kind deduction will be insufficient for these needs and that SPLNG will have to purchase additional natural
gas from third parties. SPLNG will bear the cost and risk of changing prices for any such fuel.
Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of the Liquefaction
Project, higher construction costs and the deferral of the dates on which payments are due to SPL under the SPAs, all of which
could adversely affect us.
In August and September of 2005, Hurricanes Katrina and Rita, respectively, damaged coastal and inland areas located in
Texas, Louisiana, Mississippi and Alabama, resulting in the temporary suspension of construction of the Sabine Pass LNG terminal.
In September 2008, Hurricane Ike struck the Texas and Louisiana coast, and the Sabine Pass LNG terminal experienced minor
damage.
Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents,
could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays
or cost increases in the construction and the development of the Liquefaction Project and related infrastructure. Changes in the
global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea
levels; if any such effects were to occur, they could have an adverse effect on our coastal operations.
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Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design,
construction and operation of our facilities could impede operations and construction and could have a material adverse effect
on us.
The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Project,
and other facilities, and the import and export of LNG and the transportation of natural gas, are highly regulated activities. Approvals
of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory
approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG
facility and an interstate natural gas pipeline and export LNG. Although the FERC has issued an order under Section 3 of the
NGA authorizing the siting, construction and operation of six Trains, the FERC order requires us to obtain certain additional
approvals in conjunction with ongoing construction and operations of the Liquefaction Project. We also have a pending application
with the DOE for authorization to export LNG to non-FTA countries in addition to the orders previously granted to us by the DOE.
Authorizations obtained from other federal and state regulatory agencies also contain ongoing conditions, and additional approval
and permit requirements may be imposed. We cannot control the outcome of the review and approval process. We do not know
whether or when any such approvals or permits can be obtained, or whether or not any existing or potential interventions or other
actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain
and maintain the necessary approvals and permits, we may not be able to recover our investment in our projects. There is no
assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to
obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a
material adverse effect on our business, financial condition, operating results, liquidity and prospects.
We are entirely dependent on Cheniere, including employees of Cheniere and its subsidiaries, for key personnel, and the
unavailability of skilled workers or failure to attract and retain qualified personnel could adversely affect us. In addition,
changes in our general partner’s senior management or other key personnel could affect our business results.
As of January 31, 2016, Cheniere and its subsidiaries had 888 full-time employees, including 488 employees who directly
supported the Sabine Pass LNG terminal operations. We have contracted with subsidiaries of Cheniere to provide the personnel
necessary for the operation, maintenance and management of the Sabine Pass LNG terminal, the Creole Trail Pipeline and
construction of the Liquefaction Project. We face competition for these highly skilled employees in the immediate vicinity of the
Sabine Pass LNG terminal and more generally from the Gulf Coast hydrocarbon processing and construction industries. A shortage
in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could
make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages
that are offered, thereby increasing our operating costs.
The executive officers of our general partner are officers and employees of Cheniere and its affiliates. Our general partner
is currently in a transition process with respect to its Chief Executive Officer, which could affect our strategic direction or our
business results. Further, we do not maintain key person life insurance policies on any personnel, and our general partner does
not have any employment contracts or other agreements with key personnel binding them to provide services for any particular
term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our
future success will depend in part on our general partner’s ability to engage, and Cheniere’s ability to attract and retain additional
qualified personnel.
We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including
Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, Cheniere Investments
has entered into an amended and restated variable capacity rights agreement (the “VCRA”) with Cheniere Marketing, under which
Cheniere Marketing will be able to derive economic benefits to the extent it assists Cheniere Investments in commercializing
Cheniere Investments’ access to capacity at the Sabine Pass LNG terminal through its agreement with SPL, which has a TUA with
SPLNG. In addition, Cheniere Marketing has entered into an SPA to purchase, at Cheniere Marketing’s option, any LNG produced
by SPL in excess of that required for other customers. All of these agreements involve conflicts of interest between us, on the one
hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently developing and constructing a
natural gas liquefaction facility near Corpus Christi, Texas and has entered into eight third-party SPAs for the sale of LNG from
this natural gas liquefaction facility, and may continue to enter into commercial arrangements with respect to this liquefaction
facility that might otherwise have been entered into with respect to Train 6.
17
We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future
transportation, interconnection and gas balancing agreements with one or more Cheniere-affiliated natural gas pipelines as well
as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with
Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.
We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling
to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminates their agreement,
we would be required to engage a substitute service provider. This could result in a significant interference with operations and
increased costs.
We are dependent on Bechtel and other contractors for the successful completion of the Liquefaction Project.
Timely and cost-effective completion of the Liquefaction Project in compliance with agreed specifications is central to our
business strategy and is highly dependent on the performance of Bechtel and our other contractors under their agreements. The
ability of Bechtel and our other contractors to perform successfully under their agreements is dependent on a number of factors,
including their ability to:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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;
(cid:129) manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
(cid:129) maintain their own financial condition, including adequate working capital.
Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required
with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the
operation of the applicable liquefaction facility, and any liquidated damages that we receive may not be sufficient to cover the
damages that we suffer as a result of any such delay or impairment. The obligations of Bechtel and our other contractors to pay
liquidated damages under their agreements are subject to caps on liability, as set forth therein. Furthermore, we may have
disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights
and remedies under their contracts and increase the cost of the applicable liquefaction facility or result in a contractor’s unwillingness
to perform further work on the Liquefaction Project. If any contractor is unable or unwilling to perform according to the negotiated
terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a
substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse
effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are relying on third-party engineers to estimate the future capacity ratings and performance capabilities of the Liquefaction
Project, and these estimates may prove to be inaccurate.
We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the
future capacity ratings and performance capabilities of the Liquefaction Project. If any Train, when actually constructed, fails to
have the capacity ratings and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our
Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start
dates under our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results,
cash flow, liquidity and prospects.
If third-party pipelines and other facilities interconnected to our pipelines and facilities are or become unavailable to transport
natural gas, this could have a material adverse effect on our business, financial condition, operating results, liquidity and
prospects.
We will depend upon third-party pipelines and other facilities that will provide gas delivery options to the Liquefaction
Project and to and from the Creole Trail Pipeline. If the construction of new or modified pipeline connections is not completed
18
on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs,
damage to the facility, lack of capacity or any other reason, our ability to meet our SPA obligations and continue shipping natural
gas from producing regions or to end markets could be restricted, thereby reducing our revenues, which could have a material
adverse effect on our business, financial condition, operating results, liquidity and prospects.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under
the SPAs, which could have a material adverse effect on us.
Under the SPAs with our liquefaction customers, we are required to deliver to them a specified amount of LNG at specified
times. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those
delivery obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase
or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities
and losses for us.
The operation of the Sabine Pass LNG terminal and construction of the Liquefaction Project is and will be subject to the
inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes
and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or
interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition,
our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated
with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain
desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully
insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating
results, cash flow, liquidity and prospects.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and
the performance of our customers and could have a material adverse effect on our business, contracts, financial condition,
operating results, cash flows, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about
the future availability and price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural
gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or
more of the following factors:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert
LNG from the Sabine Pass LNG terminal;
competitive liquefaction capacity in North America;
insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
insufficient LNG tanker capacity;
(cid:129) weather conditions;
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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 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;
19
(cid:129)
(cid:129)
(cid:129)
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
(cid:129)
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the prices of LNG and natural
gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on
our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Failure of imported or exported LNG to be a competitive source of energy could adversely affect our customers and could
materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Current operations at the Sabine Pass LNG terminal are dependent upon the ability of our TUA customers to import LNG
supplies into the United States, which is primarily dependent upon LNG being a competitive source of energy in North America.
In North America, due mainly to a historically abundant supply of natural gas and discoveries of substantial quantities of
unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the
regasification services component of our business plan is dependent, in part, on the extent to which LNG can, for significant periods
and in significant volumes, be produced internationally and delivered to North America at a lower cost than the cost to produce
some domestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies,
additional sources of natural gas have recently been and may continue to be discovered in North America, which could further
increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG.
Operations at the Liquefaction Project will be dependent upon the ability of our SPA customers to deliver LNG supplies
from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success
of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be
supplied from North America and delivered to international markets at a lower cost than the cost of other alternative energy sources.
Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside North America,
which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than
LNG exported to these markets.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and
the United States, may also impede the willingness or ability of LNG suppliers and merchants in such countries to import or export
LNG from or to the United States. Furthermore, some foreign suppliers of LNG may have economic or other reasons to obtain
their LNG from, or direct their LNG to, non-United States markets or from or to our competitors’ LNG facilities in the United
States. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric,
wind and solar energy, which may become available at a lower cost in certain markets.
As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally.
The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources could
adversely affect the ability of our customers to deliver LNG from the United States or to the United States on a commercial basis.
Any significant impediment to the ability to deliver LNG to or from the United States generally, or to the Sabine Pass LNG terminal
or from the Liquefaction Project specifically, could have a material adverse effect on our customers and on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
Various economic and political factors could negatively affect the development of LNG facilities, including the Liquefaction
Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash
flow, liquidity and prospects.
Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be
delayed by factors such as:
(cid:129)
increased construction costs;
20
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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
(cid:129)
any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
There may be shortages of LNG vessels worldwide, which could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability
of the vessels could be delayed to the detriment of our LNG business and our customers because of:
(cid:129)
(cid:129)
(cid:129)
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;
(cid:129) work stoppages or other labor disturbances at the shipyards;
(cid:129)
(cid:129)
bankruptcy or other financial crisis of shipbuilders;
quality or engineering problems;
(cid:129) weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
(cid:129)
shortages of or delays in the receipt of necessary construction materials.
We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas
transportation requirements, which could have a material adverse effect on us.
We have contracted for firm capacity for our natural gas feedstock transportation requirements for Trains 1 through 5 of
the Liquefaction Project and have an option for firm capacity for Train 6. We cannot control the regulatory and permitting
approvals or third parties’ construction times. If and when we need to replace one or more of our agreements with these
interconnecting pipelines, we may not be able to do so on commercially reasonable terms or at all, which could impair our
ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
We face competition based upon the international market price for LNG.
The Liquefaction Project is subject to the risk of LNG price competition at times when we need to replace any existing
SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs with respect to Train 6. Factors relating to
competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs,
or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash
flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from the Liquefaction Project are
diverse and include, among others:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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 the Liquefaction Project;
decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
increases in capacity and utilization of nuclear power and related facilities; and
21
(cid:129)
displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not
currently available.
Terrorist attacks, including cyberterrorism, or military campaigns may adversely impact our business.
A terrorist, including cyberterrorist, or military incident involving an LNG facility, our infrastructure or an LNG vessel may
result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, which would increase
our costs and decrease our cash flows. A terrorist incident may also result in temporary or permanent closure of existing LNG
facilities, including the Sabine Pass LNG terminal or the Creole Trail Pipeline, which could increase our costs and decrease our
cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental
scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism
and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our
business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability
in the financial markets as a result of terrorism, including cyberterrorism, or war could also materially adversely affect our ability
to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as
well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs
or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws and regulations that regulate and restrict, among
other things, discharges to air, land and water, with particular respect to the protection of the environment and natural resources;
the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated
with the release of hazardous substances. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA
and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances
that can be released into the environment in connection with the construction and operation of our facilities, and require us to
maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our
compliance. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties or to capital expenditures
related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition,
operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness
of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner
and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment
at or from our facilities and for resulting damage to natural resources.
The Obama Administration is pursuing a number of regulatory and policy initiatives to reduce GHG emissions in the United
States from a variety of sources. For example, in October 2015, the EPA promulgated a final rule to implement the Obama
Administration’s Clean Power Plan, which is designed to reduce GHG emissions from power plants in the United States. Other
federal and state initiatives are being considered or may be considered in the future to address GHG emissions through, for example,
United States treaty commitments, direct regulation, a carbon emissions tax, or cap-and-trade programs. Such initiatives could
affect the demand for or cost of natural gas, which we consume at the Sabine Pass LNG terminal, or could increase compliance
costs for our operations.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or
exported from the Sabine Pass LNG terminal through the Sabine-Neches Waterway less than four miles from the Gulf Coast, could
cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot
be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted
or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and
restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity
and prospects.
The Creole Trail Pipeline and its FERC gas tariffs are subject to FERC regulation.
The Creole Trail Pipeline is subject to regulation by the FERC under the NGA and under the Natural Gas Policy Act of
1978. The FERC regulates the transportation of natural gas in interstate commerce, including the construction and operation of
the Creole Trail Pipeline, the rates and terms of conditions of service and abandonment of facilities. Under the NGA, the rates
22
charged by the Creole Trail Pipeline must be just and reasonable, and CTPL is prohibited from unduly preferring or unreasonably
discriminating against any person with respect to pipeline rates or terms and conditions of service. If CTPL fails to comply with
all applicable statutes, rules, regulations and orders, the Creole Trail Pipeline could be subject to substantial penalties and fines.
Our FERC gas tariffs, including our pro forma transportation agreements, must be filed and approved by the FERC. Before
we enter into a transportation agreement with a shipper that contains a term that materially deviates from our tariff, we must seek
the FERC’s approval. The FERC may approve the material deviation in the transportation agreement; however, in that case, the
materially deviating terms must be made available to our other similarly-situated customers. If CTPL fails to seek the FERC’s
approval of a transportation agreement that materially deviates from our tariff, or if the FERC audits our contracts and finds
deviations that appear to be unduly discriminatory, the FERC could conduct a formal enforcement investigation, resulting in serious
penalties and/or onerous ongoing compliance obligations.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject
to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA to impose penalties for
current violations of up to $1.0 million per day for each violation.
A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational
damage.
Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance
may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or litigation, and a failure
that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could
generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies
and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating
results, cash flow, liquidity and prospects.
Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.
The federal Office of Pipeline Safety requires pipeline operators to develop integrity management programs to
comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located
in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair,
remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to
comply with the Federal Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant
penalties and fines.
Our business could be materially and adversely affected if we lose the right to situate the Creole Trail Pipeline on property
owned by third parties.
We do not own the land on which the Creole Trail Pipeline is situated, and we are subject to the possibility of increased
costs to retain necessary land use rights. If we were to lose these rights or be required to relocate the Creole Trail Pipeline, our
business could be materially and adversely affected.
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Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash
flow, liquidity and prospects.
Substantially all of our anticipated revenue in 2016 will be dependent upon one facility, the Sabine Pass LNG terminal
located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass
LNG terminal, including the related pipeline, or in the LNG industry, would have a significantly greater impact on our financial
condition and operating results than if we maintained more diverse assets and operating areas.
If we do not make acquisitions or implement capital expansion projects on economically acceptable terms, our future growth
and our ability to increase distributions to our unitholders will be limited.
Our ability to grow depends on our ability to make accretive acquisitions or implement accretive capital expansion projects,
such as the Liquefaction Project. We may be unable to make accretive acquisitions or implement accretive capital expansion
projects for any of the following reasons:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
if we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
if we are unable to identify attractive capital expansion projects or negotiate acceptable engineering procurement and
construction arrangements for them;
if we are unable to obtain necessary governmental approvals;
if we are unable to obtain financing for the acquisitions or capital expansion projects on economically acceptable terms,
or at all;
if we are unable to secure adequate customer commitments to use the acquired or expansion facilities; or
if we are outbid by competitors.
If we are unable to make accretive acquisitions or implement accretive capital expansion projects, then our future growth
and ability to increase distributions to our unitholders will be limited.
We intend to pursue acquisitions of additional LNG terminals, natural gas pipelines and related assets in the future, either
directly from Cheniere or from third parties. However, Cheniere is not obligated to offer us any of these assets other than, in
certain circumstances under an investors rights agreement with Blackstone CQP Holdco, its Corpus Christi liquefaction project.
If Cheniere does offer us the opportunity to purchase assets, we may not be able to successfully negotiate a purchase and sale
agreement and related agreements, we may not be able to obtain any required financing for such purchase and we may not be able
to obtain any required governmental and third-party consents. The decision whether or not to accept such offer, and to negotiate
the terms of such offer, will be made by the conflicts committee of our general partner, which may decline the opportunity to accept
such offer for a variety of reasons, including a determination that the acquisition of the assets at the proposed purchase price would
not result in an increase, or a sufficient increase, in our adjusted operating surplus per unit within an appropriate timeframe.
If we make acquisitions, such acquisitions could adversely affect our business and ability to make distributions to our unitholders.
If we make any acquisitions, they will involve potential risks, including:
an inability to integrate successfully the businesses that we acquire with our existing business;
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the
acquisition;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129) mistaken assumptions about the cash generated, or to be generated, by the business acquired or the overall costs of equity
or debt;
(cid:129)
(cid:129)
the diversion of management’s and employees’ attention from other business concerns; and
unforeseen difficulties encountered in operating new business segments or in new geographic areas.
24
If we consummate any future acquisitions, our capitalization and operating results may change significantly, and our
unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider
in determining the application of our future funds and other resources. In addition, if we issue additional units in connection with
future growth, our existing unitholders’ interest in us will be diluted, and distributions to our unitholders may be reduced.
We may incur impairments to long-lived assets.
We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount
of these assets may not be recoverable. Significant negative industry or economic trends, reduced estimates of future cash flows
for our business or disruptions to our business could lead to an impairment charge of our long-lived assets. Our valuation
methodology for assessing impairment requires management to make judgments and assumptions based on historical experience
and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may
vary significantly from results. In addition, if our analysis results in an impairment to our long-lived assets, we may be required
to record a charge to earnings in our Consolidated Financial Statements during a period in which such impairment is determined
to exist, which may negatively impact our operating results.
Risks Relating to Our Cash Distributions
We may not be successful in our efforts to maintain or increase our cash available for distribution to cover the distributions
on our common units.
We are currently paying the initial quarterly distribution of $0.425 on each of our common units and the related distribution
on the general partner units. We are currently not paying any distributions on the subordinated units. The Class B units are not
entitled to receive distributions until they convert into common units. As of December 31, 2015, we had 57,083,723 common
units outstanding. The aggregate initial quarterly distribution on these common units and the related general partner units is
approximately $99 million per year. We are not currently generating sufficient operating surplus each quarter to pay the initial
quarterly distribution on all of these units and therefore intend to use a portion of our accumulated operating surplus each quarter
to enable us to make this distribution. We may not have sufficient operating surplus to continue paying the initial quarterly
distribution on all of our common units before Trains 1 and 2 commence commercial operations, which is not expected to occur
until at least 2016 or thereafter. Furthermore, if Trains 1 and 2 do not commence commercial operations as expected and the
outstanding Class B units convert into common units, we may not have sufficient operating surplus to be able to pay the initial
quarterly distribution on all common units then outstanding.
Accordingly, at least until Trains 1 and 2 commence commercial operations, the amount of cash that we can distribute on
our common units principally will depend upon the amount of cash that we generate from our existing operations, which will be
based on, among other things:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
performance by counterparties of their obligations under the TUAs;
performance by SPLNG of its obligations under the TUAs;
performance by, and the level of cash receipts received from, Cheniere Marketing under the VCRA; and
the level of our operating costs, including payments to our general partner and its affiliates.
In addition, the actual amount of cash that we will have available for distribution will depend on other factors such as:
the restrictions contained in our debt agreements and our debt service requirements, including the ability of SPLNG to
pay distributions to us under the indentures governing the $1.7 billion of 7.50% Senior Secured Notes due 2016 and $0.4
billion of 6.50% Senior Secured Notes due 2020, both issued by SPLNG (the “SPLNG Indentures”) as a result of
requirements for a debt service reserve account, a debt payment account and satisfaction of a fixed charge coverage ratio
and the ability of SPL to pay distributions to us under its credit facilities and its senior notes;
the costs and capital requirements of acquisitions, if any;
fluctuations in our working capital needs;
our ability to borrow for working capital or other purposes; and
the amount, if any, of cash reserves established by our general partner.
25
We may not be successful in our efforts to maintain or increase our cash available for distribution to cover the distributions
on our units. Any reductions in distributions to our unitholders because of a shortfall in cash flow or other events will result in a
decrease of the quarterly distribution on our common units below the initial quarterly distribution. Any portion of the initial
quarterly distribution that is not distributed on our common units will accrue and be paid to the common unitholders in accordance
with our partnership agreement, if at all.
We will need to refinance, extend or otherwise satisfy our substantial indebtedness, and principal amortization or other terms
of our future indebtedness could limit our ability to pay or increase distributions to our unitholders.
As of December 31, 2015, we had $11.8 billion of total consolidated indebtedness (before debt discounts and debt premiums).
We anticipate incurring additional consolidated indebtedness in the future, including by issuing additional notes of our subsidiaries,
including SPL. Any additional indebtedness incurred could be at higher interest rates and have different maturity dates and more
restrictive covenants than our current outstanding indebtedness. Approximately $1.7 billion of our indebtedness will mature in
2016, $400.0 million will mature in 2017, $420.0 million will mature in 2020, $2.0 billion will mature in 2021, $1.0 billion will
mature in 2022, $1.5 billion will mature in 2023, $2.0 billion will mature in 2024 and $2.0 billion will mature in 2025. In addition,
SPL’s $4.6 billion credit facilities will mature on the earlier of December 31, 2020 or the second anniversary of the Train 5
completion date, as defined in SPL’s credit facilities. We are not generally required to make principal payments on any of our
long-term indebtedness prior to maturity other than SPL’s credit facilities. Our ability to refinance, extend or otherwise satisfy
our indebtedness, and the principal amortization, interest rate and other terms on which we may be able to do so, will depend
among other things on our then contracted or otherwise anticipated future cash flows available for debt service. Our TUAs with
Total and Chevron, which provide substantially all of our current operating cash flows, will expire in 2029 unless extended. Our
ability to pay or increase distributions to our unitholders in future years could be limited by principal amortization, interest rate
or other terms of our future indebtedness. If we are unable to refinance, extend or otherwise satisfy our debt as it matures, that
would have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.
Our subsidiaries may be restricted under the terms of their indebtedness from making distributions to us under certain
circumstances, which may limit our ability to pay or increase distributions to our unitholders and could materially and adversely
affect the market price of our common units.
The agreements governing our indebtedness restrict payments that our subsidiaries can make to us in certain events and
limit the indebtedness that our subsidiaries can incur. For example, SPLNG may not make distributions under the SPLNG Indentures
until, among other requirements, a deposit has been made in an interest payment account for one-sixth of the semi-annual interest
payment multiplied by the number of elapsed months since the last semi-annual interest payment, a deposit has been made to a
permanent debt service reserve fund for one semi-annual interest payment and a fixed charge coverage ratio test of 2:1 is satisfied.
SPLNG also is not permitted to make cash distributions if its consolidated cash flow is not at least twice its fixed charges, calculated
as required in the SPLNG Indentures. In order to satisfy this fixed charge coverage ratio test, we estimate that SPLNG’s consolidated
cash flow, as defined in such indentures, must be greater than approximately $340 million. Thus, TUA payments from SPL and
either Chevron or Total are needed to satisfy the test. If the fixed charge coverage ratio test is not satisfied, SPLNG will not be
permitted by the SPLNG Indentures to make distributions to us, which may prevent us from making distributions to our unitholders.
SPL is likewise restricted from making distributions under the agreements governing its indebtedness generally until, among
other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts
and a debt service coverage ratio of 1.25:1.00 is satisfied.
If our subsidiaries are unable to pay distributions to us or incur indebtedness as a result of the foregoing restrictions in
agreements governing their indebtedness, we may be inhibited in our ability to pay or increase distributions to our unitholders.
Restrictions in agreements governing our subsidiaries’ indebtedness may prevent our subsidiaries from engaging in certain
beneficial transactions.
In addition to restrictions on the ability of SPLNG and SPL to make distributions or incur additional indebtedness, the
agreements governing their indebtedness also contain various other covenants that may prevent them from engaging in beneficial
transactions, including limitations on their ability to:
(cid:129) make certain investments;
(cid:129)
purchase, redeem or retire equity interests;
26
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
issue preferred stock;
sell or transfer assets;
incur liens;
enter into transactions with affiliates;
consolidate, merge, sell or lease all or substantially all of its assets; and
enter into sale and leaseback transactions.
Management fees and cost reimbursements due to our general partner and its affiliates will reduce cash available to pay
distributions to our unitholders.
We pay significant management fees to our general partner and its affiliates and reimburse them for expenses incurred on
our behalf, which reduces our cash available for distribution to our unitholders. See Note 11—Related Party Transactions of our
Notes to Consolidated Financial Statements for a description of these fees and expenses. Our general partner and its affiliates will
also be entitled to reimbursement for all other direct expenses that they incur on our behalf. The payment of fees to our general
partner and its affiliates and the reimbursement of expenses could adversely affect our ability to pay cash distributions to our
unitholders.
The amount of cash that we have available for distributions to our unitholders will depend primarily on our cash flow and not
solely on profitability.
The amount of cash that we will have available for distributions will depend primarily on our cash flow, including cash
reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a
result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during
periods when we record net income.
We have not paid any distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010.
We may not have sufficient cash available for distributions on our subordinated units in the future. Any further reduction in the
amount of cash available for distributions could impact our ability to pay the initial quarterly distribution on our common units in
full or at all.
We may not be able to maintain or increase the distributions on our common units and recommence making distributions on
our subordinated units unless we are able to make accretive acquisitions or implement accretive capital expansion projects,
which may require us to obtain one or more sources of funding.
We may not be able to make accretive acquisitions or implement accretive capital expansion projects, including our
liquefaction facilities, that would result in sufficient cash flow to fully pay distributions to the subordinated unitholder and allow
us to maintain or increase common unitholder distributions. To fund acquisitions or capital expansion projects, we will need to
pursue a variety of sources of funding, including debt and/or equity financings. Our ability to obtain these or other types of
financing will depend, in part, on factors beyond our control, such as our ability to obtain commitments from users of the facilities
to be acquired or constructed, the status of various debt and equity markets at the time financing is sought and such markets’ view
of our industry and prospects at such time. Any restrictive lending conditions in the U.S. credit markets may make it more time
consuming and expensive for us to obtain financing, if we can obtain such financing at all. Accordingly, we may not be able to
obtain financing for acquisitions or capital expansion projects on terms that are acceptable to us, if at all.
27
Risks Relating to an Investment in Us and Our Common Units
Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor
their own interests to the detriment of us and our unitholders.
Cheniere owns and, indirectly through Cheniere Holdings, controls our general partner, which has sole responsibility for
conducting our business and managing our operations. Some of our general partner’s directors are also directors of Cheniere, and
certain of our general partner’s officers are officers of Cheniere. Therefore, conflicts of interest may arise between Cheniere and
its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these
conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our unitholders.
These conflicts include, among others, the following situations:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
neither our partnership agreement nor any other agreement requires Cheniere to pursue a business strategy that favors
us. Cheniere’s directors and officers have a fiduciary duty to make these decisions in favor of the owners of Cheniere,
which may be contrary to our interests:
our general partner controls the interpretation and enforcement of contractual obligations between us, on the one hand,
and Cheniere, on the other hand, including provisions governing administrative services and acquisitions;
our general partner is allowed to take into account the interests of parties other than us, such as Cheniere and its affiliates,
in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us and our unitholders;
our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also
restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches
of fiduciary duty;
(cid:129) Cheniere is not limited in its ability to compete with us. Please read “Cheniere is not restricted from competing with us
and is free to develop, operate and dispose of, and is currently developing, LNG facilities, pipelines and other assets
without any obligation to offer us the opportunity to develop or acquire those assets”;
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings,
issuances of additional partnership securities, and the establishment, increase or decrease in the amounts of reserves, each
of which can affect the amount of cash that is distributed to our unitholders;
our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a
maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not
reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the
ability of the subordinated units to convert to common units;
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services
rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these
entities on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances,
is entitled to be indemnified by us;
our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than
80% of the common units; and
(cid:129)
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future
interconnection, natural gas balancing and storage agreements with one or more Cheniere-affiliated natural gas pipelines, services
agreements, as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional
contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.
In the event Cheniere favors its interests over our interests, we may have less available cash to make distributions on our
units than we otherwise would have if Cheniere had favored our interests.
28
Cheniere is not restricted from competing with us and is free to develop, operate and dispose of, and is currently developing,
LNG facilities, pipelines and other assets without any obligation to offer us the opportunity to develop or acquire those assets.
Cheniere and its affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly
with us. Cheniere may acquire, construct or dispose of its liquefaction project at Corpus Christi, Texas, its pipelines or any other
assets without any obligation to offer us the opportunity to purchase or construct any of those assets, other than, in certain
circumstances under an investors rights agreement with Blackstone CQP Holdco, its liquefaction project at Corpus Christi, Texas.
In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to
Cheniere and its affiliates. As a result, neither Cheniere nor any of its affiliates will have any obligation to present new business
opportunities to us, they may take advantage of such opportunities themselves, and they may enter into commercial arrangements
with respect to the liquefaction project at Corpus Christi, Texas that might otherwise have been entered into with respect to Train 6.
Cheniere also has significantly greater resources and experience than we have, which may make it more difficult for us to compete
with Cheniere and its affiliates with respect to commercial activities or acquisition candidates.
Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available
to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be
held by state fiduciary duty law. For example, our partnership agreement:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the
exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the
partnership or amendment to the partnership agreement;
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as
general partner, as long as it acted in good faith, meaning that it believed the decision was in the best interests of our
partnership;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts
committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no
less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and
reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner
may consider the totality of the relationships between the parties involved, including other transactions that may be
particularly favorable or advantageous to us;
provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to
us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered
by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or
engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was
criminal; and
provides that in resolving conflicts of interest, it will be presumed that in making its decision the conflicts committee or
the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the
person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including
the provisions described above.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which
could reduce the price at which our common units trade.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting
our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders will have
no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our
general partner is chosen entirely by affiliates of Cheniere. As a result, the price at which the common units will trade could be
diminished because of the absence or reduction of a control premium in the trading price.
29
Even if our unitholders are dissatisfied, they cannot initially remove our general partner without its consent.
The vote of the holders of at least 66 2/3% of all outstanding common units, Class B units and subordinated units (including
any units owned by our general partner and its affiliates), voting together as a single class is required to remove our general partner.
An affiliate of Cheniere owns 55.9% of our outstanding common units, Class B units and subordinated units, but it is contractually
prohibited from voting our units that it holds in favor of the removal of our general partner. If our general partner is removed
without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that
removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the
common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common
units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise
have continued until we had met certain distribution and performance tests. Cause is narrowly defined in our partnership agreement
to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for
actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of poor management
of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with our general partner’s
performance in managing our partnership will most likely result in the termination of the subordination period and conversion of
all subordinated units to common units.
Control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially
all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the
owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a
third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of
our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.
Our partnership agreement restricts the voting rights of unitholders (other than our general partner and its affiliates) owning
20% or more of any class of our units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20%
or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who
acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our
partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about
our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our partnership agreement prohibits a unitholder (other than our general partner and its affiliates) who acquires 15% or more
of our limited partner units without the approval of our general partner from engaging in a business combination with us for
three years unless certain approvals are obtained. This provision could discourage a change of control that our unitholders
may favor, which could negatively affect the price of our common units.
Our partnership agreement effectively adopts Section 203 of the General Corporation Law of the State of Delaware
(“DGCL”). Section 203 of the DGCL as it applies to us prevents an interested unitholder defined as a person (other than our
general partner and its affiliates) who owns 15% or more of our outstanding limited partner units from engaging in business
combinations with us for three years following the time such person becomes an interested unitholder unless certain approvals are
obtained. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an
interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on
other than a pro rata basis with other unitholders. This provision of our partnership agreement could have an anti-takeover effect
with respect to transactions not approved in advance by our general partner, including discouraging takeover attempts that might
result in a premium over the market price for our common units.
Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for contractual
obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware
law, and we conduct business in other states. As a limited partner in a partnership organized under Delaware law, holders of our
common units could be held liable for our obligations to the same extent as a general partner if a court determined that the right
30
or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments
to our partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of
our business. In addition, limitations on the liability of holders of limited partner interests for the obligations of a limited partnership
have not been clearly established in many jurisdictions.
Our unitholders may have liability to repay distributions wrongfully made.
Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section
17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the
distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three
years from the date of the impermissible distribution, partners who received such a distribution and who knew at the time of the
distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on
account of their partner interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining
whether a distribution is permitted.
We may issue additional units without approval of our unitholders, which would dilute their ownership interest in us.
At any time during the subordination period, with the approval of the conflicts committee of the board of directors of our
general partner, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders.
After the subordination period, we may issue an unlimited number of limited partner interests of any type without limitation of
any kind. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following
effects:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
our unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available per unit to pay distributions may decrease;
because a lower percentage of total outstanding units will be subordinated units, the risk will increase that a shortfall in
the payment of the initial quarterly distributions will be borne by our common unitholders;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
The market price of our common units has fluctuated significantly in the past and is likely to fluctuate in the future. Our
unitholders could lose all or part of their investment.
The market price of our common units has historically experienced and may continue to experience volatility. For example,
between January 1, 2015 and December 31, 2015, the market price of our common units ranged between $20.15 and $34.55. Such
fluctuations may continue as a result of a variety of factors, some of which are beyond our control, including:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
our quarterly distributions;
domestic and worldwide supply of and demand for natural gas and corresponding fluctuations in the price of natural gas;
fluctuations in our quarterly or annual financial results or those of other companies in our industry;
issuance of additional equity securities which causes further dilution to our unitholders;
sales of a high volume of units of our common units by our unitholders;
operating and unit price performance of companies that investors deem comparable to us;
events affecting other companies that the market deems comparable to us;
changes in government regulation or proposals applicable to us;
actual or potential non-performance by any customer or a counterparty under any agreement;
announcements made by us or our competitors of significant contracts;
changes in accounting standards, policies, guidance, interpretations or principles;
31
(cid:129)
(cid:129)
(cid:129)
(cid:129)
general conditions in the industries in which we operate;
general economic conditions;
the failure of securities analysts to cover our common units or changes in financial or other estimates by analysts; and
other factors described in these “Risk Factors.”
In addition, the United States securities markets have experienced significant price and volume fluctuations. These
fluctuations have often been unrelated to the operating performance of companies in these markets. Market fluctuations and broad
market, economic and industry factors may negatively affect the price of our common units, regardless of our operating performance.
If we were to be the object of securities class litigation as a result of volatility in our common unit price or for other reasons, it
could result in substantial diversion of our management’s attention and resources, which could negatively affect our financial
results.
Affiliates of our general partner may sell limited partner units, which sales could have an adverse impact on the trading price
of our common units.
Sales by us or any of our affiliated unitholders of a substantial number of our common units or our subordinated units, or
the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair
our ability to obtain capital through an offering of equity securities. An affiliate of Cheniere owns 11,963,488 common units,
135,383,831 subordinated units and 45,333,334 Class B units. All of the subordinated units will convert into common units at the
end of the subordination period and may convert earlier. Any sales of these units could have an adverse impact on the price of
our common units.
Risks Relating to Tax Matters
Our tax treatment depends on our status as a partnership for federal income tax purposes. If we were treated as a corporation
for federal income tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as
a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be
treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our
current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement
or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to
taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income taxes at varying rates.
Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions
would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions
to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction
in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common
units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, then the
initial quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
32
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash
available for distribution to you.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread
state budget deficits and other reasons, several states have been evaluating ways to subject partnerships to entity-level taxation
through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially
reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our
common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner
that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the initial quarterly distribution
amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative,
judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common
units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time the U.S.
President and members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws
that would affect publicly traded partnerships. Further, the U.S. Treasury Department and the Internal Revenue Service (“IRS”)
have issued proposed regulations under Section 7704(d)(1)(E) of the Code, interpreting the scope of qualifying income for publicly
traded partnerships by providing industry-specific guidance with respect to activities that will generate qualifying income for
purposes of the qualifying income requirement. The proposed regulations, once issued in final form, may change interpretations
of the current law relating to the characterization of income as qualifying income and could modify the amount of our gross income
we are able to treat as qualifying income for purposes of the qualifying income requirement. Any modification to the U.S. federal
income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible
for us to meet the exception to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether
any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an
investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month
based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular
common unit is transferred.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each
month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date
a particular unit is transferred. Although recently issued final Treasury Regulations allow publicly traded partnerships to use a
similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, such tax items must be
prorated on a daily basis and these regulations do not specifically authorize the use of the proration method we have adopted. If
the IRS were to successfully challenge this method or new Treasury Regulations were issued, we may be required to change the
allocation of items of income, gain, loss and deduction among our unitholders.
A change in tax treatment of our partnership, or a successful IRS contest of the federal income tax positions that we take, may
adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general
partner.
The IRS may adopt positions that differ from the positions that we take, even positions taken with advice of counsel. It
may be necessary to resort to administrative or court proceedings to sustain some or all of the positions that we take. A court may
not agree with some or all of the positions that we take. Any contest with the IRS may adversely impact the taxable income reported
to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and
adversely impact the market for our common units and the price at which our common units trade. In addition, the costs of any
contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to
our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
Recently enacted legislation, applicable to partnership tax years beginning after 2017, alters the procedures for auditing
large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level
federal income tax audit. Under the new rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partners
with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest)
33
directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties and interest as a result of
audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment
would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of
the adjustment even if they were not unitholders during the audited tax year.
Our unitholders may be required to pay taxes on their share of our taxable income even if they do not receive any cash
distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in
amount from the cash that we distribute, our unitholders will be required to pay federal income taxes and, in some cases, state and
local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders
may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which
results from their share of our taxable income.
We intend to allocate items of income, gain, loss and deduction among the holders of our common units and subordinated
units on or after the date that the subordination period ends to ensure that common units issued in exchange for our subordinated
units have the same economic and federal income tax characteristics as our other common units. Any such allocation of items of
our income or gain to unitholders, which may include allocations to holders of our common units, would not be accompanied by
a distribution of cash to such unitholders. In addition, any such allocation of items of deduction or loss to specific unitholders (for
example, to the holder of the subordinated units) would effectively reduce the amount of items of deduction or loss that will be
allocated to other unitholders.
Tax gain or loss on the disposition of our common units could be different than expected.
If our unitholders sell any of their common units, they will recognize gain or loss equal to the difference between the amount
realized and their tax basis in those common units. Because distributions in excess of the unitholders’ allocable share of our net
taxable income decrease the unitholders’ tax basis in their common units, the amount, if any, of such prior excess distributions
with respect to the units sold will, in effect, become taxable income to the unitholder if they sell such units at a price greater than
their tax basis in those units, even if the price received is less than their original cost. A substantial portion of the amount realized,
whether or not representing gain, may be ordinary income due to the potential recapture items, including depreciation recapture.
In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells
common units may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investments in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), raises issues
unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal
income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and
will be taxable to them.
Non-U.S. investors face unique tax issues from owning common units that may result in adverse tax consequences to them.
Non-U.S. investors who own common units will be required to file U.S. federal income tax returns and pay tax on their
share of our taxable income and distributions to non-U.S. investors will generally be reduced by withholding taxes at the highest
applicable effective tax rate. The IRS has taken the position that a non-U.S. investor’s gain on the sale of common units is subject
to United States federal income tax.
We will treat each holder of our common units as having the same tax benefits without regard to the actual common units held.
The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions
that may not conform with all aspects of applicable Treasury Regulations.
A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders.
It also could affect the timing of those tax benefits or the amount of gain from the sale of common units and could have a negative
impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.
34
Our unitholders will likely be subject to state and local taxes and return filing requirements as a result of an investment in our
common units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local income
taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in
which we do business or own property, even if the unitholder does not live in any of those jurisdictions. Our unitholders may be
required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.
Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions
or expand our business, we may own property or conduct business in additional states or foreign countries that impose a personal
tax or an entity level tax. Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility
of our unitholders to file all United States federal, state and local tax returns.
The sale or exchange of 50% or more of the total interest in our capital and profits during any twelve-month period will result
in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or
exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining
whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. Our technical termination
would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax
returns (and our unitholders could receive two Schedules K-1 if relief was not available as described below) for one fiscal year.
Our technical termination could also result in a deferral of depreciation deductions allowable in computing our taxable income.
In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable
year may result in more than 12 months of our taxable income or loss being includable in the unitholder’s taxable income for the
year of termination. Our technical termination currently would not affect our classification as a partnership for federal income
tax purposes, but instead, we would be treated as a new partnership, we would be required to make new tax elections and we could
be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has announced a publicly
traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests
relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to
unitholders for the year, notwithstanding two partnership tax years.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction.
The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value
of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the
fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation
matters, we make many fair market value estimates ourselves using a methodology based on the market value of our common
units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting
allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income
or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and
could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without
the benefit of additional deductions.
35
A unitholder whose common units are loaned to a “short seller” to cover a short sale of units may be considered as having
disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to
those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of units may be considered as
having disposed of the loaned common units, the unitholder may no longer be treated for tax purposes as a partner with respect
to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such
disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to
those common units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those
common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk
of gain recognition from a loan to a short seller are urged to consult with their tax advisor about whether it is advisable to modify
any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
LEGAL PROCEEDINGS
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of
business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual
disposition of these matters. In the opinion of management, as of December 31, 2015, there were no pending legal matters that
would reasonably be expected to have a material impact on our consolidated operating results, financial position or cash flows.
ITEM 4.
MINE SAFETY DISCLOSURE
None.
36
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common units began trading on the NYSE MKT under the symbol “CQP” commencing with our initial public offering
on March 21, 2007. The table below presents the high and low sales prices per common unit, as reported by the NYSE MKT, and
cash distributions to common unitholders for each quarter during 2015 and 2014.
2015
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2014
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
High
Low
Cash
Distributions
Per Common
Unit (1)
Cash
Distributions
Per
Subordinated
Unit (2)
Cash
Distributions
Per Class B
Unit (3)
$
$
$
$
32.70
34.55
32.54
29.59
30.23
34.60
33.48
33.00
$
$
28.36
29.77
20.53
20.15
27.42
29.71
30.96
25.08
$
$
0.425
0.425
0.425
0.425
0.425
0.425
0.425
0.425
— $
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
(1) We also paid cash distributions to our general partner with respect to its 2% general partner interest.
(2) We have not paid distributions on our subordinated units since the distribution made with respect to the quarter ended March
31, 2010. See “Subordination Period” below.
(3) Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of
substantially all of our assets). See “Class B Units” below.
A distribution for the quarter ended December 31, 2015 of $0.425 per common unit was paid on February 12, 2016. In
addition, we paid cash distributions to our general partner with respect to its 2% general partner interest.
As of February 12, 2016, we had (1) 57.1 million common units outstanding held by approximately 12 record owners and
(2) 145.3 million Class B units outstanding, of which 100.0 million Class B units were held by Blackstone CQP Holdco and 45.3
million Class B units were held by Cheniere Holdings.
We consider cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash
distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors.
The SPLNG Indentures described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”
may prohibit SPLNG from making cash distributions to us under certain circumstances, which could limit our ability to make
distributions.
Upon the closing of our initial public offering, Cheniere received 135,383,831 subordinated units. Below is a description
of our cash distribution policy regarding common, subordinated and Class B units. References therein to “unitholders” made in
the context of the recipients of quarterly cash distributions refer to our common unitholders and subordinated unitholders.
Cash Distribution Policy
Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all
of our available cash quarterly.
37
Subordination Period
During the subordination period, the common units will have the right to receive distributions of available cash from
operating surplus in an amount equal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment
of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating
surplus may be made on the subordinated units. Cheniere Holdings owns all of the 135,383,831 subordinated units, representing
39.3% of the limited partner interests in us as of December 31, 2015. These units are deemed “subordinated” because for a period
of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until after
the common units have received the initial quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages
will be paid on the subordinated units. The practical effect of the subordination period is to increase the likelihood that during
this period there will be sufficient available cash to pay the initial quarterly distribution on the common units.
As a result of the assignment of Cheniere Marketing’s TUA to Cheniere Investments, effective July 1, 2010, our available
cash for distributions was reduced. Therefore, we have not paid distributions on our subordinated units since the distribution made
with respect to the quarter ended March 31, 2010.
Definition of Subordination Period
The subordination period will extend until the first business day following the distribution of available cash to partners in
respect of any quarter that each of the following occurs:
(cid:129)
(cid:129)
distributions of available cash from operating surplus on each of the outstanding common units (assuming conversion of
the Class B units), subordinated units and any other outstanding units that are senior or equal in right of distribution to
the subordinated units equaled or exceeded the sum of the initial quarterly distributions on all of the outstanding common
units (assuming conversion of the Class B units), subordinated units, general partner units and any other outstanding units
that are senior or equal in right of distribution to the subordinated units for each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date;
the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-
quarter periods immediately preceding that date equaled or exceeded the sum of the initial quarterly distributions on all
of the outstanding common units (assuming conversion of the Class B units), subordinated units, general partner units
and any other outstanding units that are senior or equal in right of distribution to the subordinated units during those
periods on a fully diluted basis; and
(cid:129)
there are no arrearages in payment of the initial quarterly distribution on the common units.
Expiration of the Subordination Period
When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then
participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our
general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:
(cid:129)
(cid:129)
(cid:129)
the subordination period will end and each subordinated unit will immediately convert into one common unit;
any existing arrearages in payment of the initial quarterly distribution on the common units will be extinguished; and
the general partner will have the right to convert its general partner units and its incentive distribution rights into common
units or to receive cash in exchange for those interests.
Early Conversion of Subordinated Units
The subordination period will automatically terminate and all of the subordinated units will convert into common units on
a one-for-one basis on the first business day following the distribution of available cash to partners in respect of any quarter that
each of the following occurs:
(cid:129)
in connection with distributions of available cash from operating surplus, the amount of such distributions constituting
“contracted adjusted operating surplus” (as defined below) on each outstanding common unit (assuming conversion of
the Class B units), subordinated unit and any other outstanding unit that is senior or equal in right of distribution to the
38
subordinated units equaled or exceeded $0.638 (150% of the initial quarterly distribution) for each quarter in the four-
quarter period immediately preceding that date;
(cid:129)
the contracted adjusted operating surplus generated during each quarter in the four-quarter period immediately preceding
that date equaled or exceeded the sum of a distribution of $0.638 (150% of the initial quarterly distribution) on all of the
outstanding common units (assuming conversion of the Class B units), subordinated units, general partner units, any other
units that are senior or equal in right of distribution to the subordinated units, and any other equity securities that are
junior to the subordinated units that the board of directors of our general partner deems to be appropriate for the calculation,
after consultation with management of our general partner, on a fully diluted basis; and
(cid:129)
there are no arrearages in payment of the initial quarterly distribution on the common units
Definition of Adjusted Operating Surplus
We define adjusted operating surplus in our partnership agreement, and for any period, it generally means:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
operating surplus generated with respect to that period; less
any net increase in working capital borrowings with respect to that period; less
any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating
expenditure made with respect to that period; plus
any net decrease in working capital borrowings with respect to that period; plus
any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument
for the repayment of principal, interest or premium.
Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore
excludes the $30 million operating surplus “basket,” net increases in working capital borrowings, net drawdowns of reserves of
cash generated in prior periods.
Definition of Contracted Adjusted Operating Surplus
We define contracted adjusted operating surplus in our partnership agreement and it:
(cid:129)
(cid:129)
generally means adjusted operating surplus derived solely from SPAs and TUAs, in each case, with a minimum term of
three years with counterparties who are not affiliates of Cheniere; and
excludes revenues and expenses attributable to the portion of payments made under the LNG sale and purchase agreements
related to the final settlement price for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for
the month in which the relevant cargo’s delivery window is scheduled.
Class B Units
During 2012, Blackstone CQP Holdco and Cheniere completed their purchases of Class B units for total consideration of
$1.5 billion and $500.0 million, respectively. Proceeds from the financings are being used to fund a portion of the costs of
developing, constructing and placing into service the Liquefaction Project. In May 2013, Cheniere purchased an additional 12.0
million Class B units for consideration of $180.0 million in connection with our acquisition of Cheniere’s ownership interests in
CTPL and Cheniere Pipeline GP Interests, LLC (collectively, “the Creole Trail Pipeline Business”), described in Note 3—Summary
of Significant Accounting Policies of our Notes to Consolidated Financial Statements. The Class B units are not entitled to cash
distributions except in the event of our liquidation or a merger, consolidation or other combination of us with another person or
the sale of all or substantially all of our assets. The Class B units are subject to conversion, mandatorily or at the option of the
holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion
value of the Class B units. On a quarterly basis beginning on the initial purchase date of the Class B units, the conversion value
of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain
equity and debt financings. The holders of Class B units have a preference over the holders of the subordinated units in the event
of a liquidation (or merger, combination or sale of substantially all of our assets).
39
General Partner Units and Incentive Distribution Rights
Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available
cash from operating surplus in excess of the initial quarterly distribution. Our general partner currently holds the incentive
distribution rights but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership
agreement.
Assuming we do not issue any additional classes of units that are paid distributions and our general partner maintains its
2% interest, if we have made distributions to our unitholders from operating surplus in an amount equal to the initial quarterly
distribution for any quarter, assuming no arrearages, then we will distribute any additional available cash from operating surplus
for that quarter among the unitholders and our general partner as follows:
Initial quarterly distribution
First Target Distribution
Second Target Distribution
Third Target Distribution
Thereafter
ITEM 6.
SELECTED FINANCIAL DATA
Marginal Percentage
Interest Distributions
Total Quarterly Distribution
Target Amount
$0.425
Above $0.425 up to $0.489
Above $0.489 up to $0.531
Above $0.531 up to $0.638
Above $0.638
Common and
Subordinated
Unitholders
98%
98%
85%
75%
50%
General Partner
2%
2%
15%
25%
50%
Selected financial data set forth below (in thousands, except per unit data) are derived from our audited Consolidated
Financial Statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion
and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the accompanying
notes thereto included elsewhere in this report.
Year Ended December 31,
2015
270,028
$
2014
268,698
$
2013
268,191
2012
264,498
2011
283,888
$
$
$
Revenues (including transactions with affiliates)
Operating costs and expenses (including
transactions with affiliates)
Income (loss) from operations
Interest expense, net of capitalized interest
Net loss
Net income (loss) per common unit
Weighted average units outstanding
$
(0.43) $
— $
(0.03) $
57,081
57,079
54,235
266,986
268,183
3,042
(184,600)
(318,891)
515
(177,032)
(410,036)
300,220
(32,029)
(178,400)
(258,117)
226,875
37,623
(171,646)
(175,431)
0.27
33,470
Cash and cash equivalents
Restricted cash (current)
Non-current restricted cash
$
2015
146,221
274,557
13,650
$
2014
248,830
195,702
544,465
December 31,
$
2013
351,032
227,652
1,025,056
$
2012
419,292
92,519
272,425
Property, plant and equipment, net
11,931,602
8,978,356
6,383,939
3,219,592
2,044,020
Total assets
Current debt, net
Long-term debt, net
12,996,327
10,387,515
8,516,783
4,265,787
2,267,990
1,676,197
—
—
—
—
10,178,681
8,991,333
6,576,273
2,167,113
Total partners’ equity (deficit)
712,931
1,130,729
1,639,744
1,879,978
40
164,054
119,834
(173,590)
(53,560)
1.23
27,910
2011
81,415
13,732
82,394
$
$
2,192,418
(14,411)
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall
performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes in
“Financial Statements and Supplementary Data.” This information is intended to provide investors with an understanding of our
past performance, current financial condition and outlook for the future. Our discussion and analysis includes the following
subjects:
(cid:129) Overview of Business
(cid:129) Overview of Significant Events
(cid:129) Liquidity and Capital Resources
(cid:129) Contractual Obligations
(cid:129) Results of Operations
(cid:129) Off-Balance Sheet Arrangements
(cid:129)
Summary of Critical Accounting Estimates
(cid:129) Recent Accounting Standards
Overview of Business
We are a publicly traded Delaware limited partnership formed by Cheniere. Through our wholly owned subsidiary, SPLNG,
we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine-Neches Waterway less than
four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with
capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters
and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We are developing and constructing natural gas liquefaction
facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through our
wholly owned subsidiary, SPL. We are constructing five Trains and developing a sixth Train, each of which is expected to have
a nominal production capacity of approximately 4.5 mtpa of LNG. We also own a 94-mile pipeline that interconnects the Sabine
Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through our wholly owned subsidiary,
CTPL.
Overview of Significant Events
Our significant accomplishments since January 1, 2015 and through the filing date of this Form 10-K include the following:
(cid:129)
SPL issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 SPL
Senior Notes”). Net proceeds from the offering will be used to pay a portion of the capital costs associated with the
construction of the first four Trains of the Liquefaction Project.
(cid:129) We received authorization from the FERC to site, construct and operate Trains 5 and 6 of the Liquefaction Project.
(cid:129)
(cid:129)
(cid:129)
SPL received authorization from the DOE to export up to a combined total of the equivalent of 503.3 Bcf/yr of domestically
produced LNG by vessel from Trains 5 and 6 of the Liquefaction Project to non-FTA countries for a 20-year term.
SPL and Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) entered into a lump sum turnkey contract for the engineering,
procurement and construction of Train 5 of the Liquefaction Project (the “EPC Contract (Train 5)”).
SPL entered into four credit facilities (collectively, the “2015 SPL Credit Facilities”) aggregating $4.6 billion, which
terminated and replaced its existing credit facilities. The 2015 SPL Credit Facilities will be used to fund a portion of the
costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project.
(cid:129)
SPL issued a notice to proceed to Bechtel under the EPC Contract (Train 5).
41
(cid:129)
(cid:129)
SPL entered into a $1.2 billion Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit
Reimbursement Agreement (the “SPL Working Capital Facility”), which replaced the $325.0 million senior letter of credit
and reimbursement agreement that was entered into in April 2014 (the “SPL LC Agreement”). The SPL Working Capital
Facility will be used primarily for certain working capital requirements related to developing and placing into operation
the Liquefaction Project.
In January 2016, we engaged 13 financial institutions to act as Joint Lead Arrangers, Mandated Lead Arrangers and other
participants to assist in the structuring and arranging of up to approximately $2.8 billion of senior secured credit facilities.
Proceeds from these new credit facilities are intended to be used by us to prepay $400.0 million of the CTPL term loan
facility (the “CTPL Term Loan”), to redeem or repay $1,665.5 million of the 7.50% Senior Secured Notes due 2016 (the
“2016 SPLNG Senior Notes”) and $420.0 million of the 6.50% Senior Secured Notes due 2020 (the “2020 SPLNG Senior
Notes” and collectively with the 2016 SPLNG Senior Notes, the “SPLNG Senior Notes”), to pay associated transaction
fees, expenses and make-whole amounts, if applicable, and for our general business purposes.
Liquidity and Capital Resources
Cash and Cash Equivalents
As of December 31, 2015, we had $146.2 million of cash and cash equivalents and $288.3 million of current and non-
current restricted cash (which included current and non-current restricted cash available to us, SPL, CTPL and SPLNG) designated
for the following purposes: $189.3 million for the Liquefaction Project; $7.9 million for CTPL; and $91.1 million for interest
payments related to the SPLNG Senior Notes described below.
Sabine Pass LNG Terminal
Regasification Facilities
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG
storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG
terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed
monthly fees, whether or not they use the LNG terminal. Each of Total Gas & Power North America, Inc. (“Total”) and Chevron
U.S.A. Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity
payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009. Total S.A. has
guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has
guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.
The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make
monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after
SPL delivers its first commercial cargo at the Liquefaction Project. SPL entered into a partial TUA assignment agreement with
Total, whereby SPL will progressively gain access to Total’s capacity and other services provided under Total’s TUA with SPLNG.
This agreement will provide SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used
to accommodate the development of Trains 5 and 6, provide increased flexibility in managing LNG cargo loading and unloading
activity starting with the commencement of commercial operations of Train 3 and permit SPL to more flexibly manage its LNG
storage capacity with the commencement of Train 1. Notwithstanding any arrangements between Total and SPL, payments required
to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.
Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.
Liquefaction Facilities
The Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal adjacent to the existing
regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. We
commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in
August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In June 2015, we commenced
construction of Train 5 and the related facilities.
42
The DOE has authorized the export of up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of
domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries for a 30-year term and to non-FTA
countries for a 20-year term. The DOE further issued an order authorizing SPL to export up to the equivalent of approximately
203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period. SPL’s
application for authorization to export that same 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal
to non-FTA countries is currently pending at the DOE. Additionally, the DOE issued orders authorizing SPL to export up to a
combined total of 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries and non-FTA
countries for a 20-year term. A party to the proceeding requested a rehearing of the non-FTA order pertaining to the 503.3 Bcf/
yr, and the DOE has not yet issued a final ruling on the rehearing request. In each case, the terms of these authorizations begin
on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 5 to 10 years
from the date the order was issued. Furthermore, the DOE issued an order authorizing SPL to export up to 600 Bcf in total of
domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-
year period commencing on January 15, 2016.
As of December 31, 2015, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction
Project were approximately 97.4% and 79.5%, respectively. As of December 31, 2015, the overall project completion percentage
for Train 5 of the Liquefaction Project was approximately 14.9% with engineering, procurement and construction approximately
41.9%, 20.5% and 0.1% complete, respectively. As of December 31, 2015, the overall project completion of each of our Trains
was ahead of the contractual schedule. We produced our first LNG from Train 1 of the Liquefaction Project in February 2016.
Based on our current construction schedule, we anticipate that Train 2 will produce LNG as early as mid-2016 and Trains 3 through
5 are expected to commence operations on a staggered basis thereafter.
Customers
SPL has entered into six fixed price, 20-year SPAs with third parties that in the aggregate equate to approximately 19.75
mtpa of LNG, which is approximately 88% of the expected aggregate nominal production capacity of Trains 1 through 5, that
commence with the date of first commercial delivery for Trains 1 through 5. Under these SPAs, the customers will purchase LNG
from SPL for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers
may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee
with respect to the contracted volumes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for
inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the
term of each SPA commences upon the start of operations of a specified Train.
In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion annually for
Trains 1 through 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable
Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of
Trains 1 through 5, respectively.
In addition, Cheniere Marketing has entered into an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG
produced by SPL in excess of that required for other customers.
All of our revenues from external customers and long-lived assets for each of the years ended December 31, 2015, 2014
and 2013 are attributed to or located in the United States.
Construction
SPL entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1
through 5, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain
specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change
order.
The total contract prices of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC Contract
(Train 5) of the Liquefaction Project are approximately $4.1 billion, $3.8 billion and $3.0 billion, respectively, reflecting amounts
incurred under change orders through December 31, 2015. Total expected capital costs for Trains 1 through 5 are estimated to be
between $12.5 billion and $13.5 billion before financing costs and between $17.0 billion and $18.0 billion after financing costs,
including, in each case, estimated owner’s costs and contingencies.
43
Final Investment Decision on Train 6
We will contemplate making a final investment decision (“FID”) to commence construction of Train 6 of the Liquefaction
Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements and
obtaining adequate financing to construct the Train.
Capital Resources
We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 5 of the Liquefaction Project
will be financed through one or more of the following: borrowings, equity contributions from us and cash flows under the SPAs.
We believe that with the net proceeds of borrowings, available commitments under the 2015 SPL Credit Facilities, available
commitments under the SPL Working Capital Facility and cash flows from operations, we will have adequate financial resources
available to complete Trains 1 through 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and
debt service requirements. We currently project that we will generate cash flow from the Liquefaction Project by early 2016.
Senior Secured Notes
As of December 31, 2015, our subsidiaries had seven series of senior secured notes outstanding (collectively, the “Senior
Notes”):
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
$1.7 billion of the 2016 SPLNG Senior Notes;
$0.4 billion of the 2020 SPLNG Senior Notes;
$2.0 billion of 5.625% Senior Secured Notes due 2021 issued by SPL (the “2021 SPL Senior Notes”);
$1.0 billion of 6.25% Senior Secured Notes due 2022 issued by SPL (the “2022 SPL Senior Notes”);
$1.5 billion of 5.625% Senior Secured Notes due 2023 issued by SPL (the “2023 SPL Senior Notes”);
$2.0 billion of 5.75% Senior Secured Notes due 2024 issued by SPL (the “2024 SPL Senior Notes” and collectively with
the 2021 SPL Senior Notes, the 2022 SPL Senior Notes, the 2023 SPL Senior Notes and the 2025 SPL Senior Notes, the
“SPL Senior Notes”); and
(cid:129)
$2.0 billion of the 2025 SPL Senior Notes.
Interest on the SPL Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the SPLNG Senior Notes
are secured on a pari passu first-priority basis by a security interest in all of SPLNG’s equity interests and substantially all of
SPLNG’s operating assets. The SPL Senior Notes are secured on a first-priority basis by a security interest in all of the membership
interests in SPL and substantially all of SPL’s assets.
SPLNG may redeem all or part of its 2016 SPLNG Senior Notes at any time at a redemption price equal to 100% of the
principal plus any accrued and unpaid interest plus the greater of:
(cid:129)
(cid:129)
1.0% of the principal amount of the 2016 SPLNG Senior Notes; or
the excess of: (1) the present value at such redemption date of (a) the redemption price of the 2016 SPLNG Senior Notes
plus (b) all required interest payments due on the 2016 SPLNG Senior Notes (excluding accrued but unpaid interest to
the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis
points; over (2) the principal amount of the 2016 SPLNG Senior Notes, if greater.
SPLNG may redeem all or part of the 2020 SPLNG Senior Notes at any time on or after November 1, 2016 at fixed redemption
prices specified in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest, if any, to the date of
redemption. SPLNG may also, at its option, redeem all or part of the 2020 SPLNG Senior Notes at any time prior to November 1,
2016, at a “make-whole” price set forth in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest,
if any, to the date of redemption.
At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes, SPL may
redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price set forth in the
44
common indenture governing the SPL Senior Notes (the “SPL Indenture”), plus accrued and unpaid interest, if any, to the date of
redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior
Notes, redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of
such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
Under the indentures governing the SPLNG Senior Notes (the “SPLNG Indentures”), except for permitted tax distributions,
SPLNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a
fixed charge coverage ratio test of 2:1 is satisfied. Under the SPL Indenture, SPL may not make any distributions until, among
other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts
as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. During the years ended December 31, 2015, 2014 and
2013, SPLNG made distributions of $337.3 million, $346.9 million and $348.9 million, respectively, after satisfying all the
applicable conditions in the SPLNG Indentures.
The SPL Indenture includes restrictive covenants. SPL may incur additional indebtedness in the future, including by issuing
additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive
covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes, the 2015 SPL Credit Facilities and
the SPL Working Capital Facility.
2015 SPL Credit Facilities
In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion. The 2015 SPL
Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through
5 of the Liquefaction Project. Borrowings under the 2015 SPL Credit Facilities may be refinanced, in whole or in part, at any time
without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. As of December 31,
2015, SPL had $3.8 billion of available commitments and outstanding borrowings of $845.0 million under the 2015 SPL Credit
Facilities.
Loans under the 2015 SPL Credit Facilities accrue interest at a variable rate per annum equal to, at SPL’s election, LIBOR
or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.30% to 1.75%, depending on
the applicable 2015 SPL Credit Facility, and the applicable margin for base rate loans is 1.75%. Interest on LIBOR loans is due
and payable at the end of each LIBOR period and interest on base rate loans is due and payable at the end of each quarter. In
addition, SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered
tranches of the 2015 SPL Credit Facilities. The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee
calculated at a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the
undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility. The
principal of the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the
earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the
Liquefaction Project. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon
the maturity of the 2015 SPL Credit Facilities.
The 2015 SPL Credit Facilities contain conditions precedent for borrowings, as well as customary affirmative and negative
covenants. The obligations of SPL under the 2015 SPL Credit Facilities are secured by substantially all of the assets of SPL as
well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and SPL Working Capital Facility.
Under the terms of the 2015 SPL Credit Facilities, SPL is required to hedge not less than 65% of the variable interest rate
exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of
principal. Additionally, SPL may not make any distributions until substantial completion of Trains 1 and 2 of the Liquefaction
Project has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is
satisfied.
2013 SPL Credit Facilities
In May 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 SPL Credit Facilities”)
to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project,
which amended and restated the existing credit facility that was entered into in 2012 (the “2012 SPL Credit Facility”). In June
2015, the 2013 SPL Credit Facilities were replaced with the 2015 SPL Credit Facilities.
45
In March 2015, in conjunction with SPL’s issuance of the 2025 SPL Senior Notes, SPL terminated approximately $1.8
billion of commitments under the 2013 SPL Credit Facilities. This termination and the replacement of the 2013 SPL Credit
Facilities with the 2015 SPL Credit Facilities in June 2015 resulted in a write-off of debt issuance costs and deferred commitment
fees associated with the 2013 SPL Credit Facilities of $96.3 million for the year ended December 31, 2015. The amendment and
restatement of the 2012 SPL Credit Facility with the 2013 SPL Credit Facilities in May 2013 resulted in a write-off of debt issuance
costs and deferred commitment fees associated with the 2012 SPL Credit Facility of $88.3 million during the year ended December
31, 2013.
CTPL Term Loan
CTPL has the $400.0 million CTPL Term Loan, which was used to fund modifications to the Creole Trail Pipeline and for
general business purposes. The CTPL Term Loan matures in 2017 when the full amount of the outstanding principal obligations
must be repaid. CTPL’s loan may be repaid, in whole or in part, at any time without premium or penalty. As of December 31,
2015, CTPL had borrowed the full amount of $400.0 million available under the CTPL Term Loan. Borrowings under the CTPL
Term Loan accrue interest at a variable rate per annum equal to, at CTPL’s election, LIBOR or the base rate, plus the applicable
margin. The applicable margin for LIBOR loans is 3.25%. Interest on LIBOR loans is due and payable at the end of each LIBOR
period.
SPL Working Capital Facility
In September 2015, SPL entered into the $1.2 billion SPL Working Capital Facility, which replaced the $325.0 million SPL
LC Agreement. The SPL Working Capital Facility is intended to be used for loans to SPL (“Working Capital Loans”), the issuance
of letters of credit on behalf of SPL (“Letters of Credit”), as well as for swing line loans to SPL (“Swing Line Loans”), primarily
for certain working capital requirements related to developing and placing into operation the Liquefaction Project. SPL may, from
time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the
completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to
an additional $390 million. As of December 31, 2015, SPL had $1.1 billion of available commitments, $135.2 million aggregate
amount of issued Letters of Credit, $15.0 million in Working Capital Loans and no Swing Line Loans or loans deemed made in
connection with a draw upon a Letter of Credit (“LC Loans” and collectively with Working Capital Loans and Swing Line Loans,
the “SPL Working Capital Facility Loans”) outstanding under the SPL Working Capital Facility. As of December 31, 2014, SPL
had issued letters of credit in an aggregate amount of $9.5 million, and no draws had been made upon any letters of credit issued
under the SPL LC Agreement.
SPL Working Capital Facility Loans accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to
the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve
Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR
SPL Working Capital Facility Loans is 1.75% per annum, and the applicable margin for base rate SPL Working Capital Facility
Loans is 0.75% per annum. Interest on Swing Line Loans and LC Loans is due and payable on the date the loan becomes due.
Interest on LIBOR Working Capital Loans is due and payable at the end of each applicable LIBOR period, and interest on base
rate Working Capital Loans is due and payable at the end of each fiscal quarter. However, if such base rate Working Capital Loan
is converted into a LIBOR Working Capital Loan, interest is due and payable on that date. Additionally, if the loans become due
prior to such periods, the interest also becomes due on that date.
SPL incurred $27.5 million of debt issuance costs in connection with the SPL Working Capital Facility. SPL pays (1) a
commitment fee equal to an annual rate of 0.70% on the average daily amount of the excess of the total commitment amount over
the principal amount outstanding without giving effect to any outstanding Swing Line Loans and (2) a Letter of Credit fee equal
to an annual rate of 1.75% of the undrawn portion of all Letters of Credit issued under the SPL Working Capital Facility. If draws
are made upon a Letter of Credit issued under the SPL Working Capital Facility and SPL does not elect for such draw (an “LC
Draw”) to be deemed an LC Loan, SPL is required to pay the full amount of the LC Draw on or prior to the business day following
the notice of the LC Draw. An LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of December 31, 2015,
no LC Draws had been made upon any Letters of Credit issued under the SPL Working Capital Facility.
The SPL Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or
in part, at any time without premium or penalty upon three business days’ notice. LC Loans have a term of up to one year. Swing
Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the SPL Working Capital Facility, (2) the
46
date 15 days after such Swing Line Loan is made and (3) the first borrowing date for a Working Capital Loan or Swing Line Loan
occurring at least three business days following the date the Swing Line Loan is made. SPL is required to reduce the aggregate
outstanding principal amount of all Working Capital Loans to zero for a period of five consecutive business days at least once each
year.
The SPL Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative
and negative covenants. The obligations of SPL under the SPL Working Capital Facility are secured by substantially all of the
assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and the 2015 SPL
Credit Facilities.
Arrangement to Refinance Project Debt
In January 2016, we engaged 13 financial institutions to act as Joint Lead Arrangers, Mandated Lead Arrangers and other
participants to assist in the structuring and arranging of up to approximately $2.8 billion of senior secured credit facilities. Proceeds
from these new credit facilities are intended to be used by us to prepay $400.0 million of the CTPL Term Loan, to redeem or repay
$1,665.5 million of the 2016 SPLNG Senior Notes and $420.0 million of the 2020 SPLNG Senior Notes, to pay associated
transaction fees, expenses and make-whole amounts, if applicable, and for our general business purposes.
Sources and Uses of Cash
The following table summarizes the sources and uses of our cash and cash equivalents (in thousands) for the years ended
December 31, 2015, 2014 and 2013. The table presents capital expenditures on a cash basis; therefore, these amounts differ from
the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of
these items follows the table.
Sources of cash and cash equivalents
Proceeds from issuances of debt
Use of restricted cash for the acquisition of property, plant and equipment
Operating cash flow
Proceeds from sale of partnership common and general partner units
Contributions to Creole Trail Pipeline Business from Cheniere, net
Total sources of cash and cash equivalents
Uses of cash and cash equivalents
Investment in restricted cash
Property, plant and equipment, net
Debt issuance and deferred financing costs
Distributions to owners
Repayments of debt
Purchase of Creole Trail Pipeline Business, net
Other
Total uses of cash and cash equivalents
Net decrease in cash and cash equivalents
Cash and cash equivalents—beginning of period
Cash and cash equivalents—end of period
Year Ended December 31,
2014
2013
2015
$2,860,000
2,965,477
5,748
—
—
5,831,225
$2,584,500
2,669,332
11,928
—
—
5,265,760
$ 4,504,478
3,119,632
35,664
375,897
20,896
8,056,567
(2,690,364)
(2,912,080)
(169,924)
(99,018)
—
—
(62,448)
(5,933,834)
(2,303,763)
(2,645,553)
(103,787)
(98,979)
(177,000)
—
(38,880)
(5,367,962)
(4,173,959)
(3,120,643)
(311,050)
(91,386)
(100,000)
(313,892)
(13,897)
(8,124,827)
(102,609)
248,830
$ 146,221
(102,202)
351,032
$ 248,830
(68,260)
419,292
$ 351,032
47
Proceeds from Issuances of Debt, Debt Issuance and Deferred Financing Costs and Repayments of Debt
In March 2015, SPL issued an aggregate principal amount of $2.0 billion of the 2025 SPL Senior Notes. In June 2015, SPL
entered into the 2015 SPL Credit Facilities aggregating $4.6 billion, which terminated and replaced the 2013 SPL Credit Facilities,
and borrowed $845.0 million under this facility during the year ended December 31, 2015. In September 2015, SPL entered into
the $1.2 billion SPL Working Capital Facility which replaced the SPL LC Agreement, and borrowed $15.0 million in Working
Capital Loans during the year ended December 31, 2015. Debt issuance and deferred financing costs in the year ended December
31, 2015 primarily relate to up-front fees paid upon the closing of these transactions.
In May 2014, SPL issued an aggregate principal amount of $2.0 billion of the 2024 SPL Senior Notes and an additional
$0.5 billion principal amount of the 2023 SPL Senior Notes for total net proceeds of approximately $2.5 billion. Debt issuance
costs in the year ended December 31, 2014 primarily relate to up-front fees paid upon the closing of these offerings.
During 2013, SPL issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 SPL Senior Notes and
$1.0 billion of each of the 2023 SPL Senior Notes and 2022 SPL Senior Notes. Net proceeds from those offerings were used to
pay a portion of the capital costs incurred in connection with the construction of the Liquefaction Project. In May 2013, CTPL
entered into the $400.0 million CTPL Term Loan, which was used to fund modifications to the Creole Trail Pipeline and for general
business purposes. In June 2013, SPL borrowed $100.0 million under the 2013 SPL Credit Facilities. Debt issuance and deferred
financing costs in the year ended December 31, 2013 primarily related to up-front fees paid by SPL upon the closing of the 2013
SPL Credit Facilities and the senior notes issued by SPL during the year.
Use of Restricted Cash for the Acquisition of Property, Plant and Equipment and Property, Plant and Equipment, net
During the years ended December 31, 2015, 2014 and 2013, we used $2,965.5 million, $2,669.3 million and $3,119.6
million, respectively, of restricted cash for investing activities to partially fund $2,912.1 million, $2,645.6 million and 3,120.6
million, respectively, of construction costs for Trains 1 through 5 of the Liquefaction Project. The costs associated with the
construction of Trains 1 through 5 of the Liquefaction Project are capitalized as construction-in-process.
Operating Cash Flow
Cash provided by operations during the years ended December 31, 2015, 2014 and 2013 was $5.7 million, $11.9 million
and $35.7 million, respectively. The decrease cash provided by operating activities from 2014 to 2015 primarily related to the
timing of amounts paid to third parties for operating costs. The decrease in cash provided by operating activities from 2013 to
2014 was primarily a result of increased cash outflows during 2014 related to the settlement of interest rate swaps to hedge the
exposure to volatility in a portion of the floating-rate interest payments under the 2013 SPL Credit Facilities.
Proceeds from the Sale of Partnership Common and General Partner Units
In the year ended December 31, 2013, we received $375.9 million in proceeds from the sale of Cheniere Partners common
and general partner units primarily related to the sale of 17.6 million common units to institutional investors in February 2013.
We used the proceeds from this offering to purchase Cheniere’s ownership interests in CTPL and Cheniere Pipeline GP Interests,
LLC (collectively, “the Creole Trail Pipeline Business”) described in our Note 3—Summary of Significant Accounting Policies
of our Notes to Consolidated Financial Statements.
Contributions to Creole Trail Pipeline Business from Cheniere, net
Contributions to Creole Trail Pipeline Business from Cheniere, net relate to equity contributions provided by Cheniere to
the entities owning the Creole Trail Pipeline that we purchased in May 2013. The acquisition has been accounted for as a transfer
of net assets between entities under common control. During the year ended December 31, 2013, Cheniere contributed $20.9
million to the Creole Trail Pipeline entities that we acquired.
48
Investment in Restricted Cash
In the year ended December 31, 2015, we invested $2,690.4 million in restricted cash primarily related to the net proceeds
from the 2025 SPL Senior Notes and borrowings under the 2015 SPL Credit Facilities and SPL Working Capital Facility, net of
deferred financing costs. In the year ended December 31, 2014, we invested $2,303.8 million in restricted cash primarily related
to the net proceeds from the notes issued by SPL during the year. In the year ended December 31, 2013, we invested $4,174.0
million in restricted cash primarily related to the net proceeds from the notes issued by SPL during the year and from the sale of
common units by Cheniere Partners as described above.
Other
During the years ended December 31, 2015, 2014 and 2013, we used $62.4 million, $38.9 million and $13.9 million,
respectively, of cash in other activities primarily as a result of payments made to a municipal water district for water system
enhancements that will increase potable water supply to our Sabine Pass LNG terminal and investments made in unconsolidated
entities.
Cash Distributions to Unitholders
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash
(as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any
reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus.
The following provides a summary of distributions paid by us during the years ended December 31, 2015 and 2014:
Date Paid
October 23, 2015
August 14, 2015
May 15, 2015
February 13, 2015
Period Covered by Distribution
July 1 - September 30, 2015
April 1 - June 30, 2015
January 1 - March 31, 2015
October 1 - December 31, 2014
Distribution
Per
Common
Unit
$ 0.425
0.425
0.425
0.425
November 14, 2014
August 14, 2014
May 15, 2014
February 14, 2014
July 1 - September 30, 2014
April 1 - June 30, 2014
January 1 - March 31, 2014
October 1 - December 31, 2013
$ 0.425
0.425
0.425
0.425
Total Distribution (in thousands)
Distribution
Per
Subordinated
Unit
Common
Units
Class B
Units
Subordinated
Units
General
Partner
Units
$
$
— $ 24,260
— 24,260
— 24,259
— 24,259
$ — $
—
—
—
— $ 24,259
— 24,259
— 24,259
— 24,258
$ — $
—
—
—
— $
—
—
—
— $
—
—
—
495
495
495
495
495
495
495
495
On January 22, 2016, we declared a $0.425 distribution per common unit and the related distribution to our general partner
was paid on February 12, 2016 to owners of record as of February 1, 2016 for the period from October 1, 2015 to December 31,
2015.
The subordinated units will receive distributions only to the extent we have available cash above the initial quarterly
distributions requirement for our common unitholders and general partner along with certain reserves. Such available cash could
be generated through new business development or fees received from Cheniere Marketing under an amended and restated variable
capacity rights agreement pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected
gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. The ending
of the subordination period and conversion of the subordinated units into common units will depend upon future business
development.
In 2012 and 2013, we issued a new class of equity interests representing limited partner interests in us (“Class B units”), in
connection with the development of the Liquefaction Project. The Class B units are not entitled to cash distributions, except in
the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially
all of our assets. The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under
specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On
a quarterly basis beginning on the initial purchase date of the Class B units, the conversion value of the Class B units increases at
a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The
49
accreted conversion ratio of the class B units owned by Cheniere and Blackstone CQP Holdco was 1.62 and 1.59, respectively, as
of December 31, 2015. We expect the Class B units to mandatorily convert into common units within 90 days of the substantial
completion date of Train 3 of the Liquefaction Project, which we currently expect to occur before April 30, 2017. If the Class B
units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into
common units at that time. The holders of Class B units have a preference over the holders of the subordinated units in the event
of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all
of our assets.
Contractual Obligations
We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes
certain contractual obligations (in thousands) in place as of December 31, 2015:
Construction obligations (2)
Purchase obligations (3)
Debt (4)
Interest payments (4)
Operating lease obligations (5)
Obligations to affiliates (6)
Other obligations
Total
Payments Due By Period (1)
$
Total
2,701,566
1,522,360
11,845,500
4,109,954
40,976
171,106
2,454
$ 20,393,916
$
$
2016
1,543,647
375,164
1,680,500
699,912
2,620
20,205
2,454
4,324,502
$
$
2017 - 2018
2019 - 2020
Thereafter
1,070,003
515,814
400,000
1,142,682
4,439
36,955
—
3,169,893
$
$
87,916
372,110
1,265,000
1,132,230
4,253
36,955
—
2,898,464
$
—
259,272
8,500,000
1,135,130
29,664
76,991
—
$ 10,001,057
(1)
(2)
(3)
(4)
(5)
(6)
Agreements in force as of December 31, 2015 that have terms dependent on project milestone dates are based on the
estimated dates as of December 31, 2015.
Construction obligations primarily relate to the EPC contracts for Trains 1 through 5 of the Liquefaction Project. The
estimated remaining costs pursuant to our EPC contracts as of December 31, 2015 is included. A discussion of these
obligations can be found at Note 13—Commitments and Contingencies of our Notes to Consolidated Financial Statements.
Purchase obligations consists of contracts for which conditions precedent have been met, and primarily relate to natural
gas supply, transportation and storage services, as well as maintenance contracts for the Liquefaction Project. As project
milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly.
Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2015. See Note 10—
Debt of our Notes to Consolidated Financial Statements.
Operating lease obligations primarily relate to land sites related to the Sabine Pass LNG terminal. A discussion of these
obligations can be found in Note 12—Leases of our Notes to Consolidated Financial Statements.
Obligations arising through intercompany service agreements include only fixed fees and do not include variable fees.
A discussion of these obligations can be found in Note 11—Related Party Transactions of our Notes to Consolidated
Financial Statements.
In addition, in the ordinary course of business, we maintain letters of credit and have certain cash restricted in support of
certain performance obligations of our subsidiaries. As of December 31, 2015, we had $135.2 million aggregate amount of issued
Letters of Credit under the SPL Working Capital Facility and $288.3 million of current and non-current restricted cash. For more
information, see Note 4—Restricted Cash of our Notes to Consolidated Financial Statements.
50
Results of Operations
2015 vs. 2014
Our consolidated net loss decreased $91.1 million, from $410.0 million of consolidated net loss in the year ended December
31, 2014, to $318.9 million of consolidated net loss in the year ended December 31, 2015. The decrease in consolidated net loss
was primarily a result of decreased derivative loss, net, decreased operating and maintenance expense and decreased loss on early
extinguishment of debt, partially offset by increased general and administrative expense (“G&A Expense”) (including affiliate
amounts).
Derivative loss, net decreased $77.7 million, from $119.4 million in the year ended December 31, 2014, to $41.7 million
in the year ended December 31, 2015. The higher derivative loss recognized during the year ended December 31, 2014 was
attributable to a decrease in long-term LIBOR during that period, whereas the movement in long-term LIBOR had a minimal effect
on derivative loss for the year ended December 31, 2015 as a result of a lower notional amount of interest rate derivatives. Instead
of movement in long-term LIBOR rates, the $41.7 million derivative loss recognized during the year ended December 31, 2015
was primarily attributable to the loss recognized in March 2015 upon the termination of interest rate swaps associated with
approximately $1.8 billion of commitments that were terminated under the 2013 SPL Credit Facilities.
Operating and maintenance expense decreased $31.9 million in the year ended December 31, 2015, as compared to the
year ended December 31, 2014, due to a $32.2 million increase in fair value for our natural gas purchase agreements recorded
during the third quarter of 2015, which we recognized following the completion and placement into service of certain modifications
to the Creole Trail Pipeline and the resulting development of a market for physical gas delivery at locations specified in a portion
of our natural gas purchase agreements. Excluding this amount, operating and maintenance expense would have been $63.1
million during the year ended December 31, 2015, which is comparable to $62.8 million incurred during the year ended December
31, 2014.
Loss on early extinguishment of debt decreased $18.0 million, from $114.3 million in the year ended December 31, 2014,
to $96.3 million in the year ended December 31, 2015. Loss on early extinguishment of debt during the year ended December 31,
2015 was attributable to the write-off of debt issuance costs and deferred commitment fees in connection with the termination of
approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities in March 2015 and the replacement of the 2013
SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015. Loss on early extinguishment of debt during the year ended
December 31, 2014 was attributable to the write-off of debt issuance costs in connection with the early extinguishment of $2.1
billion of commitments under the 2013 SPL Credit Facilities in May 2014.
Partially offsetting the above decreases in expenses, G&A Expense (including affiliate amounts) increased $22.2 million
in the year ended December 31, 2015, as compared to the year ended December 31, 2014, primarily due to costs of services
provided by Cheniere pursuant to an information technology services agreement.
There was no significant change to interest expense, net of amounts capitalized in the year ended December 31, 2015, as
compared to the year ended December 31, 2014, primarily as a result of our capitalization of interest costs incurred which were
directly related to the construction of the first five Trains of the Liquefaction Project. For the years ended December 31, 2015 and
2014, we incurred $707.7 million and $580.2 million of total interest cost, respectively, of which we capitalized and deferred
$523.1 million and $403.2 million, respectively.
2014 vs. 2013
Our consolidated net loss increased $151.9 million, from $258.1 million in the year ended December 31, 2013, to $410.0
million in the year ended December 31, 2014. The increase in net loss was primarily a result of decreased derivative gain, net,
which was partially offset by decreased general and administrative expense—affiliate and decreased loss on early extinguishment
of debt.
Derivative gain, net decreased $202.2 million, from $82.8 million gain in the year ended December 31, 2013 to $119.4
million loss in the year ended December 31, 2014, primarily as a result of a decrease in long-term LIBOR during the year ended
December 31, 2014, as compared to an increase in long-term LIBOR during the year ended December 31, 2013, and the early
settlement of interest rate swaps in connection with the early extinguishment of a portion of the 2013 SPL Credit Facilities in May
2014.
51
General and administrative expense—affiliate decreased $28.5 million in the year ended December 31, 2014, as compared
to the year ended December 31, 2013, primarily as a result of decreased costs incurred to manage the construction of Trains 1
through 4 of the Liquefaction Project, which resulted from a management services agreement in which we are required to pay a
monthly fee based upon the capital expenditures incurred in the previous month for Trains 1 through 4 until substantial completion
of each Train. Loss on early extinguishment of debt decreased $17.2 million in the year ended December 31, 2014, as compared
to the year ended December 31, 2013, due to the write-off of debt issuance costs in connection with the early extinguishment
of $2.1 billion of commitments under the 2013 SPL Credit Facilities in May 2014, as compared to the write-off of debt issuance
costs and deferred commitment fees in connection with the early extinguishment of a portion of the commitments under the 2012
SPL Credit Facility in April 2013 and under the 2013 SPL Credit Facilities in November 2013.
There was no significant change to interest expense, net of amounts capitalized in the year ended December 31, 2014, as
compared to the year ended December 31, 2013, primarily as a result of our capitalization of interest costs incurred which were
directly related to the construction of the first four Trains of the Liquefaction Project. For the years ended December 31, 2014
and 2013, we incurred $580.2 million and $414.0 million of total interest cost, respectively, of which we capitalized and deferred
$403.2 million and $235.6 million, respectively.
Off-Balance Sheet Arrangements
As of December 31, 2015, we had no transactions that met the definition of off-balance sheet arrangements that may have
a current or future material effect on our consolidated financial position or operating results.
Summary of Critical Accounting Estimates
The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain
estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes.
Management evaluates its estimates and related assumptions regularly, including those related to the value of properties, plant and
equipment, asset retirement obligations (“AROs”) and fair values. Changes in facts and circumstances or additional information
may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its
most critical accounting estimates that involve significant judgment.
Fair Value
When necessary or required by GAAP, we estimate fair value for derivatives, long-lived assets for impairment testing, initial
measurements of AROs and financial instruments that require fair value disclosure, including debt. When we are required to
measure fair value and there is not a market-observable price for the asset or liability or for a similar asset or liability, we use the
cost, income or market valuation approaches depending on the quality of information available to support management’s
assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income
approach is based on management’s best assumptions regarding expectations of projected cash flows, and discounts the expected
cash flows using a commensurate risk-adjusted discount rate. The market approach is based on management’s best assumptions
regarding prices and other relevant information from market transactions involving comparable assets. Such evaluations involve
significant judgment and the results are based on expected future events or conditions, such as sales prices, estimates of future
LNG production, development, construction and operating costs and the timing thereof, future net cash flows, economic and
regulatory climates and other factors, most of which are often outside of management’s control. However, assumptions used reflect
a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business
plans and investment decisions.
Derivative Instruments
All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes
in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between
willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the
quoted market price of derivatives with similar characteristics or determined through industry-standard valuation techniques.
Our derivative instruments consist of financial natural gas derivative contracts transacted in an over-the-counter market,
index-based physical natural gas contracts and interest rate swaps. Valuation of our financial natural gas derivative contracts is
52
determined using observable commodity price curves and other relevant data. Valuation of our index-based physical natural gas
contracts is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace,
market transactions and other relevant data. We value our interest rate swaps using observable inputs including interest rate curves,
risk adjusted discount rates, credit spreads and other relevant data.
Gains and losses on derivative instruments are recognized currently in earnings. The ultimate fair value of our derivative
instruments is uncertain, and we believe that it is reasonably possible that a change in the estimated fair value could occur in the
near future as commodity prices and interest rates change.
Impairment of Long-Lived Assets
A long-lived asset, including an intangible asset, is evaluated for potential impairment whenever events or changes in
circumstances indicate that its carrying value may not be recoverable. Recoverability generally is determined by comparing the
carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not
recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated
fair value. We use a variety of fair value measurement techniques when market information for the same or similar assets does
not exist. Projections of future operating results and cash flows may vary significantly from results. Management reviews its
estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and
commodity price environment.
Recent Accounting Standards
For descriptions of recently issued accounting standards, see Note 16—Recent Accounting Standards of our Notes to
Consolidated Financial Statements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Cash Investments
We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation
of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance
Sheets.
Marketing and Trading Commodity Price Risk
We have entered into commodity derivatives consisting of natural gas purchase agreements to secure natural gas feedstock
for the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction
Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the basis price for natural
gas for each delivery location. As of December 31, 2015, we estimated the fair value of the Liquefaction Supply Derivatives to
be $32.5 million. Based on actual derivative contractual volumes, a 10% increase or decrease in the underlying basis price would
have resulted in a change in the fair value of the Liquefaction Supply Derivatives of $0.9 million as of December 31, 2015,
compared to $0.4 million as of December 31, 2014. The increase in the effect of change in the underlying basis price was due to
a $32.2 million increase in fair value for our natural gas purchase agreements recorded during the third quarter of 2015, which we
recognized following the completion and placement into service of certain modifications to the Creole Trail Pipeline and the
resulting development of a market for physical gas delivery at locations specified in a portion of our natural gas purchase agreements.
See Note 7—Derivative Instruments for additional details about our derivative instruments.
53
Interest Rate Risk
We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments
under the 2015 SPL Credit Facilities (“Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest
Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across
the full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates would have resulted in a change in the fair
value of our Interest Rate Derivatives of $3.1 million as of December 31, 2015, compared to $16.5 million as of December 31,
2014. The decrease in the effect of change in interest rates was due to lower notional amounts of Interest Rate Derivatives
outstanding and a decrease in the forward 1-month LIBOR curve during the year ended December 31, 2015.
54
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE ENERGY PARTNERS, L.P.
Management's Report to the Unitholders of Cheniere Energy Partners, L.P.
Reports of Independent Registered Public Accounting Firm—KPMG LLP
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Loss
Consolidated Statements of Partners’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data
56
57
59
60
61
62
63
64
65
93
55
MANAGEMENT’S REPORT TO THE UNITHOLDERS OF CHENIERE ENERGY PARTNERS, L.P.
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for
Cheniere Energy Partners, L.P. (“Cheniere Partners”) and its subsidiaries. In order to evaluate the effectiveness of internal control
over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including
testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations
of the Treadway Commission (“COSO”). Cheniere Partners’ system of internal control over financial reporting is designed to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent
limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be
effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
Based on our assessment, we have concluded that Cheniere Partners maintained effective internal control over financial
reporting as of December 31, 2015, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.
Cheniere Partners’ independent registered public accounting firm, KPMG LLP, has issued an audit report on Cheniere
Partners’ internal control over financial reporting as of December 31, 2015, which is contained in this Form 10-K.
Management’s Certifications
The certifications of the Chief Executive Officer and Chief Financial Officer of Cheniere Partners’ general partner required
by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere Partners’ Form 10-K.
Cheniere Energy Partners, L.P.
By: Cheniere Energy Partners GP, LLC,
Its general partner
By:
/s/ Neal A. Shear
Neal A. Shear
Interim Chief Executive Officer
(Principal Executive Officer)
By:
/s/ Michael J. Wortley
Michael J. Wortley
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
56
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Cheniere Energy Partners GP, LLC, and
Unitholders of Cheniere Energy Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Cheniere Energy Partners, L.P. and subsidiaries (the
Partnership) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive loss, partners’
equity, and cash flows for each of the years in the two-year period ended December 31, 2015. In connection with our audits of
the consolidated financial statements, we also have audited financial statement schedule I for each of the years in the two-year
period ended December 31, 2015. These consolidated financial statements and financial statement schedule are the responsibility
of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of Cheniere Energy Partners, L.P. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations
and their cash flows for each of the years in the two-year period ended December 31, 2015, in conformity with U.S. generally
accepted accounting principles. Also in our opinion, the related financial statement schedule for each of the years in the two-year
period ended December 31, 2015, when considered in relation to the basic consolidated financial statements taken as a whole,
present fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
Cheniere Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2015, based on criteria established
in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated February 18, 2016, expressed an unqualified opinion on the effectiveness of the
Partnership’s internal control over financial reporting.
Houston, Texas
February 18, 2016
/s/ KPMG LLP
KPMG LLP
57
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Cheniere Energy Partners GP, LLC, and
Unitholders of Cheniere Energy Partners, L.P.:
We have audited Cheniere Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2015, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO). Cheniere Energy Partners, L.P.’s management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in
the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion
on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control
over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Cheniere Energy Partners, L.P. maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Cheniere Energy Partners, L.P. and subsidiaries as of December 31, 2015 and 2014, and the related
consolidated statements of operations, comprehensive loss, partners’ equity, and cash flows for each of the years in the two-year
period ended December 31, 2015, and our report dated February 18, 2016 expressed an unqualified opinion on those consolidated
financial statements.
Houston, Texas
February 18, 2016
/s/ KPMG LLP
KPMG LLP
58
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Cheniere Energy Partners GP, LLC, and
Unitholders of Cheniere Energy Partners, L.P.
We have audited the accompanying consolidated statements of operations, comprehensive loss, partners’ equity, and cash
flows of Cheniere Energy Partners, L.P. and subsidiaries for the year ended December 31, 2013. Our audits also included the
financial statement schedule for the year ended December 31, 2013 listed in the Index at Item 15(a). These financial statements
and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial
statements and schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of
operations and cash flows of Cheniere Energy Partners, L.P. and subsidiaries for the year ended December 31, 2013, in conformity
with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered
in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ ERNST & YOUNG LLP
Ernst & Young LLP
Houston, Texas
February 21, 2014
59
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
ASSETS
Current assets
Cash and cash equivalents
Restricted cash
Accounts and interest receivable
Accounts receivable—affiliate
Advances to affiliate
Inventory
Other current assets
Other current assets—affiliate
Total current assets
Non-current restricted cash
Property, plant and equipment, net
Debt issuance costs, net
Non-current derivative assets
Other non-current assets
Other non-current assets—affiliate
Total assets
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable
Accrued liabilities
Current debt, net
Due to affiliates
Deferred revenue
Deferred revenue—affiliate
Derivative liabilities
Other current liabilities
Total current liabilities
Long-term debt, net
Non-current deferred revenue
Other non-current liabilities
Other non-current liabilities—affiliate
Commitments and contingencies (see Note 13)
Partners’ equity
December 31,
2015
2014
$
$
146,221
274,557
742
1,271
39,836
16,667
11,828
2,353
493,475
248,830
195,702
333
3,651
27,323
7,786
2,895
—
486,520
13,650
11,931,602
295,265
30,304
200,013
32,018
$ 12,996,327
544,465
8,978,356
241,909
11,744
124,521
—
$ 10,387,515
$
$
16,407
224,292
1,676,197
115,123
26,669
717
6,430
—
2,065,835
10,178,681
9,500
3,059
26,321
8,598
136,578
—
18,952
26,655
708
23,247
18
214,756
8,991,333
13,500
2,452
34,745
Common unitholders’ interest (57.1 million units issued and outstanding at December
31, 2015 and 2014)
Class B unitholders’ interest (145.3 million units issued and outstanding at December 31,
2015 and 2014)
Subordinated unitholders’ interest (135.4 million units issued and outstanding at
December 31, 2015 and 2014)
General partner’s interest (2% interest with 6.9 million units issued and outstanding at
December 31, 2015 and 2014)
Total partners’ equity
Total liabilities and partners’ equity
305,747
495,597
(37,429)
(38,216)
428,035
648,414
16,578
712,931
$ 12,996,327
24,934
1,130,729
$ 10,387,515
The accompanying notes are an integral part of these consolidated financial statements.
60
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
Revenues
Revenues
Revenues—affiliate
Total revenues
Operating costs and expenses
Operating and maintenance expense
Operating and maintenance expense—affiliate
Depreciation and amortization expense
Development expense
Development expense—affiliate
General and administrative expense
General and administrative expense—affiliate
Total operating costs and expenses
Income (loss) from operations
Other income (expense)
Interest expense, net of amounts capitalized
Loss on early extinguishment of debt
Derivative gain (loss), net
Other income
Total other expense
Net loss
Net loss attributable to the Creole Trail Pipeline Business
Net loss attributable to partners
Basic and diluted net income (loss) per common unit
Year Ended December 31,
2014
2013
2015
$
$
265,637
4,391
270,028
$
265,740
2,958
268,698
265,251
2,940
268,191
30,940
29,379
65,704
2,850
722
15,079
122,312
266,986
62,819
21,115
58,601
9,319
1,153
13,807
101,369
268,183
59,300
29,304
57,486
11,322
1,402
11,570
129,836
300,220
3,042
515
(32,029)
(184,600)
(96,273)
(41,722)
662
(321,933)
(177,032)
(114,335)
(119,401)
217
(410,551)
(178,400)
(131,576)
82,791
1,097
(226,088)
$
(318,891) $
(410,036) $
(258,117)
—
—
(318,891) $
(410,036) $
(18,150)
(239,967)
(0.43) $
(0.89) $
(0.03)
$
$
Weighted average number of common units outstanding used for basic and
diluted net income (loss) per common unit calculation
57,081
57,079
54,235
The accompanying notes are an integral part of these consolidated financial statements.
61
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)
Net loss
Other comprehensive income (loss)
Loss on settlements of interest rate cash flow hedges
retained in other comprehensive income
Change in fair value of interest rate cash flow hedges
Losses reclassified into earnings as a result of discontinuance of cash flow
hedge accounting
Total other comprehensive income (loss)
Comprehensive loss
Year Ended December 31,
2014
$ (318,891) $ (410,036) $ (258,117)
2015
2013
—
—
—
—
(30)
21,297
5,973
27,240
$ (318,891) $ (410,036) $ (230,877)
—
—
—
—
The accompanying notes are an integral part of these consolidated financial statements.
62
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6
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Cash flows from operating activities
Net loss
Adjustments to reconcile net loss to net cash provided by operating
activities:
Non-cash LNG inventory write-downs
Depreciation and amortization expense
Amortization of debt issuance costs and discount
Loss on early extinguishment of debt
Total (gains) losses on derivatives, net
Net cash used for settlement of derivative instruments
Other
Changes in restricted cash for certain operating activities
Changes in operating assets and liabilities:
Accounts and interest receivable
Accounts receivable—affiliate
Advances to affiliate
Inventory
Accounts payable and accrued liabilities
Due to affiliates
Deferred revenue
Other, net
Other, net—affiliate
Net cash provided by operating activities
Year Ended December 31,
2014
2013
2015
$
(318,891) $
(410,036) $
(258,117)
17,537
65,704
12,174
96,273
7,154
(41,398)
85
176,847
259
1,248
(12,513)
(25,037)
(996)
14,882
(3,986)
(12,010)
28,416
5,748
24,461
58,601
14,264
114,335
117,701
(21,581)
15
148,972
(293)
(503)
(12,586)
(19,008)
3,949
(15,842)
(3,938)
(4,236)
17,653
11,928
26,900
57,486
14,948
131,576
(84,296)
579
—
171,345
4
(1,083)
(9,281)
(30,903)
(2,384)
26,091
(3,947)
(7,632)
4,378
35,664
Cash flows from investing activities
Property, plant and equipment, net
Use of restricted cash for the acquisition of property, plant and equipment
Purchase of Creole Trail Pipeline Business, net
Other
Net cash used in investing activities
(2,912,080)
2,965,477
—
(62,448)
(9,051)
(2,645,553)
2,669,332
—
(38,880)
(15,101)
(3,120,643)
3,119,632
(313,892)
(13,897)
(328,800)
Cash flows from financing activities
Proceeds from issuances of debt
Repayments of debt
Debt issuance and deferred financing costs
Investment in restricted cash
Proceeds from sale of partnership common and general partner units
Contributions to Creole Trail Pipeline Business from Cheniere, net
Distributions to owners
Net cash provided by (used in) financing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents—beginning of period
Cash and cash equivalents—end of period
2,860,000
—
(169,924)
(2,690,364)
—
—
(99,018)
(99,306)
2,584,500
(177,000)
(103,787)
(2,303,763)
—
—
(98,979)
(99,029)
4,504,478
(100,000)
(311,050)
(4,173,959)
375,897
20,896
(91,386)
224,876
(102,609)
248,830
146,221
$
(102,202)
351,032
248,830
$
(68,260)
419,292
351,032
$
The accompanying notes are an integral part of these consolidated financial statements.
64
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
We are a publicly traded Delaware limited partnership (NYSE MKT: CQP) formed by Cheniere. Through our wholly owned
subsidiary, SPLNG, we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine-Neches
Waterway less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG
storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to
266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We are developing and constructing
natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification
facilities through our wholly owned subsidiary, SPL. We are constructing five Trains and developing a sixth Train, each of which
is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. We also own a 94-mile pipeline that
interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through our
wholly owned subsidiary, CTPL.
As of December 31, 2015, Cheniere owned 100% of our general partner interest and 80.1% of Cheniere Holdings, which
owned 12.0 million of our common units, 45.3 million of our Class B units and 135.4 million of our subordinated units.
NOTE 2—UNITHOLDERS’ EQUITY
The common units, Class B units and subordinated units represent limited partner interests in us. The holders of the units
are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our
partnership agreement. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of
our available cash (as defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a
quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from
operating surplus as defined in the partnership agreement.
The holders of common units have the right to receive initial quarterly distributions of $0.425 per common unit, plus any
arrearages thereon, before any distribution is made to the holders of the subordinated units. The holders of subordinated units will
receive distributions only to the extent we have available cash above the initial quarterly distribution requirement for our common
unitholders and general partner and certain reserves. Subordinated units will convert into common units on a one-for-one basis
when we meet financial tests specified in the partnership agreement. Although common and subordinated unitholders are not
obligated to fund losses of the Partnership, their capital accounts, which would be considered in allocating the net assets of the
Partnership were it to be liquidated, continue to share in losses.
The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds
incentive distribution rights, which allow the general partner to receive a higher percentage of quarterly distributions of available
cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met. The
higher percentages range from 15% to 50%.
During 2012, Blackstone CQP Holdco and Cheniere completed their purchases of a new class of equity interests representing
limited partner interests in us (“Class B units”) for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds
from the financings were used to fund a portion of the costs of developing, constructing and placing into service the first two Trains
of the Liquefaction Project. In May 2013, Cheniere purchased an additional 12.0 million Class B units for consideration of $180.0
million in connection with our acquisition of CTPL and Cheniere Pipeline GP Interests, LLC. In 2013, Cheniere formed Cheniere
Holdings to hold its limited partner interests in us. The Class B units are subject to conversion, mandatorily or at the option of
the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion
value of the Class B units. The Class B units are not entitled to cash distributions except in the event of our liquidation or a merger,
consolidation or other combination of us with another person or the sale of all or substantially all of our assets. On a quarterly
basis beginning on the date of the initial purchase date of the Class B units, the conversion value of the Class B units increases at
a compounded rate of 3.5% per quarter, subject to additional upward adjustment for certain equity and debt financings. The
accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco was 1.62 and 1.59,
respectively, as of December 31, 2015. We expect the Class B units to mandatorily convert into common units within 90 days of
the substantial completion date of Train 3 of the Liquefaction Project, which we currently expect to occur before April 30, 2017.
If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the
Class B units into common units at that time.
65
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Consolidated Financial Statements were prepared in accordance with GAAP. The Consolidated Financial Statements
include the accounts of Cheniere Energy Partners, L.P. and its majority owned subsidiaries. All significant intercompany accounts
and transactions have been eliminated in consolidation.
In May 2013, we completed the acquisition of Cheniere’s ownership interests in CTPL and Cheniere Pipeline GP Interests,
LLC (collectively, “the Creole Trail Pipeline Business”), thereby providing us with ownership of a 94-mile pipeline interconnecting
the Sabine Pass LNG terminal with a large number of interstate pipelines. We acquired the Creole Trail Pipeline Business for
$480.0 million and reimbursed Cheniere $13.9 million for certain expenditures incurred prior to the closing date. Concurrent with
the Creole Trail Pipeline Business acquisition closing, we issued 12.0 million Class B units to Cheniere for aggregate consideration
of $180.0 million pursuant to a unit purchase agreement with Cheniere Class B Units Holdings, LLC, a wholly owned subsidiary
of Cheniere. As a result of the two transactions, we paid Cheniere net cash of $313.9 million.
These Consolidated Financial Statements include our accounts and the assets, liabilities and operations of the Creole Trail
Pipeline Business. The effect of including the prior results of the Creole Trail Pipeline Business is reported as net loss attributable
to Creole Trail Pipeline Business in our Consolidated Statement of Operations and Creole Trail Pipeline Business equity in our
Consolidated Balance Sheets and Consolidated Statements of Partners’ Equity. This purchase has been accounted for as a transfer
of net assets between entities under common control.
We recognize transfers of net assets between entities under common control at Cheniere’s historical basis in the net assets
sold. In addition, transfers of net assets between entities under common control are accounted for as if the transfer occurred at the
beginning of the period, and prior years are retroactively adjusted to furnish comparative information. The difference between
the purchase price and Cheniere’s basis in the net assets sold, if any, is recognized as an adjustment to partners’ equity.
Subsequent to the Creole Trail Pipeline Business acquisition, we control CTPL’s operating and financial decisions and
policies and have consolidated CTPL in our Financial Statements. Our Consolidated Financial Statements and all other financial
information included in this report assume that our acquisition of the Creole Trail Pipeline Business from Cheniere had occurred
at the date when the Creole Trail Pipeline Business met the accounting requirements for entities under common control (the date
of our inception since both we and the Creole Trail Pipeline Business were formed by Cheniere). Net income (loss) attributable
to the Creole Trail Pipeline Business for periods prior to the acquisition is not allocated to the common units for purposes of
calculating net income (loss) per common unit. See Note 15—Net Income (Loss) Per Common Unit for an adjusted net loss per
common unit that includes pre-acquisition date net losses of the Creole Trail Pipeline Business.
Certain reclassifications have been made to conform prior period information to the current presentation. The
reclassifications had no effect on our overall consolidated financial position, operating results or cash flows.
Use of Estimates
The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain
estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes.
Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and
equipment, collectability of accounts receivable, derivative instruments, asset retirement obligations (“AROs”) and fair value
measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results
may differ from these estimates.
Fair Value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair
value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are
inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy
Level 3 inputs are inputs that are not observable in the market.
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In determining fair value, we use observable market data when available, or models that incorporate observable market
data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market
participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of
unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for commodity derivatives and interest rate derivatives as disclosed in
Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and
accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated
amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the
difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note
10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt
instruments. Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a
business combination, intangible assets and AROs.
Revenue Recognition
LNG regasification capacity reservation fees are recognized as revenue over the term of the respective TUAs. Advance
capacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer’s regasification
capacity reservation fees payable under its TUA. Under each of these TUAs, SPLNG is entitled to retain 2% of LNG delivered
for each customer’s account at the Sabine Pass LNG terminal, which is recognized as revenues as SPLNG performs the services
set forth in each customer’s TUA.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash
Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately
from cash and cash equivalents on our Consolidated Balance Sheets.
Amounts that are designated as restricted cash are contractually restricted as to usage or withdrawal and will not become
available to us as cash and cash equivalents. For these amounts, we have presented increases and decreases separately from
increases and decreases in cash and cash equivalents in our Consolidated Statements of Cash Flows. These amounts that represent
non-cash transactions within our Consolidated Statements of Cash Flows present the effect of sources and uses of restricted cash
as they relate to the changes to assets and liabilities in our Consolidated Balance Sheets. Restricted cash is presented on a gross
basis within each of those categories so as to reconcile the change in non-cash activity that occurs on the balance sheet from period
to period.
Inventory
Inventory is recorded at weighted average cost and is subject to lower of cost or market (“LCM”) adjustments at the end
of each period. Our LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the
regasification facilities at the Sabine Pass LNG terminal that are recorded in operating and maintenance expense on our Consolidated
Statements of Operations. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price
recoveries occur on the same inventory in the same fiscal year. These recoveries are recognized as gains in later interim periods
with such gains not exceeding previously recognized losses.
During the years ended December 31, 2015, 2014 and 2013, we recognized $17.5 million, $24.5 million and $26.9 million,
respectively, as operating and maintenance expense as a result of LCM adjustments to our LNG inventory.
Accounting for LNG Activities
Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the
following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has
committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as
67
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing
necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals and
related pipelines.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include:
land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other
non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the
costs are expensed.
We capitalize interest and other related debt costs during the construction period of our LNG terminal and related pipeline.
Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated
useful life of the asset.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments
that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs and general and administrative
activities are charged to expense as incurred. Interest costs incurred on debt obtained for the construction of property, plant and
equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We
depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of
property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains
or losses are recorded in other operating costs and expenses.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated
that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for
which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of
assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected
undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss
is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We have recorded no impairments
related to property, plant and equipment for 2015, 2014 or 2013.
Regulated Natural Gas Pipelines
The Creole Trail Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the
Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those
costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are
expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the
amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated
rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory
assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable
to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery.
These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities.
We periodically evaluate their applicability under GAAP and consider factors such as regulatory changes and the effect of
competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market
basis less than cost and write off the associated regulatory assets and liabilities.
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
Items that may influence our assessment are:
inability to recover cost increases due to rate caps and rate case moratoriums;
inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and
the FERC proceedings;
excess capacity;
increased competition and discounting in the markets we serve; and
impacts of ongoing regulatory initiatives in the natural gas industry.
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”).
The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC
represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is
capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover
AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price and interest rate risk.
Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending
on the derivative position and the expected timing of settlement, unless they satisfy criteria and we elect the normal purchases and
sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net
basis.
Changes in the fair value of our derivative instruments are recorded in current earnings, unless we elect to apply hedge
accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any
derivative instruments designated as cash flow hedges as of December 31, 2015 and 2014.
In the past, we elected cash flow hedge accounting for derivatives that we used to hedge the exposure to volatility in floating-
rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge
was effective, were recognized in accumulated other comprehensive loss on our Consolidated Balance Sheets. We reclassified
gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Consolidated Statements
of Operations as the hedged item was recognized. Any change in the fair value resulting from ineffectiveness was recognized
immediately as derivative gain (loss) on our Consolidated Statements of Operations. We used regression analysis to determine
whether we expected a derivative to be highly effective as a cash flow hedge, prior to electing hedge accounting and also to
determine whether all derivatives designated as cash flow hedges had been effective. We performed these effectiveness tests prior
to designation for all new hedges and on a quarterly basis for all existing hedges. We calculated the actual amount of ineffectiveness
on our cash flow hedges using the “dollar offset” method, which compared changes in the expected cash flows of the hedged
transaction to changes in the value of expected cash flows from the hedge. We discontinued hedge accounting when our effectiveness
tests indicated that a derivative was no longer highly effective as a hedge; when the derivative expired or was sold, terminated or
exercised; when the hedged item matured, was sold or repaid; or when we determined that the occurrence of the hedged forecasted
transaction was not probable. When we discontinued hedge accounting but continued to hold the derivative, prospective changes
in fair value of the derivative instrument were recorded in income. Once we concluded that the hedged forecasted transaction
became probable of not occurring, the amount remaining in accumulated other comprehensive loss pertaining to the previously
designated derivatives was reclassified out of accumulated other comprehensive loss and into income.
See Note 7—Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash
equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally
insured levels. We have not incurred losses related to these balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to
meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject
to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral
deposited for such contracts is recorded as other current asset. Our interest rate derivative instruments are placed with investment
grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing
basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not
sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties
not perform, we may not realize the benefit of some of our derivative instruments.
SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass
LNG terminal. SPLNG is dependent on the respective counterparties’ creditworthiness and their willingness to perform under
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
their respective TUAs. SPLNG has mitigated this credit risk by securing TUAs for a significant portion of its regasification
capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.
SPL has entered into six fixed price 20-year SPAs with six unaffiliated third parties. SPL is dependent on the respective
counterparties’ creditworthiness and their willingness to perform under their respective SPAs.
Debt
Our debt consists of current and long-term secured debt securities and credit facilities with banks and other lenders. Debt
issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Debt is recorded on our Balance Sheet at par value adjusted for unamortized discount or premium. Discounts, premiums
and costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net using
the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment
of debt on our Consolidated Statements of Operations.
Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are
recorded as debt issuance costs on our Consolidated Balance Sheets and are being amortized to interest expense or property, plant
and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain
fees are written off to loss on early extinguishment of debt.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition,
construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement
are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized
in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to
the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the
asset. Our recognition of AROs is described below.
Currently, the Sabine Pass LNG terminal is our only constructed and operating LNG terminal. Based on the real property
lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG
terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at
the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to
surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero.
Therefore, we have not recorded an ARO associated with the Sabine Pass LNG terminal.
Currently, the Creole Trail Pipeline is our only constructed and operating natural gas pipeline. We believe that it is not
feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In
addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. Therefore,
we have concluded that due to advanced technology associated with current natural gas pipelines and our intent to operate the
Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States, we have not recorded an ARO
associated with the Creole Trail Pipeline.
Income Taxes
We are not subject to federal, state or foreign income taxes, as the partners are taxed individually on their allocable share
of taxable income. At December 31, 2015, the tax basis of our assets and liabilities was $212.8 million less than the reported
amounts of our assets and liabilities. See Note 11—Related Party Transactions for details about income taxes under our tax sharing
agreements.
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Business Segment
Our LNG terminal business is our only operating business segment in which separate financial information is produced and
evaluated by our chief operating decision maker in deciding how to allocate resources. Our LNG terminal business segment
consists of the operational regasification and pipeline facilities at the Sabine Pass LNG terminal and the adjacent Liquefaction
Project. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately
16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters, vaporizers with
regasification capacity of approximately 4.0 Bcf/d and pipeline facilities (including the Creole Trail Pipeline) interconnecting the
Sabine Pass LNG terminal with a number of large interstate pipelines. The Liquefaction Project is adjacent to the existing
regasification facilities at the Sabine Pass LNG terminal.
NOTE 4—RESTRICTED CASH
Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately
from cash and cash equivalents on our Consolidated Balance Sheets. Restricted cash includes the following:
SPLNG Senior Notes Debt Service Reserve
SPLNG, our wholly owned subsidiary, has consummated private offerings of an aggregate principal amount of $1.7 billion,
before discount, of 7.50% Senior Secured Notes due 2016 (the “2016 SPLNG Senior Notes”) and $0.4 billion of 6.50% Senior
Secured Notes due 2020 (the “2020 SPLNG Senior Notes” and collectively with the 2016 SPLNG Senior Notes, the “SPLNG
Senior Notes”). Under the indentures governing the SPLNG Senior Notes (the “SPLNG Indentures”), except for permitted tax
distributions, SPLNG may not make distributions until certain conditions are satisfied, including: (1) there must be on deposit in
an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed
months since the last semi-annual interest payment, and (2) there must be on deposit in a permanent debt service reserve fund an
amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding
requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the SPLNG Indentures.
As of December 31, 2015 and 2014, we classified $77.4 million and $15.0 million, respectively, as current restricted cash
for the payment of current interest due. As of December 31, 2015 and 2014, we classified the permanent debt service reserve fund
of $13.7 million and $76.1 million, respectively, as non-current restricted cash. These cash accounts are controlled by a collateral
trustee; therefore, these amounts are shown as restricted cash on our Consolidated Balance Sheets.
SPL Reserve
During 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 SPL Credit Facilities”).
In June 2015, SPL entered into four credit facilities aggregating $4.6 billion (collectively, the “2015 SPL Credit Facilities”), which
replaced the 2013 SPL Credit Facilities. Under the terms and conditions of the 2015 SPL Credit Facilities (and previously the
2013 SPL Credit Facilities), SPL is required to deposit all cash received into reserve accounts controlled by a collateral trustee.
The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project; therefore, these
amounts are shown as restricted cash on our Consolidated Balance Sheets.
During 2013, SPL issued an aggregate principal amount of $2.0 billion, before premium, of 5.625% Senior Secured Notes
due 2021 (the “2021 SPL Senior Notes”), $1.0 billion of 6.25% Senior Secured Notes due 2022 (the “2022 SPL Senior Notes”)
and $1.0 billion of 5.625% Senior Secured Notes due 2023 (the “Initial 2023 SPL Senior Notes”). During 2014, SPL issued an
aggregate principal amount of $2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) and additional
5.625% Senior Secured Notes due 2023 in an aggregate principal amount of $0.5 billion, before premium (collectively with the
Initial 2023 SPL Senior Notes, the “2023 SPL Senior Notes”). In March 2015, SPL issued an aggregate principal amount of $2.0
billion of 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes” and collectively with the 2021 SPL Senior Notes,
the 2022 SPL Senior Notes, the 2023 SPL Senior Notes and the 2024 SPL Senior Notes, the “SPL Senior Notes”). The use of cash
proceeds from the SPL Senior Notes is restricted to the payment of liabilities related to the Liquefaction Project; therefore, these
amounts are shown as restricted cash on our Consolidated Balance Sheets. See Note 10—Debt for additional details about our
debt.
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
As of December 31, 2015 and 2014, we classified $189.3 million and $155.8 million, respectively, as current restricted cash
held by SPL for the payment of current liabilities, including interest payments, related to the Liquefaction Project and zero and
$457.1 million, respectively, as non-current restricted cash held by SPL for future Liquefaction Project construction costs.
CTPL Reserve
In May 2013, CTPL entered into a $400.0 million term loan facility (the “CTPL Term Loan”). As of December 31, 2015
and 2014, we classified $7.9 million and $24.9 million, respectively, as current restricted cash held by CTPL for the payment of
current liabilities and zero and $11.3 million, respectively, as non-current restricted cash held by CTPL because the usage and
withdrawal of such funds is primarily restricted to the payment of liabilities related to modifications of the Creole Trail Pipeline
in order to enable bi-directional natural gas flow, and for the payment of interest during construction of such modifications. The
restricted cash reserved to pay interest during construction is controlled by a collateral agent and can only be released by the
collateral agent upon satisfaction of certain terms and conditions. CTPL is required to pay annual fees to the administrative and
collateral agents.
NOTE 5—INVENTORY
As of December 31, 2015 and 2014, inventory consisted of the following (in thousands):
Natural gas
LNG
Materials and other
Total inventory
December 31,
2015
2014
$
$
5,724
3,690
7,253
16,667
$
$
—
4,293
3,493
7,786
NOTE 6—PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands):
LNG terminal costs
LNG terminal
LNG terminal construction-in-process
LNG site and related costs, net
Accumulated depreciation
Total LNG terminal costs, net
Fixed assets
Computer and office equipment
Furniture and fixtures
Computer software
Vehicles
Machinery and equipment
Other
Accumulated depreciation
Total fixed assets, net
Property, plant and equipment, net
December 31,
2015
2014
$ 2,478,036
9,859,836
135
(411,907)
11,926,100
$ 2,240,233
7,082,732
141
(348,907)
8,974,199
1,126
1,375
4,238
2,081
1,906
93
(5,317)
5,502
$ 11,931,602
1,105
1,375
2,411
1,507
1,508
94
(3,843)
4,157
$ 8,978,356
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
LNG Terminal Costs
The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal
assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives
have a depreciable range between 15 and 50 years, as follows:
Components
LNG storage tanks
Natural gas pipeline facilities
Marine berth, electrical, facility and roads
Regasification processing equipment (recondensers, vaporization and vents)
Sendout pumps
Other
Fixed Assets
Useful life (yrs)
50
40
35
30
20
15-30
Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the
individual assets or groups of assets.
NOTE 7—DERIVATIVE INSTRUMENTS
We have entered into the following derivative instruments that are reported at fair value:
(cid:129)
(cid:129)
(cid:129)
commodity derivatives to hedge the exposure to price risk attributable to future: (1) sales of our LNG inventory and
(2) purchases of natural gas to operate the Sabine Pass LNG terminal (“Natural Gas Derivatives”);
commodity derivatives consisting of natural gas purchase agreements and associated economic hedges to secure natural
gas feedstock for the Liquefaction Project (“Liquefaction Supply Derivatives”); and
interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015
SPL Credit Facilities (and previously the 2013 SPL Credit Facilities) (“Interest Rate Derivatives”).
None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded
within our Consolidated Statements of Operations.
SPLNG has elected to account for a portion of the Natural Gas Derivatives as normal purchase normal sale transactions,
exempt from fair value accounting. Gains and losses for these physical hedges are not reflected on our Consolidated Statements
of Operations until the period of delivery. SPLNG had not posted collateral for such forward contracts as of December 31, 2015
and 2014.
The following table shows the fair value (in thousands) of the derivative instruments that are required to be measured at
fair value on a recurring basis as of December 31, 2015 and 2014, which are classified as other current assets, non-current derivative
assets, derivative liabilities or other non-current liabilities in our Consolidated Balance Sheets.
Fair Value Measurements as of
December 31, 2015
December 31, 2014
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
Natural Gas Derivatives
asset
Liquefaction Supply
Derivatives asset (liability)
Interest Rate Derivatives
liability
$
— $
39
$
— $
39
$
— $
1,216
$
— $
1,216
—
—
(25)
32,492
32,467
—
—
342
342
(8,740)
—
(8,740)
— (12,036)
— (12,036)
The estimated fair values of our Natural Gas Derivatives are the amounts at which the instruments could be exchanged
currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data.
73
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
We value the Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach,
subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount
rates, credit spreads and other relevant data.
The fair value of substantially all of the Liquefaction Supply Derivatives is developed through the use of internal models
which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of the Liquefaction Supply
Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of the Liquefaction
Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be
observable liquid market basis information in the near term, but terms of a particular Liquefaction Supply Derivatives contract
may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair
value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery
periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair
value models that include contractual pricing with a fixed basis include fixed basis amounts for delivery at locations for which no
market currently exists. Internal fair value models also include conditions precedent to the respective long-term natural gas purchase
agreements. As of December 31, 2015 and 2014, some of the Liquefaction Supply Derivatives existed within markets for which
the pipeline infrastructure has not been developed to accommodate marketable physical gas flow. In the absence of infrastructure
to accommodate marketable physical gas flow, our internal fair value models are based on a market price that equates to our own
contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty
in the timing of our actual receipt of the physical volumes associated with each forward. The fair value of the Liquefaction Supply
Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent,
including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the completion and
placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or
loss based on the fair value of the respective natural gas purchase agreements as of the reporting date.
There were no transfers into or out of Level 3 Liquefaction Supply Derivatives for the years ended December 31, 2015,
2014 and 2013. As all of the Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis,
we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value
measurements. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction
Supply Derivatives as of December 31, 2015:
Liquefaction Supply Derivatives
$32,492
Income Approach
Basis Spread
$ (0.350) - $0.050
Net Fair Value Asset
(in thousands)
Valuation Technique
Significant Unobservable
Input
Significant Unobservable
Inputs Range
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis,
as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty
credit risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset
position.
Commodity Derivatives
We recognize all commodity derivative instruments that qualify for derivative accounting treatment, including the Natural
Gas Derivatives and the Liquefaction Supply Derivatives (collectively, “Commodity Derivatives”), as either assets or liabilities
and measure those instruments at fair value. Changes in the fair value of our Commodity Derivatives are reported in earnings.
74
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table (in thousands) shows the fair value and location of our Commodity Derivatives on our Consolidated
Balance Sheets:
Balance Sheet Location
Other current assets
Non-current derivative assets
Total derivative assets
Derivative liabilities
Other non-current liabilities
Total derivative liabilities
December 31, 2015
Natural Gas
Derivatives (1)
Liquefaction
Supply
Derivatives
Total
Natural Gas
Derivatives (1)
December 31, 2014
Liquefaction
Supply
Derivatives
Total
$
39
—
39
—
—
—
$
$
2,737
30,304
33,041
$
2,776
30,304
33,080
$
1,216
—
1,216
$
76
586
662
1,292
586
1,878
(490)
(84)
(574)
(490)
(84)
(574)
—
—
—
(53)
(267)
(320)
(53)
(267)
(320)
Derivative asset, net
$
39
$
32,467
$
32,506
$
1,216
$
342
$
1,558
(1)
Does not include a collateral deposit of $0.4 million and a collateral call of $1.1 million for such contracts, which are
included in other current assets in our Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.
The following table (in thousands) shows the changes in the fair value and settlements and location of our Commodity
Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2015, 2014 and 2013:
Statement of Operations Location
2015
2014
2013
Year Ended December 31,
Natural Gas Derivatives loss
Natural Gas Derivatives gain
Liquefaction Supply Derivatives gain (1)
Operating and maintenance expense
Operating and maintenance expense
Revenues
$
— $
(31) $
2,065
32,503
1,389
342
(463)
657
—
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable
to meet its commitments in instances when our Commodity Derivatives are in an asset position.
Natural Gas Derivatives
Our Natural Gas Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as
these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial
institutions to use margin deposits as credit support for our Natural Gas Derivatives activities.
Liquefaction Supply Derivatives
SPL has entered into index-based physical natural gas supply contracts and associated economic hedges to secure natural
gas feedstock for the Liquefaction Project. The terms of the physical contracts primarily range from approximately one to seven
years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified
Trains of the Liquefaction Project. We recognize the Liquefaction Supply Derivatives as either assets or liabilities and measure
those instruments at fair value. Changes in the fair value of the Liquefaction Supply Derivatives are reported in earnings. As of
December 31, 2015, SPL has secured up to approximately 2,154.2 million MMBtu of natural gas feedstock through natural gas
purchase agreements. The notional natural gas position of the Liquefaction Supply Derivatives was approximately 1,240.5 million
MMBtu.
75
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Interest Rate Derivatives
SPL has entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the
variable interest payments on the 2015 SPL Credit Facilities. The Interest Rate Derivatives hedge a portion of the expected
outstanding borrowings over the term of the 2015 SPL Credit Facilities.
In March 2015, SPL settled a portion of its Interest Rate Derivatives and we recognized a derivative loss of $34.7 million
within our Consolidated Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments
under the 2013 SPL Credit Facilities as discussed in Note 10—Debt. In May 2014, SPL settled a portion of its Interest Rate
Derivatives and recognized a derivative loss of $9.3 million within our Consolidated Statements of Operations in conjunction with
the early termination of approximately $2.1 billion of commitments under the 2013 SPL Credit Facilities.
At December 31, 2015, SPL had the following Interest Rate Derivatives outstanding:
Initial
Notional Amount
Maximum
Notional Amount
Effective Date
Maturity Date
Weighted
Average Fixed
Interest Rate
Paid
Interest Rate
Derivatives
$20.0 million
$628.8 million August 14, 2012
July 31, 2019
1.98%
Variable Interest Rate
Received
One-month
LIBOR
The following table (in thousands) shows the fair value and location of our Interest Rate Derivatives on our Consolidated
Balance Sheets:
Interest Rate Derivatives
Interest Rate Derivatives
Balance Sheet Location
Derivative liabilities
Non-current derivative assets (Other non-
current liabilities)
Fair Value Measurements as of
December 31, 2015
December 31, 2014
$
(5,940) $
(23,194)
(2,800)
11,158
The following table (in thousands) details the effect of our Interest Rate Derivatives included in Other Comprehensive
Income (“OCI”) and accumulated other comprehensive income (“AOCI”) during the year ended December 31, 2013. The Interest
Rate Derivatives had no effect on OCI during the years ended December 31, 2015 and 2014.
Year Ended December 31, 2013
Interest Rate Derivatives - Designated
Interest Rate Derivatives - Settlements
Gain (Loss) in OCI
Gain (Loss) Reclassified
from AOCI into
Interest Expense
(Effective Portion)
Losses Reclassified into
Earnings as a Result of
Discontinuance of Cash
Flow Hedge Accounting
$
21,297
(30)
$
— $
—
5,807
166
The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives
recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2015,
2014 and 2013:
Interest Rate Derivatives gain (loss)
$
(41,722) $
(119,401) $
88,596
Year Ended December 31,
2015
2014
2013
76
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Balance Sheet Presentation
Our Commodity Derivatives and Interest Rate Derivatives are presented on a net basis on our Consolidated Balance Sheets
as described above. The following table shows the fair value (in thousands) of our derivatives outstanding on a gross and net
basis:
Offsetting Derivative Assets (Liabilities)
Gross Amounts
Recognized
Gross Amounts Offset
in the Consolidated
Balance Sheets
Net Amounts Presented
in the Consolidated
Balance Sheets
As of December 31, 2015
Natural Gas Derivatives
Liquefaction Supply Derivatives
Liquefaction Supply Derivatives
Interest Rate Derivatives
As of December 31, 2014
Natural Gas Derivatives
Liquefaction Supply Derivatives
Liquefaction Supply Derivatives
Interest Rate Derivatives
Interest Rate Derivatives
$
$
188
33,636
(574)
(8,740)
1,226
662
(320)
11,158
(23,194)
(149) $
(595)
—
—
(10)
—
—
—
—
39
33,041
(574)
(8,740)
1,216
662
(320)
11,158
(23,194)
NOTE 8—OTHER NON-CURRENT ASSETS
As of December 31, 2015 and 2014, other non-current assets consisted of the following (in thousands):
Advances made under EPC and non-EPC contracts
Advances made to municipalities for water system enhancements
Tax-related payments and receivables
Conveyed assets to non-affiliates
Other
Total other non-current assets
NOTE 9—ACCRUED LIABILITIES
December 31,
2015
2014
$
$
32,049
89,953
27,615
—
50,396
200,013
$
$
6,414
36,441
24,093
14,751
42,822
124,521
As of December 31, 2015 and 2014, accrued liabilities consisted of the following (in thousands):
Interest expense and related debt fees
Liquefaction Project costs
LNG terminal costs
Other accrued liabilities
Total accrued liabilities
December 31,
2015
150,336
66,223
3,918
3,815
224,292
$
$
2014
112,858
22,014
1,077
629
136,578
$
$
77
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 10—DEBT
As of December 31, 2015 and 2014, our debt consisted of the following (in thousands):
Long-term debt
2016 SPLNG Senior Notes
2020 SPLNG Senior Notes
2021 SPL Senior Notes
2022 SPL Senior Notes
2023 SPL Senior Notes
2024 SPL Senior Notes
2025 SPL Senior Notes
2015 SPL Credit Facilities (1)
CTPL Term Loan (3)
Total long-term debt
Long-term debt premium (discount)
2016 SPLNG Senior Notes
2021 SPL Senior Notes
2023 SPL Senior Notes
CTPL Term Loan
Total long-term debt, net
Current debt
2016 SPLNG Senior Notes
2016 SPLNG Senior Notes - discount
SPL Working Capital Facility (5)
Total current debt, net
Interest
Rate
December 31,
2015
December 31,
2014
7.500% $
6.500%
5.625%
6.250%
5.625%
5.750%
5.625%
(2)
(4)
(6)
— $
420,000
2,000,000
1,000,000
1,500,000
2,000,000
2,000,000
845,000
400,000
10,165,000
—
8,718
6,392
(1,429)
10,178,681
1,665,500
(4,303)
15,000
1,676,197
1,665,500
420,000
2,000,000
1,000,000
1,500,000
2,000,000
—
—
400,000
8,985,500
(8,998)
10,177
7,089
(2,435)
8,991,333
—
—
—
—
Total debt, net
$ 11,854,878
$
8,991,333
(1)
(2)
(3)
(4)
(5)
Matures on the earlier of December 31, 2020 or the second anniversary of the completion date of Trains 1 through 5 of
the Liquefaction Project.
Variable interest rate, at SPL’s election, is LIBOR or the base rate plus the applicable margin. The applicable margins
for LIBOR loans range from 1.30% to 1.75%, depending on the applicable 2015 SPL Credit Facility, and the applicable
margin for base rate loans is 1.75%. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and
interest on base rate loans is due and payable at the end of each quarter.
Matures on May 28, 2017, when the full amount of the outstanding principal obligations must be repaid.
Variable interest rate, at CTPL’s election, is LIBOR or the base rate plus the applicable margin. CTPL has historically
elected LIBOR loans, for which the applicable margin is 3.25% and is due and payable at the end of each LIBOR period.
Matures on December 31, 2020, with various terms for underlying loans, as further described below under SPL Working
Capital Facility. As of December 31, 2014, no loans were outstanding under the $325.0 million senior letter of credit and
reimbursement agreement that was entered into in April 2014 (the “SPL LC Agreement”) it replaced.
(6)
Variable interest rates, based on LIBOR or the base rate, as further described below under SPL Working Capital Facility.
For the years ended December 31, 2015, 2014 and 2013, we incurred $707.7 million, $580.2 million and $414.0 million of
total interest cost, respectively, of which we capitalized and deferred $523.1 million, $403.2 million and $233.0 million, respectively,
of interest cost, including amortization of debt issuance costs, primarily related to the construction of the first four Trains of the
Liquefaction Project.
78
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31,
2015 (in thousands):
Years Ending December 31,
2016
2017
2018
2019
2020
Thereafter
Total
SPLNG Senior Notes
Principal Payments
1,680,500
400,000
—
—
1,265,000
8,500,000
11,845,500
$
$
The terms of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes are substantially similar. Interest on
the SPLNG Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the SPLNG Senior Notes are secured on
a first-priority basis by a security interest in all of SPLNG’s equity interests and substantially all of its operating assets.
SPLNG may redeem all or part of the 2016 SPLNG Senior Notes at any time, and from time to time, at a redemption price
equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:
(cid:129) 1.0% of the principal amount of the 2016 SPLNG Senior Notes; or
(cid:129) the excess of: (1) the present value at such redemption date of (a) the redemption price of the 2016 SPLNG Senior Notes
plus (b) all required interest payments due on the 2016 SPLNG Senior Notes (excluding accrued but unpaid interest to
the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis
points; over (2) the principal amount of the 2016 SPLNG Senior Notes, if greater.
SPLNG may redeem all or part of the 2020 SPLNG Senior Notes at any time on or after November 1, 2016, at fixed
redemption prices specified in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest, if any,
to the date of redemption. SPLNG may also, at its option, redeem all or part of the 2020 SPLNG Senior Notes at any time prior
to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 SPLNG Senior Notes, plus accrued
and unpaid interest, if any, to the date of redemption.
Under the SPLNG Indentures, except for permitted tax distributions, SPLNG may not make distributions until certain
conditions are satisfied as described in Note 4—Restricted Cash. During the years ended December 31, 2015, 2014 and 2013,
SPLNG made distributions of $337.3 million, $346.9 million and $348.9 million, respectively, after satisfying all the applicable
conditions in the SPLNG Indentures.
SPL Senior Notes
The terms of the SPL Senior Notes are governed by a common indenture (the “SPL Indenture”), and interest on the SPL
Senior Notes is payable semi-annually in arrears. The SPL Indenture contains customary terms and events of default and certain
covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to: incur additional
indebtedness; issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated
indebtedness; purchase, redeem or retire capital stock; sell or transfer assets, including capital stock of SPL’s restricted subsidiaries;
restrict dividends or other payments by restricted subsidiaries; incur liens; enter into transactions with affiliates; consolidate, merge,
sell or lease all or substantially all of SPL’s assets; and enter into certain LNG sales contracts. Subject to permitted liens, the SPL
Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and
substantially all of SPL’s assets. SPL may not make any distributions until, among other requirements, substantial completion of
Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts as required and a debt service coverage ratio for
the prior 12-month period and a projected debt service coverage ratio for the upcoming 12-month period of 1.25:1.00 are satisfied.
At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes, SPL may
redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price set forth in the
SPL Indenture, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months
of the respective maturity dates for each series of the SPL Senior Notes, redeem all or part of such series of the SPL Senior Notes
79
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued
and unpaid interest, if any, to the date of redemption.
2015 SPL Credit Facilities
In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion. The 2015 SPL
Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through
5 of the Liquefaction Project. Borrowings under the 2015 SPL Credit Facilities may be refinanced, in whole or in part, at any time
without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. As of December 31,
2015, SPL had $3.8 billion of available commitments and outstanding borrowings of $845.0 million under the 2015 SPL Credit
Facilities.
SPL incurred $88.3 million of debt issuance costs in connection with the 2015 SPL Credit Facilities. In addition to interest,
SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of
the 2015 SPL Credit Facilities. The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee calculated at
a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the undrawn
commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility. The principal of
the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June
30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project.
Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the
2015 SPL Credit Facilities.
The 2015 SPL Credit Facilities contain conditions precedent for borrowings, as well as customary affirmative and negative
covenants. The obligations of SPL under the 2015 SPL Credit Facilities are secured by substantially all of the assets of SPL as
well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and the $1.2 billion Amended and
Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “SPL Working Capital
Facility”) described below.
Under the terms of the 2015 SPL Credit Facilities, SPL is required to hedge not less than 65% of the variable interest rate
exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of
principal. Additionally, SPL may not make any distributions until substantial completion of Trains 1 and 2 of the Liquefaction
Project has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is
satisfied.
2013 SPL Credit Facilities
In May 2013, SPL entered into the 2013 SPL Credit Facilities to fund a portion of the costs of developing, constructing
and placing into operation Trains 1 through 4 of the Liquefaction Project, which amended and restated the credit facility that was
entered into in 2012 (the “2012 SPL Credit Facility”). As of December 31, 2014, SPL had no outstanding borrowings under the
2013 SPL Credit Facilities. In June 2015, the 2013 SPL Credit Facilities were replaced with the 2015 SPL Credit Facilities.
In March 2015, in conjunction with SPL’s issuance of the 2025 SPL Senior Notes, SPL terminated approximately $1.8
billion of commitments under the 2013 SPL Credit Facilities. This termination and the replacement of the 2013 SPL Credit
Facilities with the 2015 SPL Credit Facilities in June 2015 resulted in a write-off of debt issuance costs and deferred commitment
fees associated with the 2013 SPL Credit Facilities of $96.3 million for the year ended December 31, 2015. The amendment and
restatement of the 2012 SPL Credit Facility with the 2013 SPL Credit Facilities in May 2013 resulted in a write-off of debt issuance
costs and deferred commitment fees associated with the 2012 SPL Credit Facility of $88.3 million during the year ended December
31, 2013.
CTPL Term Loan
In May 2013, CTPL entered into the CTPL Term Loan, which was used to fund modifications to the Creole Trail Pipeline
and for general business purposes. CTPL incurred $10.0 million of direct lender fees that were recorded as a debt discount. As
of December 31, 2015, CTPL had borrowed the full amount of $400.0 million available under the CTPL Term Loan. The outstanding
balance may be repaid, in whole or in part, at any time without premium or penalty.
80
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The CTPL Term Loan contains customary affirmative and negative covenants. The obligations of CTPL under the CTPL
Term Loan are secured by a first priority lien on substantially all of the personal property of CTPL and all of the general partner
and limited partner interests in CTPL.
Cheniere Partners has guaranteed (1) the obligations of CTPL under the CTPL Term Loan if the maturity of the CTPL loans
is accelerated following the termination by SPL of a transportation precedent agreement in limited circumstances and (2) the
obligations of Cheniere Investments in connection with its obligations under an equity contribution agreement (a) to pay operating
expenses of CTPL until CTPL receives revenues under a service agreement with SPL and (b) to fund interest payments on the
CTPL loans after the funds in an interest reserve account have been exhausted.
SPL Working Capital Facility
In September 2015, SPL entered into the $1.2 billion SPL Working Capital Facility, which replaced the $325.0 million SPL
LC Agreement. The SPL Working Capital Facility is intended to be used for loans to SPL (“Working Capital Loans”), the issuance
of letters of credit on behalf of SPL (“Letters of Credit”), as well as for swing line loans to SPL (“Swing Line Loans”), primarily
for certain working capital requirements related to developing and placing into operation the Liquefaction Project. SPL may, from
time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the
completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to
an additional $390 million. As of December 31, 2015, SPL had $1.1 billion of available commitments, $135.2 million aggregate
amount of issued Letters of Credit, $15.0 million in Working Capital Loans and no Swing Line Loans or loans deemed made in
connection with a draw upon a Letter of Credit (“LC Loans” and collectively with Working Capital Loans and Swing Line Loans,
the “SPL Working Capital Facility Loans”) outstanding under the SPL Working Capital Facility. As of December 31, 2014, SPL
had issued letters of credit in an aggregate amount of $9.5 million, and no draws had been made upon any letters of credit issued
under the SPL LC Agreement.
SPL Working Capital Facility Loans accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to
the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve
Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR
SPL Working Capital Facility Loans is 1.75% per annum, and the applicable margin for base rate SPL Working Capital Facility
Loans is 0.75% per annum. Interest on Swing Line Loans and LC Loans is due and payable on the date the loan becomes due.
Interest on LIBOR Working Capital Loans is due and payable at the end of each applicable LIBOR period, and interest on base
rate Working Capital Loans is due and payable at the end of each fiscal quarter. However, if such base rate Working Capital Loan
is converted into a LIBOR Working Capital Loan, interest is due and payable on that date. Additionally, if the loans become due
prior to such periods, the interest also becomes due on that date.
SPL incurred $27.5 million of debt issuance costs in connection with the SPL Working Capital Facility. SPL pays (1) a
commitment fee equal to an annual rate of 0.70% on the average daily amount of the excess of the total commitment amount over
the principal amount outstanding without giving effect to any outstanding Swing Line Loans and (2) a Letter of Credit fee equal
to an annual rate of 1.75% of the undrawn portion of all Letters of Credit issued under the SPL Working Capital Facility. If draws
are made upon a Letter of Credit issued under the SPL Working Capital Facility and SPL does not elect for such draw (an “LC
Draw”) to be deemed an LC Loan, SPL is required to pay the full amount of the LC Draw on or prior to the business day following
the notice of the LC Draw. An LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of December 31, 2015,
no LC Draws had been made upon any Letters of Credit issued under the SPL Working Capital Facility.
The SPL Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or
in part, at any time without premium or penalty upon three business days’ notice. LC Loans have a term of up to one year. Swing
Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the SPL Working Capital Facility, (2) the
date 15 days after such Swing Line Loan is made and (3) the first borrowing date for a Working Capital Loan or Swing Line Loan
occurring at least three business days following the date the Swing Line Loan is made. SPL is required to reduce the aggregate
outstanding principal amount of all Working Capital Loans to zero for a period of five consecutive business days at least once each
year.
The SPL Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative
and negative covenants. The obligations of SPL under the SPL Working Capital Facility are secured by substantially all of the
assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and the 2015 SPL
Credit Facilities.
81
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Fair Value Disclosures
The following table shows the carrying amount and estimated fair value (in thousands) of our debt:
2016 SPLNG Senior Notes, net of discount (1)
2020 SPLNG Senior Notes (1)
2021 SPL Senior Notes, net of premium (1)
2022 SPL Senior Notes (1)
2023 SPL Senior Notes, net of premium (1)
2024 SPL Senior Notes (1)
2025 SPL Senior Notes (1)
2015 SPL Credit Facilities (2)
CTPL Term Loan, net of discount (2)
SPL Working Capital Facility (2)
$
December 31, 2015
December 31, 2014
$
Carrying
Amount
1,661,197
420,000
2,008,718
1,000,000
1,506,392
2,000,000
2,000,000
845,000
398,571
15,000
$
Estimated
Fair Value
1,652,891
403,200
1,832,955
912,500
1,299,263
1,715,000
1,710,000
845,000
400,000
15,000
Carrying
Amount
1,656,502
420,000
2,010,177
1,000,000
1,507,089
2,000,000
—
—
397,565
—
$
Estimated
Fair Value
1,718,621
428,400
1,985,050
1,020,000
1,476,947
1,970,000
—
—
400,000
—
(1)
(2)
The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and
similar instruments based on the closing trading prices on December 31, 2015 and 2014, as applicable.
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.
NOTE 11—RELATED PARTY TRANSACTIONS
LNG Terminal Capacity Agreements
Terminal Use Agreement
SPL obtained approximately 2.0 Bcf/d of regasification capacity under a TUA with SPLNG as a result of an assignment in
July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly
capacity payments to SPLNG aggregating approximately $250 million per year, continuing until at least 20 years after SPL delivers
its first commercial cargo at the Liquefaction Project.
In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the
cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. During the years ended December 31, 2015,
2014 and 2013, we recorded $18.8 million, $26.1 million and $26.6 million, respectively, as operating and maintenance expense
related to this obligation.
Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”)
pursuant to which Cheniere Investments has the right to use SPL’s reserved capacity under the TUA and has the obligation to make
the monthly capacity payments required by the TUA to SPLNG. However, the revenue earned by SPLNG from the capacity
payments made under the TUA and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation
of our Financial Statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments
under the TURA.
In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction
Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments
(the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of
the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal.
We recorded no revenues—affiliate from Cheniere Marketing during the years ended December 31, 2015, 2014 and 2013,
respectively, related to the Amended and Restated VCRA.
82
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Cheniere Marketing SPA
Cheniere Marketing has entered into an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by
SPL in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.
Commissioning Agreement
In May 2015, SPL entered into an agreement with Cheniere Marketing that obligates Cheniere Marketing in certain
circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) has control
of, and is commissioning, the first four Trains of the Liquefaction Project.
Pre-commercial LNG Marketing Agreement
In May 2015, SPL entered into an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s
behalf to market and sell pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC.
Services Agreements
As of December 31, 2015 and 2014, we had $39.8 million and $27.3 million of advances to affiliates, respectively, under
the services agreements described below. During the years ended December 31, 2015, 2014 and 2013, we recorded general and
administrative expense—affiliate of $122.3 million, $101.4 million and $129.8 million, respectively, and operating and maintenance
expense—affiliate of $29.4 million, $21.1 million and $29.3 million, respectively, under the services agreements described below.
Cheniere Partners Services Agreement
We have entered into a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to
which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $2.8 million (adjusted for
inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled
to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services
under the agreement.
Cheniere Investments Information Technology Services Agreement
Cheniere Investments has entered into an information technology services agreement with Cheniere, pursuant to which
Cheniere Investments’ subsidiaries receive certain information technology services. On a quarterly basis, the various entities
receiving the benefit are invoiced by Cheniere according to the cost allocation percentages set forth in the agreement. In addition,
Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the
agreement.
SPLNG O&M Agreement
SPLNG has entered into a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere
Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG
receiving terminal. SPLNG incurs a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement
and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between
SPLNG and Cheniere Investments at the beginning of each operating year. In addition, SPLNG incurs costs to reimburse Cheniere
Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services
required under the SPLNG O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere.
All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to
such subsidiary.
83
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
SPLNG MSA
SPLNG has entered into a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals,
pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters
provided for under the SPLNG O&M Agreement. SPLNG incurs a monthly fixed fee of $520,000 (indexed for inflation) under
the SPLNG MSA.
SPL O&M Agreement
SPL has entered into an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments
pursuant to which SPL receives all of the necessary services required to construct, operate and maintain the Liquefaction Project.
Before the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental
approvals on behalf of SPL, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and
preparing status reports. After the Liquefaction Project is operational, the services include all necessary services required to operate
and maintain the Liquefaction Project. Before the Liquefaction Project is operational, in addition to reimbursement of operating
expenses, SPL is required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After
substantial completion of each Train, for services performed while the Liquefaction Project is operational, SPL will pay, in addition
to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to
such Train. Cheniere Investments provides the services required under the SPL O&M Agreement pursuant to a secondment
agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPL O&M
Agreement are required to be remitted to such subsidiary.
SPL MSA
SPL has entered into a management services agreement (the “SPL MSA”) with Cheniere Terminals pursuant to which
Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for
under the SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s
affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records
of SPL’s business and operations, entering into financial derivatives on our behalf and providing contract administration services
for all contracts associated with the Liquefaction Project. Under the SPL MSA, SPL pays a monthly fee equal to 2.4% of the
capital expenditures incurred in the previous month. After substantial completion of each Train, SPL will pay a fixed monthly fee
of $541,667 (indexed for inflation) for services with respect to such Train.
CTPL O&M Agreement
CTPL has entered into an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with
Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail
Pipeline. CTPL is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses.
Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with
a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M Agreement
are required to be remitted to such subsidiary.
CTPL MSA
CTPL has entered into a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which
Cheniere Terminals manages the modification and operation of the Creole Trail Pipeline, excluding those matters provided for
under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s
affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records
of CTPL’s business and operations and providing contract administration services for all contracts associated with the pipeline
facilities. Under the CTPL MSA, CTPL pays a monthly fee equal to 3.0% of the capital expenditures to enable bi-directional
natural gas flow on the Creole Trail Pipeline incurred in the previous month.
LNG Lease Agreement
In September 2011, Cheniere Investments entered into an agreement in the form of a lease (the “LNG Lease Agreement”)
with Cheniere Marketing that enables Cheniere Investments to supply the Sabine Pass LNG terminal with LNG to maintain proper
84
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
LNG inventory levels and temperature. The LNG Lease Agreement also enables Cheniere Investments to hedge the exposure to
variability in expected future cash flows of the LNG inventory. Under the terms of the LNG Lease Agreement, Cheniere Marketing
funds all activities related to the purchase and hedging of the LNG, and Cheniere Investments reimburses Cheniere Marketing for
all costs and assumes full price risk associated with these activities.
As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, any LNG inventory
purchased by Cheniere Marketing under this arrangement is classified as inventory—affiliate on our Consolidated Balance Sheets.
This amount is recorded at cost and subject to LCM adjustments at the end of each period. Inventory—affiliate cost is determined
using the average cost method. Recoveries of losses resulting from interim period LCM adjustments are made due to market price
recoveries on the same inventory—affiliate in the same fiscal year and are recognized as gains in later interim periods with such
gains not exceeding previously recognized losses. Gains or losses on the sale of inventory—affiliate and LCM adjustments are
recorded as revenues on our Consolidated Statements of Operations. As of December 31, 2015 and 2014, we had no LNG inventory
—affiliate recorded on our Consolidated Balance Sheets under the LNG Lease Agreement.
Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”)
In July 2007, SPLNG executed CEAs with various Cameron Parish, Louisiana taxing authorities that allow them to collect
certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represents an aggregate
commitment of up to $25.0 million, and SPLNG will make resources available to the Cameron Parish taxing authorities on an
accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance
payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes
to be levied against the Sabine Pass LNG terminal starting in 2019. In September 2007, SPLNG entered into an agreement with
Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all
amounts payable under the CEAs in exchange for a similar amount of credits against future TUA payments it would owe SPLNG
under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its TUA to Cheniere Investments and concurrently
entered into a variable capacity rights agreement, allowing Cheniere Marketing to utilize Cheniere Investments’ capacity under
the TUA after the assignment. In July 2012, Cheniere Investments entered into the Amended and Restated VCRA with Cheniere
Marketing in order for Cheniere Investments to utilize during construction of the Liquefaction Project the capacity rights granted
under the TURA. Cheniere Marketing will continue to fund the CEAs during the term of the Amended and Restated VCRA and,
in exchange, Cheniere Marketing will receive the benefit of any future credits.
On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere
Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of December 31,
2015 and 2014, we had $22.1 million and $19.6 million, respectively, of both other non-current assets resulting from SPLNG’s
ad valorem tax payments and non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.
Contracts for Sale and Purchase of Natural Gas and LNG
SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these
agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price
paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing
with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal. As a result, SPLNG
records the purchases of natural gas and LNG from Cheniere Marketing to be utilized as fuel to operate the Sabine Pass LNG
terminal as operating and maintenance expense.
SPLNG recorded operating and maintenance expense of $5.0 million, $3.3 million and $3.3 million in the years ended
December 31, 2015, 2014 and 2013, respectively, for natural gas purchased from Cheniere Marketing under these agreements.
SPLNG recorded revenues—affiliate of $11.7 million, $0.7 million and $14.7 million in the years ended December 31, 2015, 2014
and 2013, respectively, for natural gas sold to Cheniere Marketing under these agreements.
Tug Boat Lease Sharing Agreement
In connection with its tug boat lease, Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of
SPLNG, entered into a tug sharing agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with
tug boat and marine services at the Sabine Pass LNG terminal. Tug Services recorded revenues—affiliate of $2.8 million pursuant
to this agreement in each of the years ended December 31, 2015, 2014 and 2013.
85
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
LNG Terminal Export Agreement
In January 2010, SPLNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere
Marketing the ability to export LNG from the Sabine Pass LNG terminal. SPLNG did not record any revenues associated with
this agreement during the years ended December 31, 2015, 2014 and 2013.
State Tax Sharing Agreements
In November 2006, SPLNG entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has
agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and
to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to
Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were
computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have
demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG.
The agreement is effective for tax returns due on or after January 1, 2008.
In August 2012, SPL entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed
to prepare and file all state and local tax returns which SPL and Cheniere are required to file on a combined basis and to timely
pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPL will pay to Cheniere an
amount equal to the state and local tax that SPL would be required to pay if SPL’s state and local tax liability were calculated on
a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded
payment from SPL under this agreement; therefore, Cheniere has not demanded any such payments from SPL. The agreement is
effective for tax returns due on or after August 2012.
In May 2013, CTPL entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed
to prepare and file all state and local tax returns which CTPL and Cheniere are required to file on a combined basis and to timely
pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CTPL will pay to Cheniere an
amount equal to the state and local tax that CTPL would be required to pay if CTPL’s state and local tax liability were calculated
on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded
payment from CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement
is effective for tax returns due on or after May 2013.
NOTE 12—LEASES
During the years ended December 31, 2015, 2014 and 2013, we recognized rental expense for all operating leases of $10.5
million, $10.5 million and $10.0 million, respectively, related primarily to office space and land sites. Our land site leases for the
Sabine Pass LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years.
Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands):
Years Ending December 31,
2016
2017
2018
2019
2020
Thereafter (1)
Total
(1)
Includes certain lease option renewals that are reasonably assured.
86
Operating Leases
$
$
2,620
2,220
2,219
2,197
2,056
29,664
40,976
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 13—COMMITMENTS AND CONTINGENCIES
We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other
items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of
December 31, 2015, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.
LNG Terminal Commitments and Contingencies
Obligations under LNG TUAs
SPLNG has entered into third-party TUAs with Total Gas & Power North America, Inc. and Chevron U.S.A. Inc. to provide
berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.
Obligations under Bechtel EPC Contracts
SPL has entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains
1 and 2 (the “EPC Contract (Trains 1 and 2)”), Trains 3 and 4 (the “EPC Contract (Trains 3 and 4)”) and Train 5 (the “EPC Contract
(Train 5)”) of the Liquefaction Project.
The EPC Contract (Trains 1 and 2), the EPC Contract (Trains 3 and 4) and the EPC Contract (Train 5) provide that SPL
will pay Bechtel contract prices of $4.1 billion, $3.8 billion and $3.0 billion, respectively, subject to adjustment by change order.
SPL has the right to terminate each EPC contract for its convenience, in which case Bechtel will be paid (1) the portion of the
contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization,
and (3) a lump sum of up to $30.0 million depending on the termination date.
Obligations under SPAs
SPL has entered into third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to
deliver 1,030.0 million MMBtu per year of LNG to the customers’ vessels, subject to completion of construction of Trains 1 through
5 of the Liquefaction Project.
Obligations under Natural Gas Supply, Transportation and Storage Service Agreements
SPL has entered into index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction
Project. The terms of these contracts primarily range from approximately one to seven years and commence upon the occurrence
of conditions precedent, including SPL’s declaration to the respective natural gas supplier that it is ready to commence the term
of the supply arrangement in anticipation of the date of first commercial operation of the applicable, specified Trains of the
Liquefaction Project. As of December 31, 2015, SPL has secured up to approximately 2,154.2 million MMBtu of natural gas
feedstock through natural gas purchase agreements, of which we determined that we have purchase obligations for the contracts
for which conditions precedent were met.
Additionally, SPL has entered into transportation and storage service agreements for the Liquefaction Project. The initial
term of the transportation agreements ranges from 10 to 20 years, with renewal options for certain contracts, and commences upon
the occurrence of conditions precedent. The term of our storage service agreements is typically three years.
As of December 31, 2015, SPL’s purchase obligations under natural gas supply, transportation and storage service agreements
for contracts in which conditions precedent were met were as follows (in thousands):
Years Ending December 31,
2016
2017
2018
2019
2020
Thereafter
Total
87
Payments Due (1)
341,039
284,263
231,550
182,470
189,640
259,273
1,488,235
$
$
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(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, 2015.
Services Agreements
We have entered into certain services agreements with affiliates. See Note 11—Related Party Transactions for information
regarding such agreements.
Restricted Net Assets
At December 31, 2015, our restricted net assets of consolidated subsidiaries were approximately $618 million.
Other Commitments
State Tax Sharing Agreements
SPLNG, SPL and CTPL have entered into state tax sharing agreements with Cheniere. See Note 11—Related Party
Transactions for information regarding such agreements.
Cooperative Endeavor Agreements
SPLNG has executed CEAs with various Cameron Parish, Louisiana taxing authorities. See Note 11—Related Party
Transactions for information regarding such agreements.
Other Agreements
In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which
are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 12—
Leases.
Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of
business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual
disposition of these matters. In the opinion of management, as of December 31, 2015, there were no pending legal matters that
would reasonably be expected to have a material impact on our consolidated operating results, financial position or cash flows.
NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in thousands):
Year Ended December 31,
2014
$ 130,578
2013
$ 120,908
2015
$ 135,836
230,699
13,169
—
124,741
166,252
—
—
—
180,000
Cash paid during the year for interest, net of amounts capitalized and deferred
Balance in property, plant and equipment, net funded with accounts payable and
accrued liabilities (including affiliate)
Non-cash conveyance of assets
Class B units issued in connection with Creole Trail Pipeline Business acquisition
88
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 15—NET INCOME (LOSS) PER COMMON UNIT
Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with
respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided
by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated
Statements of Partners’ Equity. On January 22, 2016, we declared a $0.425 distribution per common unit and the related distribution
to our general partner was paid on February 12, 2016 to unitholders of record as of February 1, 2016 for the period from October 1,
2015 to December 31, 2015.
The two-class method dictates that net income (loss) for a period be reduced by the amount of available cash that will be
distributed with respect to that period and that any residual amount representing undistributed net income be allocated to common
unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for
the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating
securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses
(including those resulting from distributions in excess of net income) are allocated to common units and other participating securities
on a pro rata basis based on provisions of the partnership agreement. Historical income (loss) attributable to a company that was
purchased from an entity under common control is allocated to the predecessor owner in accordance with the terms of the partnership
agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash
distributions are not necessarily derived from current or prior period earnings.
The Class B units were issued at a discount to the market price of the common units into which they are convertible. This
discount totaling $2,130.0 million represents a beneficial conversion feature and is reflected as an increase in common and
subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at
issuance on our Consolidated Statements of Partners’ Equity. The beneficial conversion feature is considered a dividend that will
be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase
in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortize the beneficial conversion
feature assuming a conversion date of June 2017 and August 2017 for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B
units, respectively, although actual conversion may occur prior to or after these assumed dates. We are amortizing using the
effective yield method with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’
and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature is also included in
earnings per unit for the years ended December 31, 2015, 2014 and 2013.
The following is a schedule by years, based on the capital structure as of December 31, 2015, of the anticipated impact to
the capital accounts in connection with the amortization of the beneficial conversion feature (in thousands):
2016
2017
Common Units
Class B Units
Subordinated Units
$
(29,565) $
(594,426)
99,685
2,004,209
$
(70,119)
(1,409,783)
89
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Under our partnership agreement, the incentive distribution rights (“IDRs”) participate in net income (loss) only to the
extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net
income (loss). We did not allocate earnings or losses to IDR holders for the purpose of the two-class method earnings per unit
calculation for any of the periods presented. The following table provides a reconciliation of net loss and the allocation of net loss
to the common units, the subordinated units, the general partner and the Creole Trail Pipeline Business for purposes of computing
net loss per unit The following table (in thousands, except per unit data) also provides net loss per unit, as adjusted, assuming
the common units, subordinated units and the general partner had participated in the pre-acquisition date net losses of the Creole
Trail Pipeline Business.
Limited Partner Units
Total
Common Units
Class B Units
Subordinated
Units
General
Partner
Creole Trail
Pipeline
Business
Year Ended December 31, 2015
Net loss
Declared distributions
Assumed allocation of undistributed net
loss
Assumed allocation of net loss
$ (318,891)
99,018
97,038
—
—
1,980
$ (417,909)
(121,468)
$
(24,430) $
(288,083)
—
— $ (288,083) $
(8,358)
(6,378) $
—
—
Weighted average units outstanding
Net loss per unit
57,081
145,333
$
(0.43) $
— $
135,384
(2.13)
Year Ended December 31, 2014
Net loss
Declared distributions
Assumed allocation of undistributed net
loss
Assumed allocation of net loss
$ (410,036)
99,015
97,036
—
—
1,979
$ (509,051)
(147,952)
$
(50,916) $
(350,918)
—
— $ (350,918) $
(10,181)
(8,202) $
—
—
Weighted average units outstanding
Net loss per unit
57,079
145,333
$
(0.89) $
— $
135,384
(2.59)
Year Ended December 31, 2013
Net loss
Declared distributions
Assumed allocation of undistributed net
loss
Assumed allocation of net loss
Assumed allocation of net loss adjusted
for the Creole Trail Pipeline Business
Weighted average units outstanding
Net loss per unit
Net loss per unit, adjusted to include pre-
acquisition date net losses of the Creole
Trail Pipeline Business
$ (258,117)
99,015
97,035
—
—
1,980
$ (357,132)
(98,522)
(1,487) $
(233,680)
—
— $ (233,680) $
(6,780)
(4,800) $
(18,150)
(18,150)
$
$
$
$
(6,762) $
— $ (246,192) $
(5,163)
54,235
140,500
(0.03) $
— $
135,384
(1.73)
(0.12) $
— $
(1.82)
90
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 16—RECENT ACCOUNTING STANDARDS
The following table provides a brief description of recent accounting standards that had not yet been adopted by the Partnership
as of December 31, 2015:
Standard
ASU 2014-09, Revenue
from Contracts with
Customers (Topic 606)
ASU 2014-15, Presentation
of Financial Statements-
Going Concern (Subtopic
205-40): Disclosure of
Uncertainties about an
Entity’s Ability to Continue
as a Going Concern
ASU 2015-02,
Consolidation (Topic 810):
Amendments to the
Consolidation Analysis
Description
The standard amends 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. This guidance may be
early adopted beginning January 1, 2017, and
may be adopted either retrospectively to each
prior reporting period presented or as a
cumulative-effect adjustment as of the date of
adoption.
The standard requires an entity’s management to
evaluate, for each reporting period, whether there
are conditions and events that raise substantial
doubt about the entity’s ability to continue as a
going concern within one year after the financial
statements are issued. Additional disclosures are
required if management concludes that conditions
or events raise substantial doubt about the entity’s
ability to continue as a going concern. Early
adoption is permitted.
This amendment primarily affects asset managers
and reporting entities involved with limited
partnerships or similar entities, but the analysis is
relevant in the evaluation of any reporting
organization’s requirement to consolidate a legal
entity. This guidance changes (1) the
identification of variable interests, (2) the
variable interest entity characteristics for a
limited partnership or similar entity and (3) the
primary beneficiary determination. This
guidance may be early adopted, and may be
adopted either retrospectively to each prior
reporting period presented or as a cumulative-
effect adjustment as of the date of adoption.
Expected
Date of
Adoption
January 1,
2018
Effect on our
Consolidated Financial
Statements or Other
Significant Matters
We are currently
evaluating the impact of
the provisions of this
guidance on our
Consolidated Financial
Statements and related
disclosures.
December 31,
2016
The adoption of this
guidance is not expected
to have an impact on our
Consolidated Financial
Statements or related
disclosures.
January 1,
2016
The adoption of this
guidance is not expected
to have an impact on our
Consolidated Financial
Statements or related
disclosures.
ASU 2015-03, Interest -
Imputation of Interest
(Subtopic 835-30):
Simplifying the
Presentation of Debt
Issuance Costs and ASU
2015-15, Presentation and
Subsequent Measurement of
Debt Issuance Costs
Associated with Line-of-
Credit Arrangements
This standard requires debt issuance costs related
to a recognized debt liability to be presented in
the balance sheet as a direct deduction from the
debt liability rather than as an asset. Debt
issuance costs incurred in connection with line of
credit arrangements may be presented as an asset
and subsequently amortized ratably over the term
of the line of credit arrangement. This guidance
may be early adopted, and must be adopted
retrospectively to each prior reporting period
presented.
January 1,
2016
Upon adoption of this
standard, the balance of
debt, net will be reduced
by the balance of debt
issuance costs, net, except
for the balance related to
line of credit
arrangements, on our
Consolidated Balance
Sheets. Additionally,
disclosures will be
required for a change in
accounting principle.
91
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Standard
ASU 2015-06, Earnings
Per Share (Topic 260):
Effects on Historical
Earnings per Unit of
Master Limited Partnership
Dropdown Transactions
ASU 2015-11, Inventory
(Topic 330): Simplifying the
Measurement of Inventory
Description
This standard requires a master limited
partnership to allocate net income (losses) of a
transferred business entirely to the general
partner when computing earnings per unit for
periods before the dropdown transaction
occurred. This guidance also requires a master
limited partnership to disclose the effects of the
dropdown transaction on net income (losses) per
unit for the periods before and after the dropdown
transaction occurred. This guidance may be early
adopted, and must be adopted retrospectively to
each prior reporting period presented.
This standard requires inventory to be measured
at the lower of cost and net realizable value. Net
realizable value is the estimated selling prices in
the ordinary course of business, less reasonably
predictable costs of completion, disposal and
transportation. This guidance may be early
adopted and must be adopted prospectively.
NOTE 17—SUBSEQUENT EVENTS
Expected
Date of
Adoption
January 1,
2016
Effect on our
Consolidated Financial
Statements or Other
Significant Matters
The adoption of this
guidance is not expected
to have an impact on our
Consolidated Financial
Statements or related
disclosures.
January 1,
2017
We are currently
evaluating the impact of
the provisions of this
guidance on our
Consolidated Financial
Statements and related
disclosures.
In January 2016, we engaged 13 financial institutions to act as Joint Lead Arrangers, Mandated Lead Arrangers and other
participants to assist in the structuring and arranging of up to approximately $2.8 billion of senior secured credit facilities. Proceeds
from these new credit facilities are intended to be used by us to prepay $400.0 million of the CTPL Term Loan, to redeem or repay
$1,665.5 million of the 2016 SPLNG Senior Notes and $420.0 million of the 2020 SPLNG Senior Notes, to pay associated
transaction fees, expenses and make-whole amounts, if applicable, and for our general business purposes.
92
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
SUMMARIZED QUARTERLY FINANCIAL DATA
(unaudited)
Summarized Quarterly Financial Data—(in thousands, except per unit amounts)
Year ended December 31, 2015:
Revenues
Income (loss) from operations
Net loss
Basic and diluted net income (loss) per common unit (1)
Year ended December 31, 2014:
Revenues
Income (loss) from operations
Net loss
Basic and diluted net income (loss) per common unit (1)
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$
$
$
$
$
67,530
(9,822)
(178,676)
$
67,689
(4,318)
(60,043)
(0.61) $
(0.01) $
$
67,221
4,893
(69,733)
$
67,328
(7,791)
(226,224)
(0.06) $
(0.85) $
67,537
35,921
(24,132)
0.18
67,590
(1,862)
(43,240)
0.08
$
$
$
$
67,272
(18,739)
(56,040)
0.01
66,559
5,275
(70,839)
(0.06)
(1) The sum of the quarterly net income (loss) per common unit may not equal the full year amount as the computations of the
weighted average common units outstanding for basic and diluted common units outstanding for each quarter and the full
year are performed independently.
93
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to
our management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow
timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 31, 2015, our general partner’s principal executive
officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e)
and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or
submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive
officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded,
processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have
materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements
on page 55 and is incorporated herein by reference.
ITEM 9B.
OTHER INFORMATION
Compliance Disclosure
Pursuant to Section 13(r) of the Exchange Act, if during the fiscal year ended December 31, 2015, we or any of our affiliates
had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be
required to disclose information regarding such transactions in our annual report on Form 10-K as required under Section 219 of
the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”). During the fiscal year ended December 31, 2015, we
did not engage in any transactions with Iran or with persons or entities related to Iran.
Blackstone CQP Holdco, an affiliate of Blackstone Group, is a holder of more than 29% of our outstanding equity interests
and has three representatives on the Board of Directors of Cheniere Partners GP. Accordingly, Blackstone Group may be deemed
our “affiliate,” as that term is defined in Exchange Act Rule 12b-2. During the year ended December 31, 2015, Blackstone Group
has included in its quarterly reports on Form 10-Q for the quarterly periods ended March 31, 2015, June 30, 2015 and September
30, 2015 disclosures pursuant to ITRA regarding two of its portfolio companies that may be deemed to be affiliates of Blackstone
Group. Because of the broad definition of “affiliate” in Exchange Act Rule 12b-2, these portfolio companies of Blackstone Group,
through Blackstone Group’s ownership of Cheniere Partners, may also be deemed to be affiliates of ours. We have not independently
verified the disclosure described in the following paragraphs.
Blackstone Group has reported that Hilton Worldwide Holdings Inc. (“Hilton”) has engaged in the following activity during
the fiscal quarter ended September 30, 2015: an Iranian governmental delegation stayed at the Transcorp Hilton Abuja for one
night. The stays were booked and paid for by the government of Nigeria. The hotel received revenues of approximately $5,320
from these dealings, and net profit to Hilton from these dealings was approximately $495, as reported by Blackstone Group. The
gross revenues and net profits attributable to such activities by Hilton during the fiscal year ended December 31, 2015 have not
been reported by Hilton. Hilton believes that the hotel stays were exempt from the Iranian Transactions and Sanctions Regulations,
31 C.F.R. Part 560, pursuant to the International Emergency Economic Powers Act (“IEEPA”) and under 31 C.F.R. Section 560.210
94
(d). Blackstone Group has reported that the Transcorp Hilton Abuja intends to continue engaging in future similar transactions to
the extent they remain permissible under applicable laws and regulations.
Blackstone Group has reported that Travelport Worldwide Limited (“Travelport”) has engaged in the following activities:
as part of its global business in the travel industry, Travelport provides certain passenger travel related Travel Commerce Platform
and Technology Services to Iran Air. Travelport also provides certain airline Technology Services to Iran Air Tours. The gross
revenues and net profits attributable to such activities by Travelport during the fiscal year ended December 31, 2015 have not been
reported by Travelport; the gross revenues and net profits attributable to such activities by Travelport during the first nine months
of 2015 were reported by Travelport to be approximately $435,000 and $307,000, respectively. Blackstone Group reported that
Travelport intends to continue these business activities with Iran Air and Iran Air Tours as such activities are either exempt from
applicable sanctions prohibitions or specifically licensed by the Office of Foreign Assets Control.
In our Form 10-Q reports for the quarterly periods ended on March 31, 2015, June 30, 2015 and September 30, 2015, we
disclosed, under “Item 5. Other Information—Compliance Disclosure” in each such report, as amended, activities as required by
Section 13(r) of the Exchange Act as transactions or dealings with the government of Iran that have not been specifically authorized
by a U.S. federal department or agency. Such disclosures are incorporated herein by reference.
95
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND CORPORATE
GOVERNANCE
Management of Cheniere Energy Partners, L.P.
Cheniere Partners GP, as our general partner, manages our operations and activities. Our general partner is not elected by
our unitholders and is not subject to re-election on a regular basis in the future. The directors of our general partner are elected
by the sole member of the general partner. Unitholders are not entitled to elect the directors of our general partner or to participate
directly or indirectly in our management or operations.
Audit Committee
The board of directors of our general partner has appointed an audit committee composed of Lon McCain, chairman, Oliver
G. Richard, III and Vincent Pagano, Jr., each of whom is an independent director and satisfies the additional independence and
other requirements for audit committee members provided for in the listing standards of the NYSE MKT and the Exchange Act.
In addition, the board of directors of our general partner has determined that Lon McCain and Oliver G. Richard, III meet the
qualifications of a “financial expert” and are “financially sophisticated” as such terms are defined by the SEC and the NYSE MKT,
respectively.
The audit committee assists the board of directors of our general partner in its oversight of the integrity of our Financial
Statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee
has the sole authority to retain and terminate our independent registered public accounting firm, approve all audit services and
related fees and the terms thereof and pre-approve any non-audit services to be rendered by our independent registered public
accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent
registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the
audit committee. Our audit committee charter is posted at /http://www.cheniere.com/about-us/cheniere-partners/governance-and-
ethics/audit-committee/.
Conflicts Committee
Under our partnership agreement, the board of directors of our general partner has appointed a conflicts committee composed
of the independent directors, Vincent Pagano, Jr., chairman, Lon McCain, Oliver G. Richard, III and James R. Ball, to review
specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution
of a conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be security holders, officers
or employees of our general partner, directors, officers, or employees of affiliates of the general partner or holders of any ownership
interest in us other than common units or other publicly traded units and must meet the independence standards established by the
NYSE MKT, the Exchange Act and other federal securities laws. Any matter approved by the conflicts committee is conclusively
deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties that
it may owe us or our unitholders.
Other
We do not have a nominating committee because the directors of our general partner manage our operations. Our general
partner is not elected by our unitholders and is not subject to re-election on a regular basis. Unitholders are not entitled to elect
the directors of our general partner or to participate directly or indirectly in our management or operations.
We also do not have a compensation committee. We have no employees, directors or officers. We are managed by our
general partner, Cheniere Partners GP. Our general partner has paid no cash compensation to its executive officers since its
inception. All of the executive officers of our general partner are also executive officers of Cheniere. Cheniere compensates these
officers for the performance of their duties as executive officers of Cheniere, which includes managing our partnership. Cheniere
does not allocate this compensation between services for us and services for Cheniere and its affiliates.
96
Directors and Executive Officers of Our General Partner
We have no employees, directors or officers. We are managed by our general partner, Cheniere Partners GP. The following
sets forth information, as of February 12, 2016, regarding the individuals who currently serve on the board of directors and as
executive officers of our general partner. Neal Shear has served as a director of Cheniere Partners GP since December 13, 2015.
Meg Gentle and Lon McCain have served as directors of the general partner since 2007. Keith Teague has served as a director of
the general partner since 2008. Messrs. Ball, Klimczak, Pagano and Richard were elected as directors of the general partner in
2012. Philip Meier was elected a director of the general partner in July 2013. Michael Wortley was elected as a director of the
general partner in January 2014. John-Paul Munfa was elected as a director of the general partner in 2015. The appointments of
Messrs. Klimczak, Meier and Munfa to the board of directors of our general partner were made pursuant to the rights of Blackstone
CQP Holdco under the Third Amended and Restated Limited Liability Company Agreement of our general partner to appoint
certain directors to the board of directors of our general partner.
Name
Neal A. Shear
R. Keith Teague
Michael J. Wortley
James R. Ball
John-Paul Munfa
Meg A. Gentle
Sean T. Klimczak
Lon McCain
Philip Meier
Vincent Pagano, Jr.
Oliver G. Richard, III
Age
61
51
39
65
33
41
39
67
56
65
63
Position with Our General Partner
Chairman of the Board and Interim Chief Executive Officer
Director, President and Chief Operating Officer
Director, Senior Vice President and Chief Financial Officer
Director
Director
Director
Director
Director
Director
Director
Director
Neal A. Shear is Chairman of the Board and Interim Chief Executive Officer of our general partner and has held such
positions since December 13, 2015. Mr. Shear serves as director, Interim Chief Executive Officer and President of Cheniere. He
also serves as Chairman of the Board, Interim Chief Executive Officer and President of Cheniere Holdings. He is also Interim
Chief Executive Officer of SPL and Interim Chief Executive Officer and Manager of the general partner of SPLNG. Mr. Shear
is currently a partner of Silverpeak Partners LP, a private investment company. Mr. Shear was the Chief Executive Officer of
Higgs Capital Management, a commodity focused hedge fund until September 2014. Prior to Higgs Capital Management, Mr.
Shear served as Global Head of Securities at UBS Investment Bank from January 2010 to March of 2011. From May 2008 to
December 2009, Mr. Shear was a Partner at Apollo Global Management, LLC, where he served as the Head of the Commodities
Division. Prior to Apollo Global Management, Mr. Shear spent 26 years at Morgan Stanley serving in various roles including
Head of the Commodities Division, Global Head of Fixed Income, Co-Head of Institutional Sales and Trading and Chair of the
Commodities Business. He currently serves on the Advisory Board of Green Key Technologies, a financial Voice over Internet
Protocol (VoIP) technology company. Mr. Shear received a B.S. from the University of Maryland, Robert H. Smith School of
Business Management in 1976 and an M.B.A. from Cornell University, Johnson School of Business in 1978. It was determined
that Mr. Shear should serve as a director of our general partner because of his knowledge of and expertise in the energy industry.
R. Keith Teague is President and Chief Operating Officer and a director of our general partner and has held such positions
since June 2008. He has served as Executive Vice President-Asset Group of Cheniere since February 2014 and served as Senior
Vice President-Asset Group of Cheniere from April 2008 to February 2014. Prior to April 2008, he served as Vice President-
Pipeline Operations since May 2006. Mr. Teague has also served as President of CQH Holdings Company, LLC (formerly known
as Cheniere Pipeline Company), a wholly owned subsidiary of Cheniere, since January 2005. In addition, Mr. Teague is a director
of Cheniere Holdings and President and a manager of SPL. Mr. Teague is also President of the general partner of SPLNG and is
responsible for the development, construction and operation of Cheniere’s LNG terminal and pipeline assets. Mr. Teague began
his career with Cheniere in February 2004 as Director of Facility Planning. Prior to joining Cheniere, Mr. Teague served as the
Director of Strategic Planning for the CMS Panhandle Companies from December 2001 until September 2003. He began his
career with Texas Eastern Transmission Corporation where he managed pipeline operations and facility expansion. Mr. Teague
received a B.S. in civil engineering from Louisiana Tech University and an M.B.A. from Louisiana State University. With Mr.
Teague’s knowledge and expertise relating to the Sabine Pass LNG terminal, it was determined that he should serve as a director
of our general partner. Mr. Teague has not held any other directorship positions in the past five years.
97
Michael J. Wortley is Chief Financial Officer and a director of our general partner and has held such positions since January
2014. Mr. Wortley is also a member of the Executive Committee. Mr. Wortley has been Senior Vice President and Chief Financial
Officer of Cheniere since January 2014. Prior to January 2014, he served as Vice President-Strategy and Risk of Cheniere since
January 2013. Prior to January 2013, he served as Vice President-Business Development of Cheniere and President of Corpus
Christi Liquefaction, LLC, a wholly owned subsidiary of Cheniere, since September 2011. Prior to September 2011, Mr. Wortley
served as Cheniere’s Vice President-Strategic Planning since January 2009 and Manager-Strategic New Business since August
2007. Prior to joining Cheniere in February 2005, Mr. Wortley spent five years in oil and gas corporate development, mergers,
acquisitions and divestitures with Anadarko Petroleum Corporation, a publicly traded oil and gas exploration and production
company. Mr. Wortley began his career as an Internal Auditor with Union Pacific Resources Corporation, a publicly traded oil
and gas exploration and production company subsequently acquired by Anadarko. Mr. Wortley is currently a director and Chief
Financial Officer of Cheniere Holdings. Mr. Wortley is also Chief Financial Officer of the general partner of SPLNG and a manager
and Chief Financial Officer of SPL. Mr. Wortley received a B.B.A. in Finance from Southern Methodist University. It was
determined that Mr. Wortley should serve as a director of our general partner because of his financial expertise and his perspective
as Chief Financial Officer of Cheniere and certain of its affiliates. Mr. Wortley has not held any other directorship positions in
the past five years.
James R. Ball is a director of our general partner, Chairman of the Executive Committee and a member of the Conflicts
Committee. Mr. Ball served as a non-executive director of Gas Strategies Group Ltd, a professional services company providing
commercial energy advisory services (“GSG”), from September 2011 to June 2013. From 1988 until August 2011, he also served
as an executive director of GSG. Since 2011, Mr. Ball has served as a senior advisor to Tachebois Limited, an energy and equities
advisory firm. Mr. Ball is a Fellow of the Energy Institute and Companion of the Institute of Gas Engineers and Managers. Mr.
Ball received a B.A. in economics from the University of Colorado and a Master of Science from City University Business School
(now Cass Business School). It was determined that Mr. Ball should serve as a director of our general partner because of his
background as an advisor in the energy industry. Mr. Ball has not held any other directorship positions in the past five years.
John-Paul Munfa is a director of our general partner and a member of the Executive Committee. Mr. Munfa is a Principal
in the Private Equity Group of Blackstone Group, an investment and advisory firm. Mr. Munfa joined Blackstone Group in 2004
and was an employee in its Restructuring & Reorganization and Private Equity Groups from 2004 to 2009. Mr. Munfa re-joined
Blackstone Group in 2011 after receiving an M.B.A. from Stanford University’s Graduate School of Business. Mr. Munfa also
received an A.B. in Economics from Harvard University. It was determined that Mr. Munfa should serve as a director of our
general partner because of his significant investment experience with Blackstone Group. Mr. Munfa has not held any other
directorship positions in the past five years.
Meg A. Gentle is a director of our general partner. Ms. Gentle is also a director of Cheniere Holdings. In addition, Ms.
Gentle has served as Executive Vice President-Marketing of Cheniere since February 2014 and served as Senior Vice President-
Marketing of Cheniere from June 2013 to February 2014. She previously served as Senior Vice President and Chief Financial
Officer of Cheniere and our general partner from March 2009 to June 2013 and Senior Vice President of our general partner from
June 2008 to March 2009. She served as Senior Vice President - Strategic Planning and Finance for Cheniere from February 2008
to March 2009. Prior to that time, she served as Cheniere’s Vice President of Strategic Planning since September 2005 and Manager
of Strategic Planning since June 2004. Prior to joining Cheniere, Ms. Gentle spent eight years in energy market development,
economic evaluation and long-range planning. She conducted international business development and strategic planning for
Anadarko Petroleum Corporation, an oil and natural gas exploration and production company, for six years and energy market
analysis for Pace Global Energy Services, an energy management and consulting firm, for two years. Ms. Gentle received her
B.A. in economics and international affairs from James Madison University and an M.B.A. from Rice University. It was determined
that Ms. Gentle should serve as a director of our general partner because of her experience with strategic planning and finance in
the energy industry and because of the perspective she brings as the former Chief Financial Officer of Cheniere, Cheniere Partners
GP and the general partner of SPLNG. Ms. Gentle has not held any other directorship positions in the past five years.
Sean T. Klimczak is a director of our general partner and a member of the Executive Committee. In addition, Mr. Klimczak
is a director of SPL. Mr. Klimczak is a Senior Managing Director in the Private Equity Group of Blackstone Group, an investment
and advisory firm. Prior to joining Blackstone Group in 2005, Mr. Klimczak was an Associate at Madison Dearborn Partners, a
private equity investment firm, from 2001 to 2003 and an employee in the Mergers & Acquisitions department of the Investment
Banking division of Morgan Stanley, a financial services firm, from 1998 to 2001. Mr. Klimczak received a B.B.A. in finance
and business economics from Notre Dame and a Master of Business Administration from Harvard Business School. It was
determined that Mr. Klimczak should serve as a director of our general partner because of his significant investment experience
with Blackstone Group. Mr. Klimczak has not held any other directorship positions in the past five years.
98
Lon McCain is a director of our general partner and serves as the Chairman of the Audit Committee and a member of the
Conflicts Committee. He was Executive Vice President and Chief Financial Officer of Ellora Energy Inc., a private, independent
exploration and production company from July 2009 to August 2010. Prior to that, he was Vice President, Treasurer and Chief
Financial Officer of Westport Resources Corporation, a publicly traded exploration and production company, from 2001 until the
sale of that company to Kerr-McGee Corporation in 2004. From 1992 until joining Westport, Mr. McCain was Senior Vice President
and Principal of Petrie Parkman & Co., an investment banking firm specializing in the oil and gas industry. From 1978 until
joining Petrie Parkman, Mr. McCain held senior financial management positions with Presidio Oil Company, Petro-Lewis
Corporation and Ceres Capital. He is currently on the board of directors of Contango Oil and Gas Company, a publicly traded oil
and natural gas exploration and production company into which Crimson Exploration, Inc. was merged effective October 2, 2013.
Mr. McCain served on the Board of Crimson Exploration, Inc. from 2005 until the merger with Contango. Mr. McCain also currently
serves on the board of directors of Continental Resources, Inc., a publicly traded oil and natural gas exploration and production
company. During the past five years, he served as a director of Transzap, Inc., a privately held provider of digital data and electronic
payment solutions. Mr. McCain received a B.S. in business administration and a Masters of Business Administration/Finance
from the University of Denver. Mr. McCain was also an Adjunct Professor of Finance at the University of Denver from 1982 to
2005. It was determined that Mr. McCain should serve as a director of our general partner because of his experience as a chief
financial officer for energy companies and his background as an investment banker in the energy industry.
Philip Meier is a director of our general partner and a member of the Executive Committee. Mr. Meier is president of Meier
Consulting LLC and is currently providing technical and project management advice to Blackstone CQP Holdco with respect to
the Liquefaction Project. From 2007 to 2012, Mr. Meier was Senior Vice President Projects with Woodside Energy, an oil and
gas company in Perth, Western Australia, where he was accountable for delivery of all Woodside construction projects (both LNG
and offshore). Prior to this, he spent 25 years with Bechtel at various levels culminating as Project Manager of Egyptian LNG
Train 2. Mr. Meier received a BSCE from Rensselaer Polytechnic Institute and an M.B.A. in Finance and International Business
from the University of Houston. It was determined that Mr. Meier should serve as a director of our general partner because of his
international experience and expertise in the LNG industry. Mr. Meier has not held any other directorship positions in the past
five years.
Vincent Pagano, Jr. is a director of our general partner and serves as Chairman of the Conflicts Committee and as a member
of the Audit Committee. Mr. Pagano served as a senior corporate partner of Simpson Thacher & Bartlett LLP, a law firm, with a
focus on capital markets transactions and public company advisory matters from 1981 until his retirement at the end of 2012. Mr.
Pagano earned his law degree, cum laude, from Harvard Law School and his B.S. in Engineering, summa cum laude, from Lehigh
University and an M.S. in Engineering from the University of California, Berkeley. It was determined that Mr. Pagano should
serve as a director of our general partner because of his capital markets expertise and his experience as an advisor to public
companies on a variety of corporate matters. Mr. Pagano currently also serves as a director of L-3 Communications Holdings,
Inc., a publicly traded defense company, and Hovnanian Enterprises, Inc., a publicly traded homebuilding company.
Oliver G. Richard, III is a director of our general partner and serves as a member of the Audit Committee and Conflicts
Committee. Mr. Richard has served as Chairman of Cleanfuel USA, an alternative vehicular fuel company, since September 2007
and, for the past five years, he has been the owner and president of Empire of the Seed LLC, a private consulting firm in
the energy and management industries. Mr. Richard served as Chairman, President and Chief Executive Officer of Columbia
Energy Group, a natural gas company, from 1995 until 2000. Mr. Richard was a Commissioner on the Federal Energy Regulatory
Commission from 1982 until 1985. Mr. Richard received a B.S. in Journalism and a J.D. from Louisiana State University and a
Master of Law in Taxation from Georgetown University. It was determined that Mr. Richard should serve as a director of our
general partner because of his extensive background in the energy industry, including his experience in both the public and private
sectors of the energy industry. Mr. Richard currently serves as a director of Buckeye Partners, L.P., a publicly traded petroleum
product pipeline and terminal company, and American Electric Power Company, Inc., a publicly traded electric utility.
Code of Ethics
Our Code of Business Conduct and Ethics covers a wide range of business practices and procedures and furthers our
fundamental principles of honesty, loyalty, fairness and forthrightness. The Code of Business Conduct and Ethics was approved
by the directors of our general partner. Our Code of Business Conduct and Ethics, which is applicable to all directors, officers
and employees of the Company, is posted at http://www.cheniere.com/about-us/cheniere-partners/governance-and-ethics/. We
also intend to post any changes to or waivers of our Code of Business Conduct and Ethics for the executive officers of our general
partner on our website.
99
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Exchange Act requires the directors and executive officers of our general partner and persons who own
more than 10% of a registered class of our equity securities to file initial reports of ownership and reports of changes in ownership
with the SEC. Such persons are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file. Based
solely on our review of the copies of such forms furnished to us and written representations from the directors and executive
officers of our general partner (or otherwise based on our knowledge), we believe that all Section 16(a) filing requirements were
met during 2015 in a timely manner.
ITEM 11.
EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Our general partner has paid no cash compensation to its executive officers since its inception. All of the executive officers
of our general partner are also executive officers of Cheniere. Cheniere compensates these officers for the performance of their
duties as executive officers of Cheniere, which includes managing our partnership. Cheniere does not allocate this compensation
between services for us and services for Cheniere and its affiliates. Instead, an affiliate of Cheniere provides us various general
and administrative services for our benefit, such as technical, commercial, regulatory, financial, accounting, treasury, tax and legal
staffing and related support services, pursuant to a services agreement for which we pay a quarterly non-accountable overhead
reimbursement charge of $2.8 million (adjusted for inflation). For a description of the services agreement, see Note 11—Related
Party Transactions of our Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
In 2007, the board of directors of our general partner adopted the Cheniere Energy Partners, L.P. Long-Term Incentive Plan
for employees, consultants and directors of our general partner, employees of its affiliates and consultants to its subsidiaries. The
purpose of the plan is to enhance attraction and retention of qualified individuals who are essential for the successful operation of
our partnership and to encourage them to align their interests with our interests through an equity ownership stake in us. The plan
allows for the grant of options, restricted units, phantom units and unit appreciation rights. Up to 1,250,000 units may be granted
under the plan. The only awards that have been granted under the plan have been made to the non-management directors of our
general partner in the form of phantom units to be settled, at the director’s election, in common units, cash or in equal amounts
over a four-year vesting period.
Compensation Committee Report
As discussed above, the board of directors of our general partner does not have a compensation committee. In fulfilling its
responsibilities, the board of directors of our general partner, acting in lieu of a compensation committee, has reviewed and discussed
the Compensation Discussion and Analysis with management. Based on this review and discussion, the board of directors of our
general partner recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.
By the members of the board of directors of our general partner:
Neal A. Shear
R. Keith Teague
Michael J. Wortley
James R. Ball
John-Paul Munfa
Meg A. Gentle
Sean T. Klimczak
Lon McCain
Philip Meier
Vincent Pagano, Jr.
Oliver G. Richard, III
100
Compensation Committee Interlocks and Insider Participation
As discussed above, the board of directors of our general partner does not have a compensation committee. If any
compensation is to be paid to our general partners’ officers, the compensation would be reviewed and approved by the entire board
of directors of our general partner because they perform the functions of a compensation committee in the event such committee
is needed. Other than Mr. Shear who served as Chairman of the compensation committee of Cheniere, none of the directors or
executive officers of our general partner served as a member of a compensation committee of another entity that has or has had
an executive officer who served as a member of the board of directors of our general partner during 2015.
Director Compensation
On July 22, 2014, the board of directors of our general partner approved an annual fee of $70,000 to each non-management
director of our general partner for services as a director effective pro-rata as of the date of the approval. Also approved were annual
fees of $30,000 for the chairman of the audit committee; $15,000 for the members of the audit committee other than the chairman;
$10,000 for the chairman of the conflicts committee; $2,500 per meeting for the members of the conflicts committee, including
the chairman; $10,000 for the chairman of the executive committee; and $2,500 per meeting for the non-employee members of
the executive committee, including the chairman. All directors’ fees are pro-rated from the date of election to the board and are
payable quarterly.
In addition to the annual fees paid to the non-management directors, when they joined the board of directors Messrs. Ball,
McCain, Pagano and Richard each received 12,000 phantom units pursuant to the terms of the Cheniere Energy Partners, L.P.
Long-Term Incentive Plan. The grant date for each grant is as follows: May 29, 2007 for Mr. McCain, September 7, 2012 for
Messrs. Ball and Richard and December 7, 2012 for Mr. Pagano. Each of these directors will receive an additional 3,000 phantom
units annually on each anniversary of the grant date. Vesting will occur for one-fourth of the phantom units on each anniversary
of the grant date beginning on the first anniversary of the grant date. Upon vesting, the phantom units will be payable, at the
director’s election, in common units, cash in an amount equal to the fair market value of a common unit on such date, or an equal
amount of both. The directors receive no distributions, and no distributions accrue, on the outstanding phantom units. Mr. Foley
and Mr. Klimczak serve as Senior Managing Director and Mr. Munfa serves as a Managing Director, in the Private Equity Group
of Blackstone Group, and they do not receive additional compensation for service as directors. Mr. Meier and Meier Consulting
LLC entered into a letter agreement, dated June 14, 2013 (the “Meier Consulting Letter Agreement”), with Blackstone CQP Holdco
pursuant to which Mr. Meier agreed to provide consulting services to Blackstone CQP Holdco relating to the development,
construction and operation of the Liquefaction Project. For a further description of the Meier Consulting Letter Agreement, see
“Related-Party Transactions-Arrangements involving Mr. Meier and Meier Consulting LLC” below. Mr. Meier receives no
additional compensation for service as a director.
The following table shows the compensation paid for service as a member of the board of directors of our general partner
for the 2015 fiscal year:
Name
Neal A. Shear (2)
R. Keith Teague (2)
Michael J. Wortley (2)
James R. Ball (3)
David I. Foley (4)
Meg A. Gentle (2)
Sean T. Klimczak (4)
Lon McCain (5)
Philip Meier (6)
John-Paul Munfa (4)
Vincent Pagano, Jr. (7)
Oliver G. Richard, III (8)
Charif Souki (2)
Fees
Earned
or Paid
in Cash
Unit
Awards (1)
Option
Awards
Non-Equity
Incentive Plan
Compensation
Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings
All Other
Compensation
Total
$
— $
—
—
85,000
— $
—
—
87,360
— $
—
—
—
— $
—
—
—
— $
—
—
—
— $
—
—
—
—
—
—
172,360
—
—
100,000
—
—
95,000
85,000
—
—
—
99,570
—
—
65,610
87,360
—
—
—
—
—
—
—
—
—
101
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
199,570
—
—
160,610
172,360
—
(1) Reflects aggregate grant date fair value. The phantom units are to be settled, at the director’s election, in common units,
cash, or an equal amount of both. The units are valued using the closing unit price on the date of grant and are revalued
on a quarterly basis through the date of vesting.
(2) Mr. Teague served as an executive officer of our general partner and as an executive officer of Cheniere during fiscal
year 2015. Ms. Gentle served as an executive officer of Cheniere during fiscal year 2015. Mr. Wortley served as an
executive officer of our general partner and as an executive officer of Cheniere during fiscal year 2015. Mr. Shear served
as an executive officer of our general partner since December 13, 2015 and as an executive officer of Cheniere since
December 12, 2015. Mr. Souki served as an executive officer of our general partner from January 1 until December 13,
2015 and as an executive officer of Cheniere from January 1 until December 12, 2015. Cheniere compensates these
officers for the performance of their duties as executive officers of Cheniere, which includes managing our partnership.
They do not receive additional compensation for service as directors.
(3) Mr. Ball was granted 3,000 phantom units in 2015 with a grant date fair value of $87,360. In addition, Mr. Ball received
$87,360 in cash and 1,500 common units on account of 4,500 phantom units granted in earlier years that vested in 2015.
As of December 31, 2015, he held 9,750 phantom units and 2,250 common units for a total of 12,000 units.
(4) Messrs. Foley and Klimczak serve as Senior Managing Directors, and Mr. Munfa is a Managing Director, in the Private
Equity Group of Blackstone Group. They do not receive additional compensation for service as directors.
(5) Mr. McCain was granted 3,000 phantom units in 2015 with a grant date fair value of $99,570. In addition, Mr. McCain
received $74,678 in cash and 750 common units on account of 3,000 phantom units granted in earlier years that vested
in 2015. As of December 31, 2015, he held 7,500 phantom units and 750 common units for a total of 8,250 units.
(6) Mr. Meier is compensated by Blackstone CQP Holdco pursuant to the Meier Consulting Letter Agreement and received
no additional compensation for service as a director. For a further description of the Meier Consulting Letter Agreement,
see “Related-Party Transactions-Arrangements involving Mr. Meier and Meier Consulting LLC” below.
(7) Mr. Pagano was granted 3,000 phantom units in 2015 with a grant date fair value of $65,610. In addition, Mr. Pagano
received $82,013 in cash and 750 common units on account of 4,500 phantom units granted in earlier years that vested
in 2015. As of December 31, 2015, he held 9,750 phantom units and 1,125 common units for a total of 10,875 units.
(8) Mr. Richard was granted 3,000 phantom units in 2015 with a grant date fair value of $87,360. In addition, Mr. Richard
received $109,200 in cash and 750 common units on account of 4,500 phantom units granted in earlier years that vested
in 2015. As of December 31, 2015, he held 9,750 phantom units and 750 common units for a total of 10,500 units.
Indemnification of Directors
We have entered into indemnification agreements with each of our directors, which provide for indemnification with respect
to all expenses and claims that a director incurs as a result of actions taken, or not taken, on our behalf while serving as a director,
officer, employee, controlling person, agent or fiduciary of Cheniere Partners GP or any of our subsidiaries. Pursuant to the
agreements, no indemnification will generally be provided (1) for claims brought by the director, except for a claim of indemnity
under the indemnification agreement, if we approve the bringing of such claim, or if the Delaware Limited Liability Company Act
requires providing indemnification because our director has been successful on the merits of such claim, (2) for claims under
Section 16(b) of the Exchange Act, or (3) if there has been a final judgment entered by a court determining that the director acted
in bad faith, engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct
was unlawful. Indemnification will be provided to the extent permitted by law, Cheniere Partners GP’s certificate of formation
and limited liability company agreement, and to a greater extent if, by law, the scope of coverage is expanded after the date of the
indemnification agreements. In all events, the scope of coverage will not be less than what was in existence on the date of the
indemnification agreements.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND
RELATED UNITHOLDER MATTERS
The limited partner interest in our partnership is divided into units. As of February 12, 2016, the following units were
outstanding: 57,103,598 common units, 135,383,831 subordinated units and 145,333,334 Class B units. In addition, as of
February 12, 2016, there were 6,893,811 general partner units outstanding.
102
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the
determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner”
of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security,
or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed
to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under
these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a
beneficial owner of securities as to which he has no economic interest.
Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect
to all units shown as beneficially owned by them, subject to community property laws where applicable. Except as indicated by
footnote, the address for the beneficial owners listed below is 700 Milam Street, Suite 1900, Houston, Texas 77002.
Owners of More than Five Percent of Outstanding Units
The following table shows the beneficial owners known by us to own more than five percent of our common units, Class
B units, subordinated units and/or general partner units as of February 12, 2016:
Name of Beneficial Owner
Cheniere Energy, Inc. (1)
Common
Units
Beneficially
Owned
11,963,488
Cheniere Energy Partners LP Holdings, LLC
11,963,488
Blackstone Group (2)
Blackstone CQP Holdco
UBS Group AG (3)
Percentage
of
Common
Units
Beneficially
Owned
Class B Units
Beneficially
Owned
Percentage of
Class B Units
Beneficially
Owned
Subordinated
Units
Beneficially
Owned
Percentage
of
Subordinated
Units
Beneficially
Owned
Percentage
of Total
Securities
Beneficially
Owned
21% 45,333,334
21% 45,333,334
7%
—
3,758,003
—
—% 100,000,000
2,855,220
5%
—
31% 135,383,831
31% 135,383,831
—%
69%
—
—
—
—
100%
100%
—
—
—
58%
56%
1%
29%
1%
(1) Cheniere Energy, Inc. is the parent company of Cheniere Energy Partners LP Holdings, LLC and may, therefore, be deemed
to beneficially own the units held by Cheniere Energy Partners LP Holdings, LLC. Cheniere Energy, Inc. owns approximately
80% of the outstanding common shares of Cheniere Energy Partners LP Holdings, LLC, as well as the sole share of that
entity authorized to elect its directors. Cheniere Energy, Inc. also owns 6,893,811 of our general partner units.
(2)
(3)
Information is based solely on a Schedule 13D/A filed with the SEC on January 15, 2016 by the Blackstone Group, L.P.,
Blackstone CQP Common Holdco L.P., Blackstone CQP Common Holdco GP LLC, Blackstone Energy Management
Associates L.L.C., Blackstone EMA L.L.C., Blackstone Management Associates VI L.L.C., BMA VI L.L.C., Blackstone
Holdings III L.P., Blackstone Holdings III GP L.P., Blackstone Holdings III GP Management L.L.C., GSO Credit Alpha
Fund AIV-2 LP, GSO Coastline Credit Partners LP, GSO Credit-A Partners LP, GSO Palmetto Opportunistic Investment
Partners LP, GSO Special Situations Fund LP, GSO Special Situations Master Fund LP, GSO Special Situations Overseas
Master Fund Ltd., Blackstone Holdings I L.P., Blackstone Holdings II L.P., Blackstone Holdings I/II GP Inc., GSO Capital
Partners LP, GSO Advisor Holdings LLC, GSO Palmetto Opportunistic Associates LLC, GSO Credit-A Associates LLC,
GSO Holdings I L.L.C., Blackstone Group Management L.L.C., Stephen A. Schwarzman, Bennett J. Goodman and J. Albert
Smith III. Blackstone CQP Common Holdco L.P. is the record holder of 1,101,169 common units. GSO Coastline Credit
Partners LP, GSO Credit-A Partners LP and GSO Palmetto Opportunistic Investment Partners LP are the record holders of
53,057, 963,855 and 963,855 common units, respectively. GSO Credit Alpha Fund AIV-2 LP is the record owner of 383,747
common units. GSO Special Situations Fund LP, GSO Special Situations Master Fund LP and GSO Special Situations
Overseas Master Fund Ltd. are the record holders of 95,696, 96,943 and 99,681 common units, respectively. The address
of the various persons identified in this footnote is 345 Park Avenue, New York, New York 10154.
Information is based on a Schedule 13G filed with the SEC on February 9, 2016 by UBS Group AG directly and on behalf
of certain subsidiaries, UBS AG London Branch, UBS Financial Services Inc., and UBS Securities LLC. UBS Group AG
has shared power to vote and dispose of the shares beneficially owned. The address of UBS Group AG is Bahnhofstrasse
45, PO Box CH-8021, Zurich, Switzerland.
Directors and Executive Officers
The following table sets forth information with respect to our common units owned of record and beneficially as of
February 12, 2016, by each director and executive officer of our general partner and by all directors and executive officers of our
general partner as a group. On February 12, 2016, the directors and executive officers of Cheniere Partners beneficially owned
an aggregate of 418,010 common units (approximately 1% of the outstanding common units at the time).
103
The table also presents the ownership of common shares of Cheniere Energy Partners LP Holdings, LLC and shares of
common stock of Cheniere Energy, Inc. owned of record or beneficially as of February 12, 2016, by each director and executive
officer of our general partner and by all directors and executive officers of our general partner as a group. Cheniere Energy Partners
LP Holdings, LLC owns a majority interest in Cheniere Partners. Cheniere Energy, Inc. owns a majority interest in Cheniere
Energy Partners LP Holdings, LLC. As of February 12, 2016, Cheniere Energy Partners LP Holdings, LLC had 231,700,000
common shares outstanding and Cheniere Energy, Inc. had 235,634,507 shares of common stock outstanding.
Cheniere Energy Partners, L.P.
Cheniere Energy Partners LP
Holdings, LLC
Cheniere Energy, Inc.
Amount and
Nature of
Beneficial
Ownership
Percent
of Class
Amount and Nature of
Beneficial Ownership
Percent
of Class
Amount and Nature of
Beneficial Ownership
Percent
of Class
Name of Beneficial Owner
Neal A. Shear (1)
Charif Souki (1)
R. Keith Teague
Meg A. Gentle
James R. Ball
David I. Foley (3)
John-Paul Munfa (3)
Sean T. Klimczak (3)
Lon McCain
Vincent Pagano, Jr.
Michael J. Wortley
Philip Meier (3)
Oliver G. Richard, III
—
400,100 (2)
—
1%
—
8,035
2,250
—
—
750
1,125
5,000
—
750
—
*
*
—
—
*
*
*
—
*
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
8,697
2,983,026
613,158
1,351,907
—
—
—
—
—
422,005 (4)
—
—
*
1%
*
1%
—
—
—
—
—
*
—
—
5,378,793
2%
All directors and executive officers as a
group (13 persons)
418,010
1%
*
(1)
(2)
(3)
Less than 1%
As of December 13, 2015, Mr. Shear was appointed as Chairman of the Board and interim Chief Executive Officer of
our general partner, replacing Mr. Souki.
Includes 400,100 units held by Mr. Souki’s wife.
Messrs. Foley, Munfa, Klimczak and Meier were appointed as directors of our general partner pursuant to the rights of
Blackstone CQP Holdco under the Third Amended and Restated Limited Liability Company Agreement of our general
partner to appoint certain directors to the board of directors of our general partner.
(4)
Includes 1,500 shares issuable upon exercise of currently exercisable stock options held by Mr. Wortley.
Equity Compensation Plan Information
In 2007, the board of directors of our general partner adopted the Cheniere Energy Partners, L.P. Long-Term Incentive Plan.
The following table provides certain information as of December 31, 2015 with respect to this plan:
Plan Category
Equity compensation plans approved by security
holders
Equity compensation plans not approved by
security holders
Total
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights (1)
Weighted-
average exercise price of
outstanding
options, warrants and
rights
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding securities
reflected in the first
column) (2)
—
19,125
19,125
N/A
N/A
N/A
—
1,231,250
1,231,250
(1)
The phantom units that have been granted are payable, at the director’s election, in common units, in cash at the time of
vesting in an amount equal to the fair market value of a common unit on such date or an equal amount of both.
104
(2)
The number of securities remaining available for issuance does not include securities reserved for issuance upon the vesting
of unvested phantom units issued to directors for which such directors have made an irrevocable election to receive common
units in lieu of cash.
For more information regarding the Long-Term Incentive Plan, see “Compensation Discussion and Analysis.”
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Related-Party Transactions
Prior to the completion of our initial public offering of common units in 2007, the managers of our general partner approved
the distributions and payments to be made to our general partner and its affiliates in connection with our ongoing operations and,
in the event of, our liquidation. During our operational stage, we will generally make cash distributions to our unitholders, including
our affiliates, as described in Part II, Item 5, of this annual report on Form 10-K. Upon our liquidation, our partners, including
our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
Procedures for Review, Approval and Ratification of Transactions with Related Persons
Under the audit committee charter, the audit committee of our general partner is required to review and approve all
transactions or series of related financial transactions, arrangements or relationships between the partnership and any related-party,
if the amount involved exceeds $120,000 and such transactions have not been reviewed by the conflicts committee of our general
partner. The following related-party transactions are in addition to those related-party transactions described in Note 11—Related
Party Transactions of our Notes to Consolidated Financial Statements which is herein incorporated by reference. Except as
described below, such related-party transactions were approved by the members of the board of directors of our general partner,
which includes each member of the audit committee.
In determining whether to approve or ratify a related party transaction, the audit committee of our general partner will apply
the following standards and such other standards it deems appropriate:
(cid:129) whether the related party transaction is on terms no less favorable than the terms generally available to an unaffiliated
third-party under the same or similar circumstances;
(cid:129) whether the transaction is material to the Company or the related party; and
(cid:129)
the extent of the related person’s interest in the transaction.
In addition, pursuant to our Code of Business Conduct and Ethics approved by the board of directors of our general partner,
the directors, officers and employees of our general partner are expected to bring to the attention of the Chief Compliance Officer
any conflict or potential conflict of interest. If a conflict or potential conflict of interest arises between us and a director, officer
or any of our affiliates, the resolution of any such conflict or potential conflict should be addressed by the board in accordance
with the provisions of our limited partnership agreement.
ISDA Master Agreement
In September 2007, Cheniere Marketing and SPLNG entered into an International Swaps and Derivatives Association
(“ISDA”) Master Agreement that provides SPLNG with the ability to hedge its future price risk from time to time. The ISDA
Master Agreement was entered into in the event SPLNG chooses to hedge some of its LNG purchases or gas sales and elects to
implement such hedges through Cheniere Marketing, which already has ISDA agreements in place with third parties and accounts
with futures brokers. There are no current transactions under this agreement. No amounts were paid to Cheniere Marketing under
this agreement during the year ended December 31, 2015.
LNG Terminal Export Agreement
In January 2010, SPLNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere
Marketing the ability to export LNG from the Sabine Pass LNG terminal. SPLNG did not record any revenues associated with
this agreement in the year ended December 31, 2015.
The following related-party transactions were not approved by the board of directors or audit committee of our general
partner:
105
Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”)
In July 2007, SPLNG executed CEAs with various Cameron Parish, Louisiana taxing authorities and a related agreement
with Cheniere Marketing, as described in Note 11—Related Party Transactions of our Notes to Consolidated Financial Statements.
During the year ended December 31, 2015, Cheniere Marketing paid Sabine Pass LNG $2.5 million under the agreement.
Arrangements involving Mr. Meier and Meier Consulting LLC
As noted above, Blackstone CQP Holdco, Mr. Meier and Meier Consulting LLC entered into the Meier Consulting Letter
Agreement, pursuant to which Mr. Meier agreed to provide consulting services to Blackstone CQP Holdco relating to the
development, construction and operation of the Liquefaction Project. As compensation for the consulting services, Blackstone
CQP Holdco agreed to pay Mr. Meier an annual base consulting fee of $375,000 per year and an annual performance consulting
fee of up to $200,000 per year in Blackstone CQP Holdco’s discretion. The annual performance consulting fee with respect to
2015 was $125,000. The consulting arrangement between Blackstone CQP Holdco and Mr. Meier may be terminated by Blackstone
for cause or by either party upon 30 days’ advance written notice.
In addition, Blackstone CQP Holdco agreed to pay Mr. Meier the following fees upon the substantial completion of each
of Trains 1 through 4 of the Liquefaction Project, provided Mr. Meier continues to provide consulting services through such time:
(a) upon the substantial completion of Train 1, an amount equal to the product of (1) 83,333, (2) 15% and (3) the fair market value
of one of our common units as of that date; (b) upon the substantial completion of Train 2, an amount equal to the product of
(1) 83,333, (2) 15% and (3) the fair market value of one of our common units as of that date; (c) upon the substantial completion
of Train 3, an amount equal to the product of (1) 83,333, (2) 30% and (3) the fair market value of one of our common units as of
that date; and (d) upon the substantial completion of Train 4, an amount equal to (1) the product of 83,333 and the fair market
value of one of our common units as of that date, less (2) the sum of all payments made with respect to the substantial completion
of each of Trains 1 through 3.
We entered into a letter agreement with Blackstone CQP Holdco (the “Blackstone Consultant Letter Agreement”), dated
June 23, 2013, pursuant to which we agreed to reimburse Blackstone CQP Holdco for (a) 25% of the fees of Mr. Meier described
in the Meier Consulting Letter Agreement and (b) 25% of the expenses of Mr. Meier incurred in connection with his consulting
services relating to the Liquefaction Project which are either to be paid or reimbursed by Blackstone CQP Holdco pursuant to the
Meier Consulting Letter Agreement. We did not reimburse Blackstone CQP Holdco for any fees and expenses with respect to
2015 under the Blackstone Consultant Letter Agreement.
Independent Directors
Because we are a limited partnership, the NYSE MKT does not require our general partner’s board of directors to be
composed of a majority of directors who meet the criteria for independence required by NYSE MKT. The board of our general
partner has determined that Messrs. Ball, McCain, Pagano and Richard are independent directors in accordance with the following
NYSE MKT independence standards. A director would not be independent if any of the following relationships exists:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
a director who is, or during the past three years was, employed by the partnership, general partner or by any parent or
subsidiary of the partnership or general partner, other than prior employment as an interim executive officer (provided
the interim employment did not last longer than one year);
a director who accepts, or has an immediate family member who accepts, any compensation from the partnership, general
partner or any parent or subsidiary of the partnership or general partner in excess of $120,000 during any twelve
consecutive-month period within the three years preceding the determination of independence, other than compensation
for board or committee services, or compensation paid to an immediate family member who is a non-executive employee
of the partnership, general partner or any parent or subsidiary of the partnership or general partner, among other exceptions;
a director who is an immediate family member of an individual who is, or at any time during the past three years was,
employed by the partnership, general partner or any parent or subsidiary of the partnership or general partner as an
executive officer;
a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive
officer of, any organization to which the partnership, general partner or any parent or subsidiary of the partnership or
general partner made, or from which the partnership, general partner or any parent or subsidiary of the partnership or
106
general partner received, payments (other than those arising solely from investments in our common units or payments
under non-discretionary charitable contribution matching programs) that exceed 5% of the organization’s consolidated
gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years;
a director who is, or has an immediate family member who is, employed as an executive officer of another entity where
at any time during the most recent three fiscal years any of the executive officers of the partnership, general partner or
any parent or subsidiary of the partnership or general partner serves on the compensation committee of such other entity;
or
a director who is, or has an immediate family member who is, a current partner of the outside auditor of the partnership,
general partner or parent or subsidiary of the partnership or general partner, or was a partner or employee of the outside
auditor of the partnership, general partner or any parent or subsidiary of the partnership or general partner who worked
on our audit at any time during any of the past three years.
(cid:129)
(cid:129)
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
KPMG LLP served as our independent auditor for the fiscal year ended December 31, 2015 and 2014. The following table
(in thousands) sets forth the fees paid to KPMG LLP for professional services rendered for 2015 and 2014:
Audit Fees
Fiscal 2015
Fiscal 2014
$
2,505
$
2,265
Audit Fees—Audit fees for 2015 and 2014 include fees associated with the integrated audit of our annual Consolidated
Financial Statements, reviews of our interim Consolidated Financial Statements and services performed in connection with
registration statements and debt offerings, including comfort letters and consents.
Audit-Related Fees—There were no audit-related fees in 2015 and 2014.
Tax Fees—There were no tax fees in 2015 and 2014.
Other Fees—There were no other fees in 2015 and 2014.
Auditor Pre-Approval Policy and Procedures
Under the audit committee’s charter, the audit committee is required to review and approve in advance all audit and lawfully
permitted non-audit services to be provided by the independent accountants and the fees for such services. Pre-approval of non-
audit services (other than review and attestation services) shall not be required if such services fall within exceptions established
by the SEC. All audit and non-audit services provided to us during the fiscal years ended December 31, 2015 and 2014 were pre-
approved.
107
PART IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
Financial Statements and Exhibits
(1)
Financial Statements—Cheniere Energy Partners, L.P.:
Management’s Report to the Unitholders of Cheniere Energy Partners, L.P.
Reports of Independent Registered Public Accounting Firm—KPMG LLP
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Loss
Consolidated Statements of Partners’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements—Quarterly Financial Data
56
57
59
60
61
62
63
64
65
93
(2)
Financial Statement Schedules:
Schedule I—Condensed Financial Information of Registrant for the years ended December 31, 2015, 2014 and 2013
119
(3)
Exhibits:
Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions
by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations,
warranties, covenants and conditions:
(cid:129)
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;
(cid:129) 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;
(cid:129) may apply standards of materiality that differ from those of a reasonable investor; and
(cid:129) were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed
circumstances.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made
or at any other time. These agreements are included to provide you with information regarding their terms and are not intended
to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should
not rely on them as statements of fact.
Exhibit No.
2.1
Description
Contribution and Conveyance Agreement (Incorporated by reference to Exhibit 10.4 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on March 26, 2007)
2.2
Amended and Restated Purchase and Sale Agreement, dated as of August 9, 2012, by and among Cheniere
Energy Partners, L.P., Cheniere Pipeline Company, Grand Cheniere Pipeline, LLC and Cheniere Energy, Inc.
(Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No.
001-33366), filed on August 9, 2012)
108
Exhibit No.
3.1
Description
Certificate of Limited Partnership of Cheniere Energy Partners, L.P. (Incorporated by reference to Exhibit 3.1
to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on December 21,
2006)
3.2
3.3
3.4
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
10.1
Third Amended and Restated Agreement of Limited Partnership of Cheniere Energy Partners, L.P., dated as
of August 9, 2012 (Incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K
(SEC File No. 001-33366), filed on August 9, 2012)
Certificate of Formation of Cheniere Energy Partners GP, LLC (Incorporated by reference to Exhibit 3.3 to the
Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on December 21, 2006)
Third Amended and Restated Limited Liability Company Agreement of Cheniere Energy Partners GP, LLC,
dated as of August 9, 2012 (Incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on
Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
Form of common unit certificate (Included as Exhibit A to Exhibit 3.2 above)
Indenture, dated as of November 9, 2006, by and among Sabine Pass LNG, L.P., as issuer, the guarantors as
defined therein and The Bank of New York, as trustee (Incorporated by reference to Exhibit 4.1 to Cheniere’s
Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
Form of 7.50% Senior Secured Note due 2016 (Included as Exhibit A1 to Exhibit 4.2 above)
Indenture, dated as of October 16, 2012, by and among Sabine Pass LNG, L.P., the guarantors that may become
party thereto from time to time and The Bank of New York Mellon, as trustee (Incorporated by reference to
Exhibit 4.1 to SPLNG’s Current Report on Form 8-K (SEC File No. 333-138916), filed on October 19, 2012)
Form of 6.5% Senior Secured Note due 2020 (Included as Exhibit A1 to Exhibit 4.4 above)
Indenture, dated as of February 1, 2013, by and among Sabine Pass Liquefaction, LLC, the guarantors that
may become party thereto from time to time and The Bank of New York Mellon, as trustee (Incorporated by
reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on
February 4, 2013)
Form of 5.625% Senior Secured Note due 2021 (Included as Exhibit A-1 to Exhibit 4.6 above)
First Supplemental Indenture, dated as of April 16, 2013, between Sabine Pass Liquefaction, LLC and The
Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1.1 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on April 16, 2013)
Second Supplemental Indenture, dated as of April 16, 2013, between Sabine Pass Liquefaction, LLC and The
Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1.2 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on April 16, 2013)
Form of 5.625% Senior Secured Note due 2023 (Included as Exhibit A-1 to Exhibit 4.9 above)
Third Supplemental Indenture, dated as of November 25, 2013, between Sabine Pass Liquefaction, LLC and
The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on November 25, 2013)
Form of 6.25% Senior Secured Note due 2022 (Included as Exhibit A-1 to Exhibit 4.11 above)
Fourth Supplemental Indenture, dated as of May 20, 2014, between Sabine Pass Liquefaction, LLC and The
Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2014)
Form of 5.750% Senior Secured Note due 2024 (Included as Exhibit A-1 to Exhibit 4.13 above)
Fifth Supplemental Indenture, dated as of May 20, 2014, between Sabine Pass Liquefaction, LLC and The
Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.2 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2014)
Form of 5.625% Senior Secured Note due 2023 (Included as Exhibit A-1 to Exhibit 4.15 above)
Sixth Supplemental Indenture, dated as of March 3, 2015, between Sabine Pass Liquefaction, LLC and The
Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on March 3, 2015)
Form of 5.625% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.17 above)
LNG Terminal Use Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine
Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Cheniere’s Quarterly Report on Form 10-Q (SEC
File No. 001-16383), filed on November 15, 2004)
109
Exhibit No.
10.2
Description
Amendment of LNG Terminal Use Agreement, dated January 24, 2005, by and between Total LNG USA, Inc.
and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.40 to Cheniere’s Annual Report on Form
10-K (SEC File No. 001-16383), filed on March 10, 2005)
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
Amendment of LNG Terminal Use Agreement, dated June 15, 2010, by and between Total Gas & Power North
America, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to Cheniere’s Quarterly
Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)
Omnibus Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG,
L.P. (Incorporated by reference to Exhibit 10.2 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No.
001-16383), filed on November 15, 2004)
Parent Guarantee, dated as of November 5, 2004, by Total S.A. in favor of Sabine Pass LNG, L.P. (Incorporated
by reference to Exhibit 10.3 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed
on November 15, 2004)
Letter Agreement, dated September 11, 2012, between Total Gas & Power North America, Inc. and Sabine
Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-
Q (SEC File No. 001-33366), filed on November 2, 2012)
LNG Terminal Use Agreement, dated November 8, 2004, between Chevron U.S.A. Inc. and Sabine Pass LNG,
L.P. (Incorporated by reference to Exhibit 10.4 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No.
001-16383), filed on November 15, 2004)
Amendment to LNG Terminal Use Agreement, dated December 1, 2005, by and between Chevron U.S.A., Inc.
and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.28 to SPLNG’s Registration Statement
on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)
Amendment of LNG Terminal Use Agreement, dated June 16, 2010, by and between Chevron U.S.A. Inc. and
Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.3 to Cheniere’s Quarterly Report on Form 10-
Q (SEC File No. 001-16383), filed on August 6, 2010)
Omnibus Agreement, dated November 8, 2004, between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P.
(Incorporated by reference to Exhibit 10.5 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No.
001-16383), filed on November 15, 2004)
Guaranty Agreement, dated as of December 15, 2004, from ChevronTexaco Corporation to Sabine Pass LNG,
L.P. (Incorporated by reference to Exhibit 10.12 to SPLNG’s Registration Statement on Form S-4 (SEC File
No. 333-138916), filed on November 22, 2006)
Second Amended and Restated LNG Terminal Use Agreement, dated as of July 31, 2012, between Sabine Pass
LNG, L.P. and Sabine Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.1 to SPLNG’s Current
Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
Letter Agreement, dated May 28, 2013, by and between Sabine Pass LNG, L.P. and Sabine Pass Liquefaction,
LLC (Incorporated by reference to Exhibit 10.1 to SPLNG’s Quarterly Report on Form 10-Q (SEC File No.
333-138916), filed on August 2, 2013)
Guarantee Agreement, dated as of July 31, 2012, by Cheniere Energy Partners, L.P. in favor of Sabine Pass
LNG, L.P. (Incorporated by reference to Exhibit 10.2 to SPLNG’s Current Report on Form 8-K (SEC File No.
333-138916), filed on August 6, 2012)
Collateral Trust Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New
York, as collateral trustee, Sabine Pass LNG-GP, Inc. and Sabine Pass LNG-LP, LLC (Incorporated by reference
to Exhibit 10.1 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16,
2006)
Amended and Restated Parity Lien Security Agreement, dated November 9, 2006, by and between Sabine Pass
LNG, L.P. and The Bank of New York, as collateral trustee (Incorporated by reference to Exhibit 10.2 to
Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
Third Amended and Restated Multiple Indebtedness Mortgage, Assignment of Rents and Leases and Security
Agreement, dated November 9, 2006, by Sabine Pass LNG, L.P. to and for the benefit of The Bank of New
York, as collateral trustee (Incorporated by reference to Exhibit 10.3 to Cheniere’s Current Report on Form 8-
K (SEC File No. 001-16383), filed on November 16, 2006)
Amended and Restated Parity Lien Pledge Agreement, dated November 9, 2006, by and among Sabine Pass
LNG, L.P., Sabine Pass LNG-GP, Inc., Sabine Pass LNG-LP, LLC and The Bank of New York, as collateral
trustee (Incorporated by reference to Exhibit 10.4 to Cheniere’s Current Report on Form 8-K (SEC File No.
001-16383), filed on November 16, 2006)
110
Exhibit No.
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28†
10.29†
10.30†
10.31†
Description
Security Deposit Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of
New York, as collateral trustee, and The Bank of New York, as depositary agent (Incorporated by reference to
Exhibit 10.5 to Cheniere’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16,
2006)
Second Amended and Restated Credit Agreement (Term Loan A), dated as of June 30, 2015, among Sabine
Pass Liquefaction, LLC, as Borrower, Société Générale, as the Commercial Banks Facility Agent and the
Common Security Trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit
10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, among Sabine Pass
Liquefaction, LLC, as Borrower, the representatives and agents from time to time parties thereto, and Société
Générale, as the Common Security Trustee and Intercreditor Agent (Incorporated by reference to Exhibit 10.2
to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
Amended and Restated KSURE Covered Facility Agreement, dated as of June 30, 2015, among Sabine Pass
Liquefaction, LLC, as Borrower, The Korea Development Bank, New York Branch, as the KSURE Covered
Facility Agent, Société Générale, as the Common Security Trustee, and the lenders from time to time party
thereto (Incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K (SEC File
No. 001-33366), filed on July 1, 2015)
KEXIM Direct Facility Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as
Borrower, Shinhan Bank New York Branch, as the KEXIM Facility Agent, Société Générale, as the Common
Security Trustee, and The Export-Import Bank of Korea, a governmental financial institution of the Republic
of Korea (“KEXIM”), as the KEXIM Direct Facility Lender, Joint Lead Arranger and Joint Lead Bookrunner
(Incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No.
001-33366), filed on July 1, 2015)
KEXIM Covered Facility Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as
Borrower, Shinhan Bank New York Branch, as the KEXIM Facility Agent, Société Générale, as the Common
Security Trustee, KEXIM and the lenders from time to time party thereto (Incorporated by reference to Exhibit
10.4 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
Omnibus Amendment, dated as of September 24, 2015, to the Second Amended and Restated Common Terms
Agreement among Sabine Pass Liquefaction, LLC, as Borrower, the representatives and agents from time to
time parties thereto, and Société Générale, as the Common Security Trustee and Intercreditor Agent
(Incorporated by reference to Exhibit 10.6 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No.
001-33366), filed on October 30, 2015)
Credit Agreement, dated as of May 28, 2013, among Cheniere Creole Trail Pipeline, L.P., as borrower, the
lenders party thereto from time to time, Morgan Stanley Senior Funding, Inc., as administrative agent, The
Bank of New York Mellon, as collateral agent, and The Bank of New York Mellon, as depositary bank
(Incorporated by reference to Exhibit 10.6 to the Partnership’s Current Report on Form 8-K (SEC File No.
001-33366), filed on May 29, 2013)
Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement
Agreement, dated as of September 4, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, The Bank of
Nova Scotia, as Senior Issuing Bank and Senior Facility Agent, ABN Amro Capital USA LLC, HSBC Bank
USA, National Association and ING Capital LLC, as Senior Issuing Banks, Société Générale, as Swing Line
Lender and Common Security Trustee, and the senior lenders party thereto from time to time (Incorporated by
reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on
September 11, 2015)
Form of Director Units Option Agreement for employees and consultants (four-year) (Incorporated by reference
to Exhibit 10.41 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on
March 2, 2007)
Form of Phantom Units Agreement for employees, consultants and directors (four-year) (Incorporated by
reference to Exhibit 10.44 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572),
filed on March 2, 2007)
Form of Phantom Units Agreement for employees, consultants and directors (three-year) (Incorporated by
reference to Exhibit 10.45 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572),
filed on March 2, 2007)
Form of Restricted Units Agreement for employees, consultants and directors (four-year) (Incorporated by
reference to Exhibit 10.40 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572),
filed on March 2, 2007)
111
Exhibit No.
10.32†
Description
Form of Restricted Units Agreement for employees, consultants and directors (three-year) (Incorporated by
reference to Exhibit 10.39 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572),
filed on March 2, 2007)
10.33†
10.34†
10.35†
10.36†
10.37†
10.38†
10.39†
10.40†
10.41†
Form of Units Option Agreement for employees and consultants (four-year) (Incorporated by reference to
Exhibit 10.43 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on
March 2, 2007)
Form of Units Option Agreement for employees and consultants (three-year) (Incorporated by reference to
Exhibit 10.42 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on
March 2, 2007)
Cheniere Energy Partners, L.P. 2007 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.3 to
the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 26, 2007)
Form of Phantom Units Agreement (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on June 4, 2007)
Form of Phantom Units Agreement under the Cheniere Energy Partners, L.P. Long-Term Incentive Plan (2012
Reload Award) (Incorporated by reference to Exhibit 10.9 to the Partnership’s Quarterly Report on Form 10-
Q (SEC File No. 001-33366), filed on November 2, 2012)
Form of Phantom Units Agreement under the Cheniere Energy Partners, L.P. Long-Term Incentive Plan
(Incorporated by reference to Exhibit 10.8 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No.
001-33366), filed on November 2, 2012)
Form of Amendment to Phantom Units Agreement (Incorporated by reference to Exhibit 10.7 to the
Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
Form of Phantom Units Agreement under the Cheniere Energy Partners, L.P. Long-Term Incentive Plan (Units
Settlement) (Incorporated by reference to Exhibit 10.41 to the Partnership’s Annual Report on Form 10-K
(SEC File No. 001-33366), filed on February 19, 2015)
Form of Phantom Units Agreement under the Cheniere Energy Partners, L.P. Long-Term Incentive Plan (Reload
Units Settlement) (Incorporated by reference to Exhibit 10.42 to the Partnership’s Annual Report on Form 10-
K (SEC File No. 001-33366), filed on February 19, 2015)
10.42*†
Form of Indemnification Agreement for officers and/or directors of Cheniere Energy Partners GP, LLC
10.43
10.44
10.45
10.46
LNG Lease Agreement, dated June 24, 2008, between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P.
(Incorporated by reference to Exhibit 10.7 to Cheniere’s Quarterly Report on Form 10-Q (SEC File No.
001-16383), filed on August 11, 2008)
LNG Lease Agreement, dated September 30, 2011, by and between Cheniere Marketing, LLC and Cheniere
Energy Investments, LLC (Incorporated by reference to Exhibit 10.3 to Cheniere’s Quarterly Report on Form
10-Q (SEC File No. 001-16383), filed on November 7, 2011)
Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG
Liquefaction Facility, dated November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas
and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to
a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on November 14, 2011)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0001 EPC Terms and Conditions,
dated May 1, 2012, (ii) the Change Order CO-0002 Heavies Removal Unit, dated May 23, 2012, (iii) the Change
Order CO-0003 LNTP, dated June 6, 2012, (iv) the Change Order CO-0004 Addition of Inlet Air Humidification,
dated July 10, 2012, (v) the Change Order CO-0005 Replace Natural Gas Generators with Diesel Generators,
dated July 10, 2012, (vi) the Change Order CO-0006 Flange Reduction and Valve Positioners, dated June 20,
2012, and (vii) the Change Order CO-0007 Relocation of Temporary Facilities, Power Poles Relocation
Reimbursement, and Duck Blind Road Improvement Reimbursement, dated July 13, 2012 (Incorporated by
reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed
on August 3, 2012)
112
Exhibit No.
10.47
10.48
10.49
10.50
10.51
10.52
10.53
Description
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0008 Delay in Full Placement of
Insurance, dated July 27, 2012, (ii) the Change Order CO-0009 HAZOP Action Items, dated July 31, 2012,
(iii) the Change Order CO-00010 Fuel Provisional Sum, dated August 8, 2012, (iv) the Change Order CO-00011
Currency Provisional Sum, dated August 8, 2012, (v) the Change Order CO-00012 Delay in NTP, dated August
8, 2012, and (vi) the Change Order CO-00013 Early EPC Work Credit, dated August 29, 2012 (Incorporated
by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366),
filed on November 2, 2012)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00014 Bundle of Changes, dated
September 5, 2012, (ii) the Change Order CO-00015 Static Mixer, Air Cooler Walkways, etc., dated November
8, 2012, (iii) the Change Order CO-0016 Delay in Full Placement of Insurance, dated October 29, 2012, (iv)
the Change Order CO-00017 Condensate Header, dated December 3, 2012 and (v) the Change Order CO-00018
Increase in Power Requirements, dated January 17, 2013 (Portions of this exhibit have been omitted and filed
separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit
10.26 to the Partnership’s Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00019 Delete Tank 6 Scope of Work,
dated February 27, 2013 and (ii) the Change Order CO-00020 Modification to Builder’s Risk Insurance Sum
Insured Value, dated March 14, 2013 (Portions of this exhibit have been omitted and filed separately with the
SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.2 to the
Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on May 3, 2013)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00021 Increase to Insurance
Provisional Sum, dated April 17, 2013, (ii) the Change Order CO-00022 Removal of LNG Static Mixer Scope,
dated May 8, 2013, (iii) the Change Order CO-00023 Revised LNG Rundown Line, dated May 30, 2013, (iv)
the Change Order CO-00024 Reroute Condensate Header, Substation HVAC Stacks, Inlet Metering Station
Pile Driving, dated June 11, 2013 and (v) the Change Order CO-00025 Feed Gas Connection Modifications,
dated June 11, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to
a request for confidential treatment.) (Incorporated by reference to Exhibit 10.45 to Amendment No. 1 to
Cheniere Holdings’ Registration Statement on Form S-1/A (SEC File No. 333-191298), filed on October 18,
2013)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00026 Bundle of Changes, dated
June 28, 2013, (ii) the Change Order CO-00027 16” Water Pumps, dated July 12, 2013, (iii) the Change Order
CO-00028 HRU Operability, dated July 26, 2013, (iv) the Change Order CO-00029 Belleville Washers, dated
August 14, 2013 and (v) the Change Order CO-00030 Soils Preparation Provisional Sum Transfer, dated August
29, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request
for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report
on Form 10-Q (SEC File No. 001-33366), filed on November 8, 2013)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00031 LNG Intank Pump Replacement
Scope Reduction/OSBL Additional Piling for the Cathodic Protection Rectifier Platform and Drum Storage
Shelter dated October 15, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC
pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.35 to Amendment
No. 2 to SPL’s Registration Statement on Form S-4/A (SEC File No. 333-192373), filed on January 28, 2014)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00032 Intra-Plant Feed Gas Header
and Jefferson Davis Electrical Distribution, dated January 9, 2014, (ii) the Change Order CO-00033 Revised
EPC Agreement Attachments S & T, dated March 24, 2014 and (iii) the Change Order CO-00034 Greenfield/
Brownfield Demarcation Adjustment, dated February 19, 2014 (Portions of this exhibit have been omitted and
filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to
Exhibit 10.1 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 1, 2014)
113
Exhibit No.
10.54
10.55
10.56
10.57
10.58
10.59
10.60
10.61
Description
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00035 Resolution of FERC Open Items,
Additional FERC Support Hours and Greenfield/Brownfield Milestone Adjustment, dated May 9, 2014
(Incorporated by reference to Exhibit 10.3 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373),
filed on July 31, 2014)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00036 Future Tie-Ins and Jeff Davis
Invoices, dated July 9, 2014 (Portions of this exhibit have been omitted and filed separately with the SEC
pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.23 to SPL’s
Registration Statement on Form S-4 (SEC File No. 333-198358), filed on August 26, 2014)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00037 Performance and Attendance
Bonus (PAB) Incentive Program Provisional Sum, dated October 31, 2014 and (ii) the Change Order CO-00038
Control Room Modifications and Miscellaneous Items, dated January 6, 2015 (Portions of this exhibit have
been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated
by reference to Exhibit 10.26 to SPL’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on
February 19, 2015)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00039 Increase to Existing Facility
Labor Provisional Sum and Decrease to Sales and Use Tax Provisional Sum, dated February 12, 2015 and (ii)
the Change Order CO-00040 Load Shedding and LNG Tank Tie-In Crane, dated February 24, 2015 (Portions
of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential
treatment.) (Incorporated by reference to Exhibit 10.2 to SPL’s Quarterly Report on Form 10-Q (SEC File No.
333-192373), filed on April 30, 2015)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00041 Additional Building Utility Tie-
in Packages and Fire and Gas Modifications, dated April 9, 2015 (Incorporated by reference to Exhibit 10.2
to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 30, 2015)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00042 Platform Design Modifications,
Compressor Oil Fills, Additional Building Modifications, dated October 16, 2015, and (ii) the Change Order
CO-00043 Soil Provisional Sum Closure, dated December 2, 2015 (Portions of this exhibit have been omitted
and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference
to Exhibit 10.32 to SPL’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February 18,
2016)
Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG
Stage 2 Liquefaction Facility, dated December 20, 2012, by and between Sabine Pass Liquefaction, LLC and
Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the
SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to the
Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on December 27, 2012)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass
Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0001 Electrical Station
HVAC Stacks, dated June 4, 2013, (ii) the Change Order CO-0002 Revised LNG Rundown Lines, dated May
30, 2013, (iii) the Change Order CO-0003 Currency Provisional Sum Closure, dated May 29, 2013 and (iv)
the Change Order CO-0004 Fuel Provisional Sum Closure, dated May 29, 2013 (Portions of this exhibit have
been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated
by reference to Exhibit 10.48 to Amendment No. 1 to Cheniere Holdings’ Registration Statement on Form S-1/
A (SEC File No. 333-191298), filed on October 18, 2013)
114
Exhibit No.
10.62
10.63
10.64
10.65
10.66
10.67
10.68
10.69
Description
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass
Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0005 Credit to EPC
Contract Value for TSA Work, dated June 24, 2013, (ii) the Change Order CO-0006 HRU Operability with
Lean Gas & Controls Upgrade and Ultrasonic Meter Configuration and Calibration, dated July 26, 2013, (iii)
the Change Order CO-0007 Additional Belleville Washers, dated August 15, 2013, (iv) the Change Order
CO-0008 GTG Switchgear Arrangement/Upgrade Fuel Gas Heater System, dated August 26, 2013, and (v) the
Change Order CO-0009 Soils Preparation Provisional Sum Transfer and Closure, dated August 26, 2013
(Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential
treatment.) (Incorporated by reference to Exhibit 10.49 to Amendment No. 1 to Cheniere Holdings’ Registration
Statement on Form S-1/A (SEC File No. 333-191298), filed on October 18, 2013)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass
Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00010 Insurance
Provisional Sum Adjustment, dated January 23, 2014, (ii) the Change Order CO-00011 Additional Stage 2
GTGs, dated January 23, 2014, (iii) the Change Order CO-0012 Lien and Claim Waiver Modification, dated
March 24, 2014 and (iv) the Change Order CO-00013 Revised Stage 2 EPC Agreement Attachments S&T,
dated March 24, 2014 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant
to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.2 to SPL’s Quarterly Report
on Form 10-Q (SEC File No. 333-192373), filed on May 1, 2014)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass
Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00014 Additional 13.8kv
Circuit Breakers and Misc. Items, dated July 14, 2014 (Portions of this exhibit have been omitted and filed
separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit
10.28 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-198358), filed on August 26, 2014)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass
Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00015 Performance and
Attendance Bonus (PAB) Incentive Program Provisional Sum, dated October 31, 2014 (Portions of this exhibit
have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
(Incorporated by reference to Exhibit 10.32 to SPL’s Annual Report on Form 10-K (SEC File No. 333-192373),
filed on February 19, 2015)
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of
the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass
Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00016 Louisiana Sales
and Use Tax Provisional Sum Adjustment, dated February 12, 2015 and (ii) the Change Order CO-00017 Load
Shedding Study and Scope Change, dated February 24, 2015 (Portions of this exhibit have been omitted and
filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to
Exhibit 10.3 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on April 30, 2015)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass
Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00018 Permanent Restroom
Trailers and Installation of Tie-In for GTG Fuel Gas Interconnect, dated May 21, 2015 (Incorporated by
reference to Exhibit 10.3 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July
30, 2015)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass
Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00019 East Meter Piping
Tie-ins, dated August 26, 2015 (Incorporated by reference to Exhibit 10.1 to SPL’s Quarterly Report on Form
10-Q (SEC File No. 333-192373), filed on October 30, 2015)
Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG
Stage 3 Liquefaction Facility, dated May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil,
Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the Securities
and Exchange Commission pursuant to a request for confidential treatment.) (Incorporated by reference to
Exhibit 10.1 to the Partnership’s Current Report on Form 8-K/A (SEC File No. 001-33366), filed on July 1,
2015)
115
Exhibit No.
10.70
10.71
10.72
10.73
10.74
10.75
10.76
10.77
10.78
10.79
10.80
10.81
10.82
10.83
10.84
Description
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00001 Currency and Fuel Provisional
Sum Adjustment, dated June 25, 2015 (Portions of this exhibit have been omitted and filed separately with the
SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.4 to SPL’s
Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 30, 2015)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00002 Credit to EPC Contract Value
for TSA Work, dated September 17, 2015 (Incorporated by reference to Exhibit 10.2 to SPL’s Quarterly Report
on Form 10-Q (SEC File No. 333-192373), filed on October 30, 2015)
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the
Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction,
LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00003 Perimeter Fencing Scope Removal,
East Meter Piping Scope Change, Additional Bathroom Facilities, dated November 18, 2015 (Incorporated by
reference to Exhibit 10.45 to SPL’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February
18, 2016)
LNG Sale and Purchase Agreement (FOB), dated November 21, 2011, between Sabine Pass Liquefaction, LLC
(Seller) and Gas Natural Aprovisionamientos SDG S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to
the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on November 21, 2011)
Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated April 3, 2013, between Sabine Pass
Liquefaction, LLC (Seller) and Gas Natural Aprovisionamientos SDG S.A. (Buyer) (Incorporated by reference
to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on May
3, 2013)
LNG Sale and Purchase Agreement (FOB), dated December 11, 2011, between Sabine Pass Liquefaction, LLC
(Seller) and GAIL (India) Limited (Buyer) (Incorporated by reference to Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K (SEC File No. 001-33366), filed on December 12, 2011)
Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between Sabine
Pass Liquefaction, LLC (Seller) and GAIL (India) Limited (Buyer) (Incorporated by reference to Exhibit 10.18
to the Partnership’s Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)
LNG Sale and Purchase Agreement (FOB), dated December 14, 2012, between Sabine Pass Liquefaction, LLC
(Seller) and Total Gas & Power North America, Inc. (Buyer) (Incorporated by reference to Exhibit 10.1 to the
Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on December 17, 2012)
Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated August 28, 2015, between Sabine Pass
Liquefaction, LLC (Seller) and Total Gas & Power North America, Inc. (Buyer) (Incorporated by reference to
Exhibit 10.4 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on October
30, 2015)
Amended and Restated LNG Sale and Purchase Agreement (FOB), dated January 25, 2012, between Sabine
Pass Liquefaction, LLC (Seller) and BG Gulf Coast LNG, LLC (Buyer) (Incorporated by reference to Exhibit
10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on January 26, 2012)
LNG Sale and Purchase Agreement (FOB), dated January 30, 2012, between Sabine Pass Liquefaction, LLC
(Seller) and Korea Gas Corporation (Buyer) (Incorporated by reference to Exhibit 10.1 to the Partnership’s
Current Report on Form 8-K (SEC File No. 001-33366), filed on January 30, 2012)
Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between Sabine
Pass Liquefaction, LLC (Seller) and Korea Gas Corporation (Buyer) (Incorporated by reference to Exhibit
10.19 to the Partnership’s Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)
LNG Sale and Purchase Agreement (FOB), dated March 22, 2013, between Sabine Pass Liquefaction, LLC
(Seller) and Centrica plc (Buyer) (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report
on Form 8-K (SEC File No. 001-33366), filed on March 25, 2013)
Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated September 11, 2015, between Sabine
Pass Liquefaction, LLC (Seller) and Centrica plc (Buyer) (Incorporated by reference to Exhibit 10.5 to the
Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on October 30, 2015)
Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between Sabine Pass
Liquefaction, LLC (Seller) and Cheniere Marketing, LLC (Buyer) (Incorporated by reference to Exhibit 10.1
to SPL’s Current Report on Form 8-K (SEC File No. 333-192373), filed on August 11, 2014)
116
Exhibit No.
10.85
Description
Management Services Agreement, dated May 14, 2012, by and between Cheniere LNG Terminals, LLC and
Sabine Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.6 to the Partnership’s Current Report
on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.86
10.87
10.88
10.89
10.90
10.91
10.92
10.93
10.94
10.95
10.96
10.97
10.98
10.99
Amendment to Management Services Agreement, dated September 28, 2015, between Cheniere LNG
Terminals, LLC and Sabine Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.8 to Amendment
No. 1 to SPL’s Quarterly Report on Form 10-Q/A (SEC File No. 333-192373), filed on November 9, 2015)
Amended and Restated Management Services Agreement, dated as of August 9, 2012, by and between Cheniere
LNG Terminals, LLC and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.6 to the Partnership’s
Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
Management Services Agreement, dated May 27, 2013, by and between Cheniere LNG Terminals, LLC and
Cheniere Creole Trail Pipeline, L.P. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly
Report on Form 10-Q (SEC File No. 001-33366), filed on August 2, 2013)
Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated May 14, 2012, by and
among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and Sabine Pass Liquefaction,
LLC (Incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K (SEC File
No. 001-33366), filed on May 15, 2012)
Assignment and Assumption Agreement (Sabine Pass Liquefaction O&M Agreement), dated as of November
20, 2013, by and between Cheniere Energy Partners GP, LLC and Cheniere Energy Investments, LLC
(Incorporated by reference to Exhibit 10.76 to Cheniere Holdings’ Registration Statement on Form S-1 (SEC
File No. 333-191298), filed on December 2, 2013)
Amendment to Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated September
28, 2015, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Investments, LLC and Sabine
Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.7 to Amendment No. 1 to SPL’s Quarterly
Report on Form 10-Q/A (SEC File No. 333-192373), filed on November 9, 2015)
Amended and Restated Operation and Maintenance Agreement (Sabine Pass LNG Facilities), dated as of August
9, 2012, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and Sabine
Pass LNG, L.P. (Incorporated by reference to Exhibit 10.5 to the Partnership’s Quarterly Report on Form 10-
Q (SEC File No. 001-33366), filed on November 2, 2012)
Assignment and Assumption Agreement (Sabine Pass LNG O&M Agreement), dated as of November 20, 2013,
by and between Cheniere Energy Partners GP, LLC and Cheniere Energy Investments, LLC (Incorporated by
reference to Exhibit 10.75 to Amendment No. 4 to Cheniere Holdings’ Registration Statement on Form S-1/A
(SEC File No. 333-191298), filed on December 2, 2013)
Amended and Restated Management and Administrative Services Agreement, dated as of August 9, 2012, by
and between Cheniere Energy Partners, L.P., Cheniere LNG Terminals, LLC and Cheniere Energy, Inc.
(Incorporated by reference to Exhibit 10.4 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No.
001-33366), filed on November 2, 2012)
Amended and Restated Operation and Maintenance Services Agreement, dated May 27, 2013, by and between
Cheniere Energy Partners GP, LLC and Cheniere Creole Trail Pipeline, L.P. (Incorporated by reference to
Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on August
2, 2013)
Assignment and Assumption Agreement (Creole Trail O&M Agreement), dated as of November 20, 2013,
between Cheniere Energy Partners GP, LLC and Cheniere Energy Investments, LLC (Incorporated by reference
to Exhibit 10.74 to Cheniere Holdings’ Registration Statement on Form S-1 (SEC File No. 333-191298), filed
on December 2, 2013)
Waiver and Assignment of O&M Agreement; Amendment to Common Terms Agreement, dated November
20, 2013 (Incorporated by reference to Exhibit 10.77 to Cheniere Holdings’ Registration Statement on Form
S-1 (SEC File No. 333-191298), filed on December 2, 2013)
Payment Deferral Agreement (O&M Agreement), dated March 27, 2014, between Cheniere Energy
Investments, LLC and Cheniere LNG O&M Services, LLC (Incorporated by reference to Exhibit 10.5 to
Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 1, 2014)
Cooperative Endeavor Agreement & Payment in Lieu of Tax Agreement, dated October 23, 2007, by and
between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.7 to
Cheniere’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2007)
10.100
Amended and Restated Services and Secondment Agreement, dated as of August 9, 2012, between Cheniere
LNG O&M Services, LLC and Cheniere Energy Partners GP, LLC (Incorporated by reference to Exhibit 10.3
to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
117
Exhibit No.
10.101
10.102
10.103
10.104
10.105
10.106
10.107
21.1*
23.1*
23.2*
31.1*
31.2*
32.1**
32.2**
Description
Assignment and Assumption Agreement (Services and Secondment Agreement), dated as of November 20,
2013, by and between Cheniere Energy Partners GP, LLC and Cheniere Energy Investments, LLC (Incorporated
by reference to Exhibit 10.73 to Cheniere Holdings’ Registration Statement on Form S-1 (SEC File No.
333-191298), filed on December 2, 2013)
Unit Purchase Agreement, dated May 14, 2012, by and among Cheniere Energy Partners, L.P., Cheniere Energy,
Inc. and Blackstone CQP Holdco LP (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
Class B Unit Purchase Agreement, dated as of May 14, 2012, by and between Cheniere Energy Partners, L.P.
and Cheniere LNG Terminals, LLC (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
First Amendment to Class B Unit Purchase Agreement, dated as of August 9, 2012, by and between Cheniere
Energy Partners, L.P. and Cheniere Class B Units Holdings, LLC (Incorporated by reference to Exhibit 10.3
to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
Subscription Agreement, dated May 14, 2012, by and between Cheniere Energy Partners, L.P. and Cheniere
LNG Terminals, LLC (Incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form
8-K (SEC File No. 001-33366), filed on May 15, 2012)
Letter Agreement, dated as of August 9, 2012, among Cheniere Energy, Inc., Cheniere Energy Partners, L.P.
and Blackstone CQP Holdco LP (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report
on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
Investors’ and Registration Rights Agreement, dated as of July 31, 2012, by and among Cheniere Energy, Inc.,
Cheniere Energy Partners, L.P., Cheniere Energy Partners GP, LLC, Blackstone CQP Holdco LP and the other
investors party thereto from time to time (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current
Report on Form 8-K (SEC File No. 001-33366), filed on August 6, 2012)
Subsidiaries of Cheniere Energy Partners, L.P.
Consent of KPMG LLP
Consent of Ernst & Young LLP
Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002
101.INS*
XBRL Instance Document
101.SCH*
XBRL Taxonomy Extension Schema Document
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
101.LAB*
XBRL Taxonomy Extension Definition Linkbase Document
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
118
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—
CHENIERE ENERGY PARTNERS, L.P.
CONDENSED BALANCE SHEETS
(in thousands)
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable—affiliates
Prepaid expenses and other
Total current assets
Investment in affiliates
Other non-current assets
Total assets
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accrued liabilities—affiliates
Other current liabilities
Total current liabilities
Partners’ equity
Total liabilities and partners’ equity
December 31,
2015
2014
109,950
—
187
110,137
617,749
953
728,839
14,750
1,158
15,908
712,931
728,839
$
$
$
$
222,130
9,568
104
231,802
902,612
123
1,134,537
3,033
775
3,808
1,130,729
1,134,537
$
$
$
$
The accompanying notes are an integral part of these condensed financial statements.
119
CHENIERE ENERGY PARTNERS, L.P.
CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
(in thousands)
Operating costs and expenses
Operating costs and expenses—affiliates
Loss from operations
Interest income
Equity loss of affiliates
Net loss
Other comprehensive income attributable to affiliates
Comprehensive loss
Year Ended December 31,
2015
2014
2013
$
5,737
11,546
(17,283)
$
3,383
11,556
(14,939)
173
(301,781)
(318,891) $
162
(395,259)
(410,036) $
—
—
(318,891) $
(410,036) $
3,041
11,376
(14,417)
242
(243,942)
(258,117)
27,240
(230,877)
$
$
$
The accompanying notes are an integral part of these condensed financial statements.
120
CHENIERE ENERGY PARTNERS, L.P.
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
Cash flows from operating activities
Cash flows from investing activities
Investments in subsidiaries
Distributions received from affiliates, net
Purchase of Creole Trail Pipeline Business, net
Net cash provided by (used in) investing activities
Cash flows from financing activities:
Distributions to owners
Proceeds from sale of partnership common and general partner units
Net cash provided by (used in) financing activities
Year Ended December 31,
2015
$
3,646
$
2014
(24,416) $
2013
(13,056)
(35,208)
18,400
—
(16,808)
(99,018)
—
(99,018)
(77,846)
108,625
—
30,779
(99,015)
—
(99,015)
(405,452)
369,726
(313,892)
(349,618)
(91,386)
375,897
284,511
(78,163)
392,945
314,782
Net decrease in cash and cash equivalents
Cash and cash equivalents—beginning of period
Cash and cash equivalents—end of period
(112,180)
222,130
109,950
$
(92,652)
314,782
222,130
$
$
The accompanying notes are an integral part of these condensed financial statements.
121
CHENIERE ENERGY PARTNERS, L.P.
NOTES TO CONDENSED FINANCIAL STATEMENTS
NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The condensed financial statements represent the financial information required by Securities and Exchange Commission
Regulation S-X 5-04 for Cheniere Partners.
A substantial amount of Cheniere Partners’ operating, investing and financing activities are conducted by its affiliates. In
the condensed financial statements, Cheniere Partners’ investments in affiliates are presented under the equity method of accounting.
Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are
recorded in the balance sheets. The gain (loss) from operations of the affiliates is reported on a net basis as equity in net gains
(losses) of affiliates.
In May 2013, we acquired Cheniere’s ownership interest in the Creole Trail Pipeline Business, thereby providing us with
ownership of a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines. The
effect on reported equity on including the prior results of the Creole Trail Pipeline Business is reported as Investment in affiliates
in our Condensed Balance Sheet and Equity loss of affiliates in our Condensed Statement of Operations. The purchase has been
accounted for as a transfer of net assets between entities under common control. We recognize transfers of net assets between
entities under common control at Cheniere’s historical basis in the net assets sold. In addition, transfers of net assets between
entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are
retroactively adjusted to furnish comparative information.
The condensed financial statements should be read in conjunction with Cheniere Partners’ Consolidated Financial
Statements.
NOTE 2—GUARANTEES
Guarantees on Behalf of CTPL
In May 2013, CTPL entered into a $400.0 million term loan facility (the “CTPL Term Loan”), which is being used to fund
modifications to the Creole Trail Pipeline and for general business purposes. CTPL incurred $10.0 million of direct lender fees
that were recorded as a debt discount. The CTPL Term Loan matures in 2017 when the full amount of the outstanding principal
obligations must be repaid. CTPL’s loans may be repaid, in whole or in part, at any time without premium or penalty. As of
December 31, 2015, CTPL had borrowed the full amount of $400.0 million available under the CTPL Term Loan. Cheniere
Partners has guaranteed on behalf of CTPL all principal, interest, costs, fees and expenses owed under the CTPL Term Loan.
NOTE 3—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in thousands):
Year Ended December 31,
Non-cash capital contributions (1)
Non-cash capital contributions related to the Creole Trail Pipeline Business (1)
2015
2014
$ (301,781) $ (395,259) $ (225,792)
(18,150)
2013
—
—
(1)
Amounts represent equity gains (losses) of affiliates not funded by Cheniere Partners.
122
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
CHENIERE ENERGY PARTNERS, L.P.
Cheniere Energy Partners GP, LLC,
By:
its general partner
By:
Date:
/s/ Neal A. Shear
Neal A. Shear
Interim Chief Executive Officer
(Principal Executive Officer)
February 18, 2016
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the general partner of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Neal A. Shear
Neal A. Shear
/s/ R. Keith Teague
R. Keith Teague
/s/ Michael J. Wortley
Michael J. Wortley
/s/ Leonard Travis
Leonard Travis
/s/ James R. Ball
James R. Ball
/s/ Meg A. Gentle
Meg A. Gentle
/s/ Sean T. Klimczak
Sean T. Klimczak
/s/ Lon McCain
Lon McCain
/s/ Philip Meier
Philip Meier
/s/ John-Paul Munfa
John-Paul Munfa
/s/ Vincent Pagano Jr.
Vincent Pagano Jr.
/s/ Oliver G. Richard, III
Oliver G. Richard, III
Interim Chief Executive Officer, Chairman of the Board
(Principal Executive Officer)
February 18, 2016
President and Chief Operating Officer, Director
(Principal Operating Officer)
February 18, 2016
Senior Vice President and Chief Financial Officer, Director
(Principal Financial Officer)
February 18, 2016
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
123
February 18, 2016
February 18, 2016
February 18, 2016
February 18, 2016
February 18, 2016
February 18, 2016
February 18, 2016
February 18, 2016
February 18, 2016
CORPORATE INFORMATION
BOARD OF DIRECTORS & OFFICERS
Neal A. Shear
Chairman of the Board &
Interim Chief Executive Officer
James R. Ball
Independent Director
Meg A. Gentle
Director
Sean T. Klimczak
Director
Lon McCain
Independent Director
Philip Meier
Director
John-Paul R. Munfa
Director
CONTACTS & ADVISORS
Corporate Office
Cheniere Energy Partners, L.P.
700 Milam, Suite 1900
Houston, Texas 77002
Telephone: (713) 375-5000
Facsimile: (713) 375-6000
Stock Exchange Listing:
NYSE MKT: CQP
Vincent Pagano, Jr.
Independent Director
Oliver G. Richard, III
Independent Director
R. Keith Teague
Director, President &
Chief Operating Officer
Michael J. Wortley
Director, Senior Vice President
& Chief Financial Officer
Daniel Belhumeur
Vice President & General Tax Counsel
Sean Bunk
Assistant Secretary
Investor Relations
Telephone: (713) 375-5100
Email: info@cheniere.com
www.cheniere.com
Lisa Cohen
Vice President & Treasurer
Sean N. Markowitz
Corporate Secretary
Mitch Price
Vice President & Chief Security Risk Officer
Greg W. Rayford
Assistant Secretary
Khaled Sharafeldin
Vice President, Internal Audit
Len Travis
Chief Accounting Officer
Transfer Agent
Computershare Trust Company, N.A.
P.O. Box 43078
Providence, RI 02940-3078
Telephone: (800) 962-4284
Facsimile: (303) 262-0600
Independent Accountants
KPMG, Houston, Texas
Cheniere Energy Partners, L.P. is a Houston-based energy
company constructing and developing a leading LNG
platform along the U.S. Gulf Coast.
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