CHENIERE ENERGY PARTNERS, L.P. ANNUAL REPORT
Cheniere Energy Partners, L.P. provides clean, secure, and affordable LNG to the world.
We conduct our business safely and responsibly, delivering a reliable, competitive,
and integrated source of LNG to our customers.
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www.cheniere.com
DEMONSTRATING CHE NIE RE PA R T NE RS’
S T A B I L I T Y
SAFE L Y AN D SUCCESSF ULLY MANAGED OPERATIONS
TH ROUGH MULTIPLE CHALLENGE S
C O V I D - 1 9
P A N D E M I C
C A R G O
C A N C E L L A T I O N S
V O L A T I L E
L N G P R I C E S
T W O M A J O R
H U R R I C A N E S
$
REP OR TED STRO NG FU LL YE A R 2 020
FINANC IA L RESU LT S
N E T I N C O M E
A D J U S T E D E B I T DA 1
D I S T R I B U T I O N P E R U N I T
$1.18
BILLION
C A R G O E S E X P O R T E D
275
~18.5 Million Tonnes
$2.76
BILLION
$2.59
PROJECT COMPLETION2
SPL Train 6
77.6%
Completion forecast
A C C E L E R A T E D T O
2H 2022
2020 Sabine Pass Trains 5 and 6
Dear Unitholders,
In my decades of experience in the energy sector, there has always been volatility – in
weather, commodity prices, production, etc. – but never with the magnitude nor personal
impact we have experienced throughout the COVID-19 pandemic. Unfortunately, as I write
this letter, the world is still struggling to move beyond the pandemic, but there is light at
the end of the tunnel.
For Cheniere Partners, 2020 was an unforgettable and pivotal year for many reasons,
and a year I will look back on with a great sense of pride in our accomplishments. We
maintained our business focus and executed as a team, achieving our annual goals
and targets despite a myriad of logistical and operational challenges borne from
both the far-reaching impacts of the pandemic and major weather events in the Gulf
of Mexico. We adeptly managed and overcame these challenges to deliver on our
promises to our stakeholders, leaving no doubt as to the stability of our business and
our formidable ability to execute.
Beginning in the first quarter of 2020, at the onset of the pandemic, we made
significant logistical and operational adjustments to keep our people and our partners
safe while also ensuring the continuity of our liquefaction operations. We activated
various emergency response teams, deployed policies and protocols, implemented
revised work schedules and ensured our people were socially distanced, and
temporarily utilized on-site housing for certain critical operations personnel at our
liquefaction facility. Our teams responded quickly and with agility, adapting to fluid
circumstances while prioritizing safety and business continuity, and thus reinforcing
Cheniere Partners’ reputation for operational excellence. We worked hand in hand
with our long-term customers, which were feeling the effects of reduced energy
demand as a result of the pandemic and needed to balance their energy needs.
Sabine Pass Train 6
estimated completion
accelerated six months
UNITHOLDER LETTER 1
“ Our people and their
hard work were critical
to the operational and
financial results we
produced for 2020“
Our engineering and construction professionals, along with our EPC partner Bechtel,
implemented proactive pandemic protocols to mitigate the potential impacts over the
thousands of construction workers at our Sabine Pass site. They diligently adhered to
protocols and conducted thousands of COVID tests to ensure the safety of the workforce.
The results of these efforts have been second to none, with continued execution on an
accelerated timeline for the construction of Sabine Pass Train 6, which also remains
within budget. The estimated substantial completion for Train 6 was accelerated in July
by approximately six months. That project continues to progress very well, and project
completion was 77.6% as of December 31.
Through the summer, the global LNG market saw record low pricing as a result of the
combination of pandemic-related demand shocks, two consecutive warm winters in key
Asian markets, and a significant increase in worldwide LNG capacity that has entered
service over the last four years. During this period of historically low LNG prices, many
of our customers elected to cancel the loading of their cargoes and pay us the fixed fee
as defined in our long-term contracts – a valuable contractual feature designed to give
our customers flexibility to manage their energy demand while enabling us to maintain
financial stability. We successfully ramped down LNG production in response to these
cancellations and managed our operations efficiently through this short-term period of
market weakness.
In August and September, our operational flexibility and resilience were further tested
when two major hurricanes made landfall near Sabine Pass, including Hurricane Laura
which was a Category 5 storm. Our facility is designed to effectively withstand the
expected weather risks of the Gulf Coast region and suffered no significant impact
from either storm. Many members of our Cheniere Partners family and neighboring
communities were personally impacted, however, and we responded quickly and
meaningfully with shelter, clothing, and other necessities for our employees and through
community donations, supply drives, and thousands of volunteer hours.
Despite all of these challenges, any of which would have been significant individually,
our team’s resolve and determination enabled Cheniere Partners to deliver on our
promises. Our people and their hard work were critical to the operational and financial
results we produced for 2020.
Distributions increased
by 5% in 2020 as
compared to 2019
2 UNI THOLD ER LETTER
“ Improving environmental
performance is not solely
about responsibility,
it also makes sound
business sense”
We reported $1.18 billion of net income and $2.76 billion of Adjusted EBITDA1 for
2020. We paid total distributions of $2.59 per common unit for full year 2020, within
our full year guidance range and an increase of over 5% as compared to distributions
for full year 2019.
We also raised capital in 2020 in support of our long-term financial strategy when we
refinanced the $2 billion Sabine Pass Liquefaction 2021 notes despite capital markets
volatility in the spring.
Our first liquefaction train was completed and handed over to our operations
professionals in May 2016. Over the last five years, they have been busy increasing
the effectiveness and efficiency of our site operations and our trains’ performance
through initiatives including maintenance optimization and debottlenecking. These
efforts to optimize operations and maximize LNG production have yielded continual
improvement and led us to increase our run rate LNG production forecasts and financial
guidance in November. We increased forecast run rate production to 4.9-5.1 mtpa per
Train, which is approximately 12% higher at the midpoint than our original production
guidance from 2017. Compared to our original guidance, our forecast production
increases have added an aggregate of up to approximately 5 million tonnes per year
of additional marketable LNG across all of our Trains, or virtually an entire additional
Train worth of production, with minimal capital investment.
Increasing the operating capacity of our existing infrastructure drives increased
Adjusted EBITDA and cash flow and increases our return on investment. In addition to
increasing our run rate production guidance, we increased our run rate Distributable
Cash Flow per Unit guidance to $3.75-3.95 per year.
We believe that LNG has a significant role to play in the global transition to a lower
carbon future over the coming decades, as it simultaneously supports both economic
growth and emissions reduction. Our constructive long-term view for global LNG
demand is reinforced by the significant investments being made in natural gas
infrastructure being developed in key LNG demand markets worldwide, in support of
increasing natural gas as a primary fuel source and displacing coal, oil, and other dirtier
fuels. These fundamentals are supportive of our ability to generate long-term, stable
cash flows, even beyond the current terms of our LNG sales and purchase agreements.
Increase in run rate
production guidance
per Train
UNITHOLDER LETTER 3
“ LNG has a significant role to
play in the global transition
to a lower carbon future”
C A R G O E M I S S I O N S T A G S
Focused on efforts in key
areas along value chain
to improve resiliency and
sustainability of LNG
Environmental, Social, and Governance (ESG) risks and opportunities were a significant
area of focus for Cheniere Partners throughout 2020. Our parent, Cheniere, published
First and Forward, its inaugural corporate responsibility report, in early July, marking a
significant step forward in the commitment to transparency in sustainability reporting.
This report was a cross-functional effort led by a team of subject matter experts from
across almost every business unit within Cheniere and forms the foundation for its ESG
reporting and disclosures.
Improving environmental performance is not solely about responsibility, it also makes
sound business sense. We, alongside Cheniere, are integrating climate opportunities
into our commercial offering, reinforcing our position at the forefront of the LNG
industry and reputation for commercial innovation, and are undertaking significant
operational analysis to quantify our lifecycle emissions and to identify and analyze
climate-related opportunities across our value chain, with the strategic goals of
resilience, transparency, avoidance, and reduction. In early 2021, Cheniere announced
the development of cargo emissions tags, or CE Tags, which will quantify the estimated
greenhouse gas emissions of our LNG cargoes from the wellhead to the cargo delivery
point, a significant step toward environmental transparency, and we expect to provide
these CE Tags to our customers beginning in 2022.
As we move into 2021, we are committed to reinforcing our track record of excellence
in operational execution, delivering on our financial guidance, and maintaining
alignment with our stakeholders. Our 2021 goals are supported by improving LNG
market dynamics and, as always, the dedication and diligence of our people.
Thank you all for your continued support of Cheniere Partners.
Sincerely,
Jack A. Fusco
Chairman, President and CEO
4 UNI THOLD ER LETTER
in the appendix.
(2) As of December 31, 2020.
(1) Adjusted EBITDA is a non-GAAP measure. A reconciliation to Net income, the most comparable U.S. GAAP measure, is included
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, 2020
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 number 001-33366
Cheniere Energy Partners, L.P.
Delaware
20-5913059
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
(Exact name of registrant as specified in its charter)
700 Milam Street, Suite 1900
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 375-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Units Representing Limited Partner Interests
Trading Symbol
CQP
Name of each exchange on which registered
NYSE American
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 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 every Interactive Data File required to be submitted 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 such files).
Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an
emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company”
in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
☒
☐
Accelerated filer
Smaller reporting company
Emerging growth company
☐
☐
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new
or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal
control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or
issued its audit report. ☒
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 $8.5 billion as of June 30, 2020.
As of February 19, 2021, the registrant had 484,021,123 common units outstanding.
Documents incorporated by reference: None
CHENIERE ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
PART I
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
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
PART II
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
Item 16. Form 10-K Summary
Signatures
PART IV
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41
41
41
42
43
44
60
61
99
99
99
100
104
107
110
112
113
126
127
i
As used in this annual report, the terms listed below have the following meanings:
DEFINITIONS
Common Industry and Other Terms
Bcf
Bcf/d
Bcf/yr
Bcfe
DOE
EPC
FERC
FTA countries
GAAP
Henry Hub
LIBOR
LNG
MMBtu
mtpa
non-FTA countries
SEC
SPA
TBtu
Train
TUA
billion cubic feet
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 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
million British thermal units, an energy unit
million tonnes per annum
countries with which the United States does not have a free trade agreement providing for national
treatment for trade in natural gas and with which trade is permitted
U.S. Securities and Exchange Commission
LNG sale and purchase agreement
trillion British thermal units, an energy unit
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into
LNG
terminal use agreement
1
Abbreviated Legal Entity Structure
The following diagram depicts our abbreviated legal entity structure as of December 31, 2020, 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. and its consolidated subsidiaries, including SPLNG, SPL and CTPL.
2
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the
meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities
Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or
conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-
looking statements” are, among other things:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
statements regarding our ability to pay distributions to our unitholders;
statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL;
statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction
facility, pipeline facility or other projects, or any expansions or portions thereof, by certain dates, or at all;
statements regarding future levels of domestic and international natural gas production, supply or consumption or
future levels of LNG imports into or exports from North America and other countries worldwide or purchases of
natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for
and prices related to natural gas, LNG or other hydrocarbon products;
statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
statements relating to the construction of our Trains, including statements concerning the engagement of any EPC
contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other
contractor, and anticipated costs related thereto;
statements regarding any SPA or other agreement to be entered into or performed substantially in the future,
including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the
amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject
to contracts;
statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
statements regarding our planned development and construction of additional Trains, including the financing of such
Trains;
statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction
capacities;
statements regarding our business strategy, our strengths, our business and operation plans or any other plans,
forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating
costs and cash flows, any or all of which are subject to change;
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals,
requirements, permits, applications, filings, investigations, proceedings or decisions;
statements regarding the outbreak of COVID-19 and its impact on our business and operating results, including any
customers not taking delivery of LNG cargoes, the ongoing credit worthiness of our contractual counterparties, any
disruptions in our operations or construction of our Trains and the health and safety of Cheniere’s employees, and on
our customers, the global economy and the demand for LNG;
any other statements that relate to non-historical or future information; and
other factors described in Item 1A. Risk Factors in this Annual Report on Form 10-K.
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking
In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,”
statements.
“should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,”
“predict,” “project,” “pursue,” “target,” 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
3
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the
other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons
acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only
as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking
statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
4
ITEMS 1. AND 2.
BUSINESS AND PROPERTIES
General
PART I
We are a publicly traded Delaware limited partnership formed by Cheniere Energy, Inc. (“Cheniere”). We provide clean,
secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire
to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our
customers.
LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into
natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that
is essential for heating, cooking and other industrial uses. Natural gas is a cleaner-burning, abundant and affordable source of
energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution
traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe.
Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to
reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid
form for efficient transport overseas.
The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four
miles from the Gulf Coast. Through our subsidiary, Sabine Pass Liquefaction, LLC (“SPL”), we are currently operating five
natural gas liquefaction Trains and are constructing one additional Train that is expected to be substantially completed in the
second half of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the
Sabine Pass LNG terminal, one of the largest LNG production facilities in the world. Through our subsidiary, Sabine Pass
LNG, L.P. (“SPLNG”), we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-
existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 17 Bcfe, two existing marine berths
and one under construction that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and
vaporizers with regasification capacity of approximately 4 Bcf/d. We also own a 94-mile pipeline through our subsidiary,
Cheniere Creole Trail Pipeline, L.P. (“CTPL”), that interconnects the Sabine Pass LNG terminal with a number of large
interstate pipelines (the “Creole Trail Pipeline”).
We remain focused on operational excellence and customer satisfaction. Increasing demand of LNG has allowed us to
expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at
our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold significant land positions at
the Sabine Pass LNG terminal, which provide opportunity for further liquefaction capacity expansion. The development of
these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require,
among other things, acceptable commercial and financing arrangements before we can make a final investment decision
(“FID”).
5
The following diagram depicts our abbreviated capital structure as of December 31, 2020:
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:
•
•
•
•
safely, efficiently and reliably operating and maintaining our assets, including our Trains;
procuring natural gas and pipeline transport capacity to our facility;
commencing commercial delivery for our long-term SPA customers, of which we have initiated for seven of eight
long-term SPA customers as of December 31, 2020;
safely, on-time and on-budget completing construction and commencing operation of Train 6 of the Liquefaction
Project;
• maximizing the production of LNG to serve our long-term customers and generating steady and stable revenues and
operating cash flows; and
•
strategically identifying actionable environmental solutions.
6
Our Business
Liquefaction Facilities
The Liquefaction Project is one of the largest LNG production facilities in the world. We are currently operating five
Trains and two marine berths at the Liquefaction Project and are constructing one additional Train that is expected to be
substantially completed in the second half of 2022, and a third marine berth. We have received authorization from the FERC to
site, construct and operate Trains 1 through 6, as well as for the construction of the third marine berth. We have achieved
substantial completion of the first five Trains of the Liquefaction Project and commenced commercial operating activities for
each Train at various times starting in May 2016. The following table summarizes the project completion and construction
status of Train 6 of the Liquefaction Project as of December 31, 2020:
Overall project completion percentage
Completion percentage of:
Engineering
Procurement
Subcontract work
Construction
Date of expected substantial completion
Train 6
77.6%
99.0%
99.9%
54.9%
49.2%
2H 2022
The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from
the Sabine Pass LNG terminal:
• Trains 1 through 4—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a
combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).
• Trains 1 through 4—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a
combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).
• Trains 5 and 6—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a combined
total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
In December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations
separately from long-term authorizations. Accordingly, the DOE amended each of SPL’s long-term authorizations to include
short-term export authority, and vacated the short-term orders.
An application was filed in September 2019 seeking authorization to make additional exports from the Liquefaction
Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of
approximately 153 Bcf/yr of natural gas, for a total Liquefaction Project export capacity of approximately 1,662 Bcf/yr. The
terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of
the volumes contemplated in the application.
In April 2020, the DOE issued an order authorizing SPL to export to FTA
countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet
issued an order authorizing SPL to export to non-FTA countries for the corresponding LNG volume. A corresponding
application for authorization to increase the total LNG production capacity of the Liquefaction Project from the currently
authorized level to approximately 1,662 Bcf/yr was also submitted to the FERC and is currently pending.
Customers
SPL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a
weighted average remaining contract length of approximately 17 years (plus extension rights) with eight third parties for Trains
1 through 6 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 75% of the total
production capacity from these Trains, potentially increasing up to approximately 85% after giving effect to an SPA that
Cheniere has committed to provide to us. Under these SPAs, the customers will purchase LNG from SPL for a price consisting
of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per
MMBtu of LNG generally equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend
deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be
required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or
7
suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries
under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable
only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees
under SPL’s SPAs were generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases
and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted
volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally
commences upon the date of first commercial delivery of a specified Train.
In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion for
Trains 1 through 5. After giving effect to an SPA that Cheniere has committed to provide to SPL, the annual fixed fee portion
to be paid by the third-party SPA customers would increase to at least $3.3 billion, which is expected to occur upon the date of
first commercial delivery of Train 6.
In addition, Cheniere Marketing has agreements with SPL to purchase: (1) at Cheniere Marketing’s option, any LNG
produced by SPL in excess of that required for other customers and (2) up to 30 cargoes scheduled for delivery in 2021 at a
price of 115% of Henry Hub plus $0.728 per MMBtu.
The annual contracted cash flows from fixed fees of each buyer of LNG under SPL’s third-party SPAs that constitute
more than 10% of SPL’s aggregate fixed fees under all its SPAs are:
•
•
•
•
•
approximately $720 million from BG Gulf Coast LNG, LLC (“BG”), which is guaranteed by BG Energy Holdings
Limited;
approximately $550 million from Korea Gas Corporation (“KOGAS”);
approximately $550 million from GAIL;
approximately $450 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM,
Limited) (“Naturgy”), which is guaranteed by Naturgy Energy Group, S.A. (formerly known as Gas Natural SDG
S.A.); and
approximately $310 million from Total Gas & Power North America, Inc. (“Total”), which is guaranteed by Total S.A.
The annual aggregate fixed fees for all of SPL’s other SPAs with third-parties is approximately $490 million, prior to
giving effect to an SPA that Cheniere has committed to provide to SPL.
The following table shows customers with revenues of 10% or greater of total revenues from external customers:
BG
GAIL
KOGAS
Naturgy
Total
* Less than 10%
Natural Gas Transportation, Storage and Supply
Percentage of Total Revenues from External Customers
Year Ended December 31,
2019
27%
20%
19%
18%
*
2018
28%
19%
23%
21%
*
2020
24%
18%
17%
15%
11%
To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into
transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party
pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in
natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply
contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2020, SPL
had secured up to approximately 4,950 TBtu of natural gas feedstock through long-term and short-term natural gas supply
contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.
8
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 6 of the Liquefaction Project, under which Bechtel charges a lump sum for
all work performed and generally bears project cost, schedule and performance risks 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 price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion,
including estimated costs for the third marine berth that is currently under construction. As of December 31, 2020, we have
incurred $1.9 billion under this contract.
Regasification Facilities
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG
storage capacity of approximately 17 Bcfe. Approximately 2 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 and Chevron U.S.A. Inc. (“Chevron”) has reserved
approximately 1 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating
approximately $125 million annually, prior to inflation adjustments, 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 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, prior to inflation adjustments,
continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial
completion of Train 5 of the Liquefaction Project, SPL gained access to substantially all of Total’s capacity and other services
provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the
Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading
activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6.
Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to
be made by Total to SPLNG in accordance with its TUA. During the years ended December 31, 2020, 2019 and 2018, SPL
recorded $129 million, $104 million and $30 million, respectively, as operating and maintenance expense under this partial
TUA assignment agreement.
Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.
Governmental Regulation
The Sabine Pass LNG terminal and the Creole Trail Pipeline are subject to extensive regulation under federal, state and
local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state
agencies and that we obtain and maintain applicable permits and other authorizations. These regulatory requirements increase
the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of
necessary authorizations.
Federal Energy Regulatory Commission
The design, construction, operation, maintenance and expansion of the Sabine Pass LNG terminal, the import or export
of LNG and the purchase and transportation of natural gas in interstate commerce through the Creole Trail Pipeline are highly
regulated activities subject to the jurisdiction of the FERC pursuant to the Natural Gas Act of 1938, as amended (the “NGA”).
Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the
sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the
construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.
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The FERC’s authority to regulate interstate natural gas pipelines and the services that they provide generally includes
regulation of:
•
•
•
•
•
•
•
rates and charges, and terms and conditions for natural gas transportation, storage and related services;
the certification and construction of new facilities and modification of existing facilities;
the extension and abandonment of services and facilities;
the administration of accounting and financial reporting regulations, including the maintenance of accounts and
records;
the acquisition and disposition of facilities;
the initiation and discontinuation of services; and
various other matters.
Under the NGA, our pipeline is not permitted to unduly discriminate or grant undue preference as to rates or the terms
and conditions of service to any shipper, including its own marketing affiliate. Those rates, terms and conditions must be
public, and on file with the FERC.
In contrast to pipeline regulation, the FERC does not require LNG terminal owners to
provide open-access services at cost-based or regulated rates. Although the provisions that codified FERC’s policy in this area
expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area.
We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing
certificate automatically granted by the FERC to our marketing affiliates. Our sales of natural gas will be affected by the
availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation
are subject to extensive federal and state regulation.
In order to site, construct and operate the Sabine Pass LNG terminal, we received and are required to maintain
authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and
permits. 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,
unless specifically provided otherwise in the EPAct, amendments to the NGA. For example, nothing in the EPAct amendments
to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities
related to LNG terminals or those of a state acting under federal law.
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 (and related facilities).
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 permitted LNG production capacity of Trains 1 through 4 from the then authorized
803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity of Trains 1
through 4. 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 issued an order
denying the rehearing request (the “FERC Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the
District of Columbia Circuit (the “Court of Appeals”) to review the February 2014 Order and the FERC Order Denying
Rehearing. The court denied the petition in June 2016.
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 an order issued in April
2015 and an order denying rehearing issued in June 2015. These orders are not subject to appellate court review. In October of
2018, SPL applied to the FERC for authorization to add a third marine berth to the Liquefaction Project, which FERC approved
in February of 2020.
The Creole Trail Pipeline, which interconnects with the Sabine Pass LNG terminal, holds 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.
In 2013, the FERC approved
CTPL’s application for authorization to construct, own, operate and maintain certain new facilities in order to enable bi-
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directional natural gas flow on the Creole Trail Pipeline system to allow for the delivery of up to 1,530,000 Dekatherms per day
of feed gas to the Sabine Pass LNG terminal. 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.
In September 2013, we filed an application with the FERC for authorization to construct and operate an
extension and expansion of Creole Trail Pipeline and related facilities in order to deliver additional domestic natural gas
supplies to the Sabine Pass LNG terminal, which was granted by the FERC in an order issued in April 2015 and an order
denying rehearing issued in June 2015. These orders are not subject to appellate court review.
On September 27, 2019, SPL filed a request with the FERC pursuant to Section 3 of the NGA, requesting authorization
to increase the total LNG production capacity of the terminal from currently authorized levels to an amount which reflects more
accurately the capacity of the facility based on enhancements during the engineering, design and construction process, as well
as operational experience to date. The requested authorizations do not involve construction of new facilities. Corresponding
applications for authorization to export the incremental volumes were also submitted to the DOE.
The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate
that engages in natural gas marketing functions. The general principles of the FERC 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 due to the improper disclosure of non-public
transmission function information. We have established the required policies, procedures and training to comply with the
FERC’s Standards of Conduct.
All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the
FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC
rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal
penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per
day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other material governmental and regulatory approvals and permits will be required throughout the life of our
LNG terminal and the Creole Trail Pipeline.
In addition, our FERC orders require us to comply with certain ongoing
conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of our LNG terminal and
Creole Trail Pipeline. For example, throughout the life of our LNG terminal and the Creole Trail Pipeline, we are subject to
regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials
Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and
maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for
these approvals and reporting obligations have not materially affected our construction or operations.
DOE Export Licenses
The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal as
discussed in Liquefaction Facilities. Although it is not expected to occur, the loss of an export authorization could be a force
majeure event under our SPAs.
Under Section 3 of the NGA applications for exports of natural gas to FTA countries, which allow for national treatment
for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without
“modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain,
Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua,
Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for
trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment
proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such
authorization would not be consistent with the public interest.
Pipeline and Hazardous Materials Safety Administration
Our LNG terminal as well as the Creole Trail Pipeline are subject to regulation by PHMSA. PHMSA is authorized by
the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The
11
regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation,
maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or
foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.
In October 2019, PHMSA published final rules revising its regulations governing the safety of certain gas transmission
pipelines (effective July 1, 2020) and established new enforcement procedures for the issuance of temporary emergency orders
(effective December 2, 2019).
PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions,
including issuance of civil penalties up to approximately $218,000 per day per violation, with a maximum administrative civil
penalty of approximately $2 million for any related series of violations.
Other Governmental Permits, Approvals and Authorizations
Construction and operation of the Sabine Pass LNG terminal requires additional permits, orders, approvals and
consultations to be issued
by various federal and state agencies, including the DOT, U.S. Army Corps of Engineers
(“USACE”), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and
Wildlife Service (“FWS”), the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security and
the LDEQ.
The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and
Harbors Act (Section 10) (the “Section 10/404 Permit”). The EPA administers the Clean Air Act, and has delegated authority
to the LDEQ to issue the Title V Operating Permit (the “Title V Permit”) and the Prevention of Significant Deterioration Permit
(the “PSD Permit”). These two permits are issued by the LDEQ for the Sabine Pass LNG terminal and CTPL.
Commodity Futures Trading Commission (“CFTC”)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity
Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that
participate in those markets. Most of the regulations are already in effect, while other rules and regulations, including the new
rules on speculative position limits that were finalized by the CFTC on October 15, 2020, are in the process of being phased in.
The full impact of the CFTC’s position limits rules is not yet known and these rules could have significant impact on our
business.
As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require
Swap Dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/
or 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 non-financial-entity end users who
qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other
counterparties in certain instances. We qualify as a non-financial-entity end user with respect to the swaps that we enter into to
hedge our commercial risks.
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, deceptive or fraudulent schemes or material misrepresentation in
the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on
commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on
which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a
CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.
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 require significant expenditures for
compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and
substantial liabilities for pollution. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts
12
to the environment or the types, quantities and concentration of substances that can be released into the environment and can
lead to substantial administrative, 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 operations 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 requiring annual reporting
of greenhouse gas (“GHG”) emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to
In addition, the EPA has defined GHG emissions thresholds that would
include reporting obligations for LNG terminals.
subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit
requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional
actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production
industries, those rules were largely stayed or repealed during the Trump Administration including by amendments adopted by
the EPA on February 23, 2018 and additional amendments to new source performance standards for the oil and gas industry on
September 14 and 15, 2020. On January 20, 2021, President Biden issued an executive order directing the EPA to consider
publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could
result in more stringent GHG emissions rulemaking. We are supportive of regulations reducing GHG emissions over time.
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. 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, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Coastal Zone Management Act (“CZMA”)
The siting and construction of the Sabine Pass LNG terminal within the coastal zone is subject to the requirements of the
CZMA. 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
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 generation, handling and disposal of solid and hazardous
wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the
operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage
and disposal of such wastes.
Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act (the “ESA”), the Migratory Bird Treaty Act
(“MBTA”), the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened
13
animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources.
If the Sabine Pass LNG
terminal or the Creole Trail Pipeline adversely affect a protected species or its habitat, we may be required to develop and
follow a plan to avoid those impacts. In that case, siting, construction or operation may be delayed or restricted and cause us to
incur increased costs.
In August 2019, the FWS announced a series of changes to the rules implementing the ESA, including revisions to the
regulations governing interagency cooperation,
listing species and delisting critical habitat, and prohibitions related to
threatened wildlife and plants, and in August and September 2020, the FWS proposed additional changes to its regulations for
designating critical habitat. The revisions are intended to streamline these processes and create more flexibility for the FWS
when making ESA-related decisions.
In addition, in January 2021, the FWS issued a final rule defining the scope of the MBTA to cover only actions
intentionally directed at migratory birds, their nests or their eggs.
On January 20, 2021, President Biden issued an executive order directing the heads of all agencies to immediately
review all regulatory actions taken between January 20, 2017 and January 20, 2021, including FWS regulations implementing
the ESA and the MBTA and EPA regulations implementing the CWA and the Oil Pollution Act, which could result in stricter
requirements with respect to endangered or threatened animal, fish and plant species and/or their designated habitats, migratory
birds, wetlands or other natural resources.
It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats
and wetlands and impact our business. However, we do not believe that our operations, or the construction and operations of
the Sabine Pass LNG terminal, will be materially and adversely affected by such regulatory actions.
Market Factors and Competition
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 operating
two Trains and is commissioning one additional Train at a natural gas liquefaction facility near Corpus Christi, Texas and
Corpus Christi Liquefaction, LLC (“CCL”) has entered into fixed price SPAs generally with terms of 20 years (plus extension
rights) and with a weighted average remaining contract length of approximately 19 years (plus extension rights) with nine third
parties 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. Many of the companies with which we compete
are major energy corporations with longer operating histories, more development experience, greater name recognition, greater
financial, technical and marketing resources and greater access to markets than us. Our affiliates have proximity to our
customers, with offices located in Houston, London, Singapore, Beijing and Tokyo.
SPLNG currently does not experience competition for its terminal capacity because the entire approximately 4 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.
Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sale of LNG by
Cheniere Marketing, or development of new projects is subject to market factors. These factors include 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, the rate of fuel switching for power generation from coal, nuclear or oil to
In addition, Cheniere’s ability to obtain additional funding to
natural gas and economic growth in developing countries.
execute its business strategy is subject to the investment community’s appetite for investment in LNG and natural gas
infrastructure and Cheniere’s ability to access 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. Players around the globe have shown commitments to
environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure
growth. Currently, hundreds of billions of dollars are being invested across Europe and Asia in natural gas projects under
construction, and if we included planned commitments, the total would exceed $1 trillion. Some examples include India’s
14
commitment to invest over $60 billion to drive its gas-based economy, Europe’s commitment of well over $100 billion in gas-
fired power, import terminals and pipelines, and China’s hundreds of billions all along the natural gas value chain. We
highlight regasification capacity, which will not only expand existing import capacities in rapidly growing markets like China
and India, but also add new import markets all over the globe, raising the total to approximately 60 by 2030 from 43 today and
just 15 markets as recently as 2005.
As a result of these dynamics, global demand for natural gas is projected by the International Energy Agency to grow by
approximately 21 trillion cubic feet (“Tcf”) between 2019 and 2030 and 42 Tcf between 2019 and 2040. LNG’s share is seen
growing from about 12% in 2019 to about 16% of the global gas market in 2030 and 19% in 2040. Wood Mackenzie Limited
(“WoodMac”) forecasts that global demand for LNG will increase by approximately 56%, from approximately 347 mtpa, or
16.6 Tcf, in 2019, to approximately 541 mtpa, or 26.0 Tcf, in 2030 and to 723 mtpa or 34.7 Tcf in 2040. WoodMac also
forecasts LNG production from existing operational facilities and new facilities already under construction will be able to
supply the market with approximately 476 mtpa in 2030, declining to 381 mtpa in 2040. This will result in a market need for
construction of an additional approximately 65 mtpa of LNG production by 2030 and about 343 mtpa by 2040. As a cleaner
burning fuel with far lower emissions than coal or liquid fuels in power generation, we expect gas and LNG to play a central
role in balancing grids and contributing to a low carbon energy system globally. We believe the capital and operating costs of
the uncommitted capacity of our Liquefaction Project is competitive with new proposed projects globally and we are well-
positioned to capture a portion of this incremental market need.
Our LNG terminal business has limited exposure to the decline in oil prices 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. We have contracted
approximately 75% of the total production capacity from the Liquefaction Project on a term basis, with approximately 17 years
of average remaining life as of December 31, 2020, which includes volumes contracted under SPAs in which the customers are
required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of
LNG cargoes. As of January 31, 2021, U.S. natural gas 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 and medium-term contracting of LNG from our terminal.
Subsidiaries
Our assets are generally held by 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, 2021, Cheniere and its subsidiaries had 1,519
full-time employees, including 490 employees who directly supported the Sabine Pass LNG terminal operations. See Note 14
—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 us, SPLNG, SPL and CTPL.
Available Information
Our common units have been publicly traded since March 21, 2007 and are traded on the NYSE American 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. 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.
15
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. The SEC maintains an internet site
(www.sec.gov) that contains reports and other information regarding issuers.
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.
Risk Factor Summary
Each of the risk factors outlined below are discussed more fully following this summary:
Risks Relating to Our Financial Matters
Our operating results, cash flows and/or liquidity could be adversely affected by the following factors:
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Our existing level of cash resources and significant debt
Dilution of our unitholders’ proportionate indirect interests in our assets, business operations and our projects from
sale of equity or equity-related securities or assets
Failure by any significant customer to perform under their long-term contracts with us
Termination of our customer contracts under certain circumstances
Use of hedging arrangements
Certain rules and regulations could adversely affect our ability to hedge risks
Risks Relating to Our Business
The operations of our Sabine Pass LNG terminal, construction of the remaining or additional Trains and the commercialization
of the LNG produced could be adversely affected by the following factors:
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COVID-19 global pandemic and volatility in the energy markets
Outbreaks of infectious diseases, such as the outbreak of COVID-19, at one or more of our facilities
Cost overruns and delays in construction, as well as difficulties in obtaining sufficient financing to pay for such costs
and delays
Hurricanes or other disasters
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies
Delays in construction leading to reduced revenues or termination of one or more of the SPAs by our customers
Dependency on Cheniere for key personnel, and the unavailability of skilled workers or failure to attract and retain
qualified personnel, including changes in our general partner’s senior management or other key personnel
Conflict of interest with Cheniere and its affiliates
Dependency on Bechtel and other contractors
Unavailability of third-party pipelines, and other facilities interconnected to our pipelines and facilities, to transport
natural gas
Inability to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the
SPAs
Significant construction and operating hazards and uninsured risks
Cyclical or other changes in the demand for and price of LNG and natural gas
Failure of imported or exported LNG to be a competitive source of energy for the United States or international
markets
Various economic and political factors
Impediments to the transport of LNG, such as shortages of LNG vessels, or operational impacts on LNG shipping
Securing firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation
requirements
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Competition based upon the international market price for LNG
Terrorist attacks, cyber incidents or military campaigns
Existing and future environmental and similar laws and governmental regulations
FERC regulations
A major health and safety incident relating to our business
Pipeline safety integrity programs and repairs
Loss of our right to situate our pipelines on property owned by third parties
Inaccurate estimates for the future capacity ratings and performance capabilities of the Liquefaction Project
Lack of diversification
Limited growth that could result from failure to make acquisitions or implementation of capital expansion projects not
made on economically acceptable terms
Acquisitions that may limit our ability to make distributions
Impairments to goodwill or long-lived assets
Risks Relating to Our Cash Distributions
The amount of cash available for cash distributions and our ability to pay cash distribution could be adversely affected by the
following factors:
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Ability to maintain or increase our cash available for distribution
Satisfaction of our indebtedness and terms of our future indebtedness
Restriction of our subsidiaries to make distributions to us
Restrictions in agreements governing our subsidiaries’ indebtedness
Payment of management fees and cost reimbursements to our general partner and its affiliates
Level of our cash flow
Ability to make accretive acquisitions or implement accretive capital expansion projects
Risks Relating to an Investment in Us and Our Common Units
Investment in us and our common units could be adversely affected by the following factors:
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Conflicts of interest and limited fiduciary duties by our general partner and its affiliates
Competition by Cheniere
Limitation of our general partner’s fiduciary duties to our unitholder
Unitholders' limited voting rights
Inability to initially remove our general partner without its consent
Transfer of control of our general partner to a third party without unitholder consent
Restriction of voting rights of unitholders owning 20% or more of our units
Certain provisions of our partnership agreement which could discourage a change of control
Limitations on the liability of holders of limited partner interests in certain circumstances
Liability to repay distributions wrongfully made
Dilution from issuance of additional units without unitholder approval
Fluctuation in the market price of our common units
Sale of limited partner units by affiliates of our general partner or affiliates of Blackstone or Brookfield
Risks Relating to Tax Matters
The following tax matters could adversely affect our business or our cash available for distribution and/or our unitholders:
Tax treatment as a corporation instead of a partnership for federal income tax purposes
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• Material amount of additional entity-level taxation by individual states
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Change in tax treatment from legislative, judicial or administrative changes and differing interpretations
Proration of items between transferors and transferees of our common units
Successful IRS contest of the federal income tax positions that we take
Audit adjustments to our income tax returns by the IRS
Taxation on unitholders’ share of our taxable income
Tax gain or loss on the disposition of our common units
Limitation on unitholders’ ability to deduct interest expense
Unique tax issues for unitholders that are tax-exempt entities
Subjectivity to U.S. taxes and withholding by non-U.S. unitholders
IRS challenge of our treatment of our unitholders’ tax benefits
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Subjectivity to state and local taxes and return filing requirements by our unitholders
IRS challenge of our valuation methodologies in determining a unitholder’s allocation of income, gain, loss and
deduction
Tax consequences for unitholders whose common units are the subject of a securities loan
Risks Relating to Our Financial Matters
Our existing level of cash resources and significant debt could cause us to have inadequate liquidity and could materially
and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
As of December 31, 2020, we had $1.2 billion of cash and cash equivalents, $0.1 billion of current restricted cash, $750
million of available commitments under the $750 million revolving credit facility (the “2019 CQP Credit Facilities”) and $17.8
billion of total debt outstanding on a consolidated basis (before unamortized premium, discount and debt issuance costs),
excluding $413 million aggregate outstanding letters of credit. We incur, and will incur, significant interest expense relating to
the assets at the Sabine Pass LNG terminal. 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 and the repricing 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 was 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.
We may sell equity or equity-related securities or assets, including additional common units. Such sales could dilute our
unitholders’ proportionate indirect interests in our assets, business operations, Liquefaction Project and other projects.
We have historically pursued a number of alternatives in order to finance the construction of our Trains, 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 significant customer fails to perform its
contractual obligations for any reason.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under
long-term contracts. As of December 31, 2020, SPL had SPAs with eight third-party customers and SPLNG had TUAs with
two third-party customers. We are dependent on each customer’s continued willingness and ability to perform its obligations
under its SPA or TUA. We are exposed to the credit risk of any guarantor of these customers’ obligations under their
respective agreements in the event that we must seek recourse under a guaranty. As a result of the disruptions caused by the
COVID-19 pandemic and the volatility in the energy markets, we believe we are exposed to heightened credit and performance
risk of our customers. Additionally, some customers have indicated to us that COVID-19 has impacted their operations and/or
may impact their operations in the future. Some of our SPA customers’ primary countries of business have experienced a
significant number of COVID-19 cases and/or have been subject to government imposed lockdown or quarantine measures.
Although we believe that impacts of the COVID-19 pandemic on LNG regasification facilities, downstream markets and
broader energy demand do not constitute valid force majeure claims under our FOB LNG SPAs, if any significant customer
fails to perform its obligations under its SPA or TUA, 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, if any, for a breach of the agreement.
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Each of our customer contracts is subject to termination under certain circumstances.
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.
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.
Our use of hedging arrangements may adversely affect our future operating results or liquidity.
To reduce our exposure to fluctuations in commodity-related marketing and price risks, we enter into derivative financial
instruments, including futures, swaps and option contracts. To the extent we hedge our exposure to commodity price, we
forego the benefits we would otherwise experience if commodity prices were to change favorably to our hedged position.
Hedging arrangements could also expose us to risk of financial loss in some circumstances, including when:
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expected supply is less than the amount hedged or is otherwise imperfect;
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.
Our use of derivative financial instruments are recorded at fair value on our Consolidated Balance Sheets with changes in
the fair value resulting from fluctuations in the underlying commodity prices or hedged item recognized in earnings, unless they
satisfy criteria for, and we elect, the normal purchases and sales exception or hedge accounting treatment. All of our derivative
financial instruments do not qualify for these exceptions from fair value reporting through earnings. As a result, our quarterly
and annual results are subject to significant fluctuations caused by changes in fair value, including circumstances in which there
is no underlying economic impact yet realized.
The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working
capital when commodity prices change.
The 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.
The provisions of the Dodd-Frank Act and the rules adopted by the CFTC, the SEC and other federal regulators
establishing federal regulation of the over-the-counter (“OTC”) derivatives market and entities like us that participate in that
market 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 terminal and to secure natural gas feedstock for our Liquefaction Project.
As required by the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require certain
market participants to collect and post initial and/or variation margin with respect to uncleared swaps from their counterparties
that are financial end users and certain registered swap dealers and major swap participants. Although we believe we will not
be required to post margin with respect to any uncleared swaps we enter into in the future, were we required 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, contractually 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.
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Risks Relating to Our Business
The COVID-19 global pandemic and volatility in the energy markets may materially and adversely affect our business,
financial condition, operating results, cash flow, liquidity and prospects.
The COVID-19 global pandemic has resulted in significant disruption globally. Actions taken by various governmental
authorities, individuals and companies around the world to prevent the spread of COVID-19 have restricted travel, business
operations, and the overall level of individual movement and in-person interaction across the globe. Additionally, recent
disputes over production levels between members of the Organization of Petroleum Exporting Countries and other oil
producing countries have resulted in increased volatility in oil and natural gas prices.
The extent, duration and magnitude of the COVID-19 pandemic’s effects will depend on future developments, all of
which are highly uncertain and difficult to predict, including the impact of the pandemic on global and regional economies,
travel, and economic activity, as well as actions taken by governments, businesses and individuals in response to the pandemic
or any future resurgence. These developments include the impact of the COVID-19 pandemic on unemployment rates, the
demand for oil and natural gas, levels of consumer confidence and the post-pandemic pace of recovery.
Many uncertainties remain with respect to the COVID-19 pandemic, and we continue to monitor the rapidly evolving
situation. The COVID-19 pandemic alone or coupled with continued volatility in the energy markets may materially and
adversely affect our business, financial condition, operating results, cash flow, liquidity and prospects or have the effect of
heightening many of the other risks described herein. The extent to which our business, contracts, financial condition,
operating results, cash flow, liquidity and prospects are affected by the COVID-19 global pandemic or volatility in the energy
markets will depend on various factors beyond our control and are highly uncertain, including the duration and scope of the
outbreak, decreased demand for LNG and the resulting economic effects of the COVID-19 global pandemic.
Outbreaks of infectious diseases, such as the outbreak of COVID-19, at our facilities could adversely affect our operations.
Federal, state and local governments have enacted various measures to try to contain the outbreak of COVID-19, such as
travel bans and restrictions, quarantines, shelter-in-place orders and business shutdowns. Our facilities at the Sabine Pass LNG
terminal are critical infrastructure and have continued to operate during the outbreak, which means that Cheniere must keep its
employees who operate our facilities safe and minimize unnecessary risk of exposure to the virus. In response, Cheniere has
taken extra precautionary measures to protect the continued safety and welfare of its employees who continue to work at our
facilities and have modified certain business and workforce practices, such as implementing work from home policies where
appropriate, but there can be no assurances that these measures will prevent any outbreak. Furthermore, the measures taken to
prevent an outbreak at our facilities have resulted in increased costs and it is unclear how long such increased costs will
continue to be incurred. If a large number of Cheniere’s employees in those critical facilities were to contract COVID-19 at the
same time, our operations could be adversely affected.
Cost overruns and delays in the completion of Train 6 or any future 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 Train 6 and any future 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 our EPC contractor the right to cause us to enter into change orders or resulting from changes
with which we otherwise agree. We have already experienced increased costs due to change orders. 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, including change orders to comply with existing or future environmental or other
regulations.
The COVID-19 pandemic and the resulting actions taken by governmental and regulatory authorities to prevent the
spread of COVID-19 may cause a slow-down in the construction of one or more Trains. Our EPC contractor has advised us of
voluntary proactive measures it is taking to protect employees and to mitigate risks associated with COVID-19, however, it has
not indicated that there will be any changes to the project cost or schedule and is still performing its obligations under its EPC
contract. While the construction of Train 6 is continuing, if there were a major outbreak of COVID-19 at any construction site
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or the implementation of restrictions by the government that prevented construction for an extended period, we could
experience significant delays in the construction of one or more Trains.
Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to
our existing EPC contract 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 fully 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.
Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of the Liquefaction
Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us.
Hurricanes Katrina and Rita in 2005, Hurricane Ike in 2008, Hurricane Harvey in 2017 and Hurricanes Laura and Delta in
2020 caused temporary suspension in construction or operation of our Liquefaction Project or caused minor damage to our
Liquefaction Project.
In August 2020, SPL entered into an arrangement with its affiliate to provide the ability, in limited
circumstances, to potentially fulfill commitments to LNG buyers from the other facility in the event operational conditions
impact operations at the Sabine Pass LNG terminal or at its affiliate’s terminal. During the year ended December 31, 2020, 17
TBtu was loaded at affiliate facilities pursuant to this agreement. 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 and increase our insurance premiums. The U.S. Global Change Research
Program has reported that the U.S.’s energy and transportation systems are expected to be increasingly disrupted by climate
change and extreme weather events. An increase in frequency and severity of extreme weather events such as storms, floods,
fires and rising sea levels could have an adverse effect on our operations.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design,
construction and operation of our facilities, the operation of our pipeline and the export of LNG 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 purchase and 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 orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related
facilities and Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline, the FERC orders
require us to comply with certain ongoing conditions and obtain certain additional approvals in conjunction with ongoing
construction and operations of the Liquefaction Project and the operations of the Creole Trail Pipeline. We will be required to
obtain similar approvals and permits with respect to any expansion or modification of our liquefaction and pipeline facilities.
We cannot control the outcome of the regulatory review and approval processes. Certain of these governmental permits,
approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies also contain ongoing
conditions, and additional approval and permit requirements may be imposed. We do not know whether or when any such
approvals or permits can be obtained, or whether 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, including as a result of untimely notices or filings, we may not be able to recover our
investment in our projects. Additionally, government disruptions, such as a U.S. government shutdown, may delay or halt our
ability to obtain and maintain necessary approvals and permits. 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,
contracts, financial condition, operating results, cash flow, liquidity and prospects.
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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 customers.
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.
In particular, each of our SPAs provides that the customer may
terminate that SPA if the relevant Train does not timely commence commercial operations. 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.
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, 2021, Cheniere and its subsidiaries had 1,519 full-time employees, including 490 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 and operation of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining
personnel sufficient to provide support for the Sabine Pass LNG terminal. Cheniere competes with other liquefaction projects
in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the
technical skills and experience required to construct and operate liquefaction facilities and pipelines and to provide our
customers with the highest quality service. We also compete with any other project Cheniere is developing, including its
liquefaction project at Corpus Christi, Texas, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere 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.
The executive officers of our general partner are officers and employees of Cheniere and its affiliates. 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.
A shortage in the labor pool of skilled workers or other general inflationary pressures, changes in applicable laws and
regulations or labor dispute 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. Any increase in our operating costs
could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and
prospects.
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 Marketing
has entered into an SPA to purchase: (1) at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required
for other customers and (2) up to 30 cargoes scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per
MMBtu. 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 operating two Trains and is constructing one additional Train at a natural
gas liquefaction facility near Corpus Christi, Texas and CCL has entered into fixed price SPAs with third parties 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 or any future Trains.
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 terminate
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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:
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design and engineer each Train to operate in accordance with specifications;
engage and retain third-party subcontractors and procure equipment and supplies;
respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by
subcontractors, some of which are beyond their control;
attract, develop and retain skilled personnel, including engineers;
post required construction bonds and comply with the terms thereof;
• manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
• maintain their own financial condition, including adequate working capital.
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 Liquefaction Project, 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 Liquefaction Project
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.
If third-party pipelines and other facilities interconnected to our pipeline and facilities are or become unavailable to
transport natural gas, this could have a material adverse effect on our business, contracts, financial condition, operating
results, cash flow, liquidity and prospects.
We depend upon third-party pipelines and other facilities that 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 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, contracts, financial condition, operating results, cash flow, 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 customers, we are required to make available 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 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.
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We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create
significant liabilities and losses for us.
The construction and operation of the Sabine Pass LNG terminal and the operation of the Creole Trail Pipeline are, and
will be, subject to the inherent risks associated with these types of operations, including explosions, breakdowns or failures of
equipment, operational errors by vessel or tug operators, 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:
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additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert
LNG from the Sabine Pass LNG terminal;
competitive liquefaction capacity in North America;
insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
insufficient LNG tanker capacity;
weather conditions, including extreme weather events and temperature volatility resulting from climate change;
reduced demand and lower prices for natural gas;
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a
result of any potential ban on production of natural gas through hydraulic fracturing;
cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction
capabilities at reduced prices;
changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and
solar energy, which may reduce the demand for natural gas;
changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or
alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
political conditions in natural gas producing regions;
sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of
a pandemic, and other catastrophic events;
adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from
North America; and
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
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Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or 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 for the United States or international markets
could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition,
operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Project are 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 alternative
energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered
outside the United States, which could increase the available supply of natural gas outside the United States and could result in
natural gas in those markets being available at a lower cost than LNG exported to those markets.
Although SPL has entered into arrangements to utilize up to approximately three-quarters of the regasification capacity
at the Sabine Pass LNG terminal in connection with operations of the Liquefaction Project, operations at the Sabine Pass LNG
terminal are dependent, in part, 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.
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 purchasers or suppliers and merchants in such countries to
import or export LNG from or to the United States. Furthermore, some foreign purchasers or suppliers of LNG may have
economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’
liquefaction or regasification 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. LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is
priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the
Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project,
may also be impacted by an increase in natural gas prices in the United States.
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 in markets accessible to our customers 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.
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Various economic and political factors could negatively affect the development, construction and operation 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:
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increased construction costs;
economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing
for LNG projects on commercially reasonable terms;
decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;
the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security
concerns; and
any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
There may be impediments to the transport of LNG, such as shortages of LNG vessels worldwide or operational impacts on
LNG shipping, including maritime transportation routes, 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. Additionally,
the availability of LNG vessels and transportation costs could be impacted to the detriment of our business and our customers
because of:
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an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
shortages of or delays in the receipt of necessary construction materials;
political or economic disturbances;
changes in governmental regulations or maritime self-regulatory organizations;
work stoppages or other labor disturbances;
bankruptcy or other financial crisis of shipbuilders or shipowners;
quality or engineering problems;
disruptions to maritime transportation routes; and
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.
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 the Liquefaction
Project. If and when we need to replace one or more of our existing 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.
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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 or any future
Trains. 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:
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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
displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not
currently available.
Terrorist attacks, cyber incidents or military campaigns may adversely impact our business.
A terrorist attack, cyber incident 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 Train 6, which would increase our costs and
decrease our cash flows. A terrorist incident or cyber 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, cyber incidents 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, rules and regulations applicable to our
construction and operation activities relating to, among other things, air quality, water quality, waste management, natural
resources and health and safety. 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.
In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and
operation of our LNG terminal and pipeline, including FERC and PHMSA, to issue compliance orders, which may restrict or
limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial
liabilities, compliance orders, fines and penalties or to capital expenditures 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.
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In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of
In 2010, the EPA expanded the rule to include reporting
GHG emissions from stationary sources in a variety of industries.
obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions
from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions
of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG
emissions from the electric power generation and the oil and gas exploration and production industries, those rules were largely
stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and
additional amendments to new source performance standards for the oil and gas industry on September 14 and 15, 2020. On
January 20, 2021, President Biden issued an executive order directing the EPA to consider publishing for notice and comment a
proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent GHG emissions
rulemaking. In addition, other federal and state initiatives may be considered in the future to address GHG emissions through,
for example, United States treaty commitments, direct regulation, market-based regulations such as a carbon emissions tax or
cap-and-trade programs or clean energy standards. Such initiatives could affect the demand for or cost of natural gas, which we
consume at our terminals, or could increase compliance costs for our operations. We are supportive of regulations reducing
GHG emissions over time.
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 or climate policies of destination countries in relation to their obligations under
the Paris Agreement or other national climate change-related policies, could cause additional expenditures, restrictions and
delays in our business and to our proposed construction activities, 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 tariff are subject to FERC regulation.
The Creole Trail Pipeline is subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978
(the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the
construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the
NGA, the rates charged by CTPL 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 we fail to comply with all
applicable statutes, rules, regulations and orders, CTPL could be subject to substantial penalties and fines.
In addition, as a natural gas market participant, should CTPL fail to comply with all applicable FERC-administered
statutes, rules, regulations and orders, CTPL could be subject to substantial penalties and fines. Under the EPAct, the FERC
has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.3 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
damages.
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 PHMSA 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, CTPL is required to:
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventative and mitigating actions.
CTPL is 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
CTPL fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, CTPL
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.
We are relying on estimates for 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.
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 2021 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:
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if we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
if we are unable to identify attractive capital expansion projects or negotiate acceptable engineering procurement and
construction arrangements for them;
if we are unable to obtain necessary governmental approvals;
if we are unable to obtain financing for the acquisitions or capital expansion projects on economically acceptable
terms, or at all;
if we are unable to secure adequate customer commitments to use the acquired or expansion facilities; or
if we are outbid by competitors.
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.
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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 liquefaction project at Corpus
Christi, Texas.
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;
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• mistaken assumptions about the cash generated, or to be generated, by the business acquired or the overall costs of
equity or debt;
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the diversion of management’s and employees’ attention from other business concerns; and
unforeseen difficulties encountered in operating new business segments or in new geographic areas.
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
In addition, if we issue additional units in
consider in determining the application of our future funds and other resources.
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.
Prior to the quarter ended September 30, 2017, we historically paid the initial quarterly distribution of $0.425 on each of
our common units and the related distribution on our general partner units, and did not pay any distributions on our
subordinated units. For the quarter ended September 30, 2017 and in each of the subsequent quarters, we have paid increasing
distributions on each of our common and subordinated units and the related distribution on our general partner units. For the
quarter ended December 31, 2017 and in each of the subsequent quarters, we also paid the related distribution to the holder of
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our incentive distribution rights (“IDRs”). During the year ended December 31, 2020, we paid aggregate distributions of $1.4
billion on our common units, subordinated units and related general partner units including IDRs.
In July 2020, the board of directors of our general partner confirmed and approved that, following the distribution with
respect to the three months ended June 30, 2020, the financial tests required for conversion of our subordinated units had been
met under the terms of the partnership agreement. Accordingly, effective August 17, 2020, the first business day following the
payment of the distribution, all of our subordinated units were automatically converted into common units on a one-for-one
basis and the subordination period was terminated.
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:
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performance by counterparties of their obligations under the SPAs;
performance by SPL of its obligations under the SPAs;
performance by counterparties of their obligations under the TUAs;
performance by SPLNG of its obligations under the TUAs;
performance by, and the level of cash receipts received from, Cheniere Marketing under the amended and restated
variable capacity rights agreement; and
the level of our operating costs, including payments to our general partner and its affiliates.
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 our ability to pay
distributions under our credit facilities and the ability of SPL to pay distributions to us under its working capital
facility and senior notes;
the costs and capital requirements of acquisitions, if any;
fluctuations in our working capital needs;
our ability to borrow for working capital or other purposes; and
the amount, if any, of cash reserves established by our general partner.
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
could 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, 2020, we had $17.8 billion of total debt outstanding on a consolidated basis (before unamortized
premium, discount and debt issuance costs). We anticipate refinancing of consolidated indebtedness in the future, which could
be at higher interest rates and have different maturity dates and more restrictive covenants than our current outstanding
indebtedness. $1.0 billion will mature in 2022, $1.5 billion will mature in 2023, $2.0 billion will mature in 2024, $3.5 billion
will mature in 2025, approximately $9.0 billion will mature between 2026 and 2030 and approximately $0.8 billion will mature
in 2037. We are not generally required to make principal payments on any of our long-term indebtedness prior to maturity.
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. SPLNG's TUAs with Total and Chevron will expire in 2029 unless extended and
SPL’s SPAs will expire beginning in 2033 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,
contracts, financial condition, operating results, cash flow, liquidity and prospects.
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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, SPL is restricted from making distributions under the
agreements governing its indebtedness generally until, among other requirements, 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 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:
• make certain investments;
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purchase, redeem or retire equity interests;
issue preferred stock;
sell or transfer assets;
incur liens;
enter into transactions with affiliates;
consolidate, merge, sell or lease all or substantially all of its assets; and
enter into sale and leaseback transactions.
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 14—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. Any reduction in the amount of cash available for distributions could impact our ability to
pay quarterly distributions to our unitholders.
We may not be able to maintain or increase the distributions on our common 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 allow us to maintain or increase common unitholder
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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.
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 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:
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neither our partnership agreement nor any other agreement requires Cheniere to pursue a business strategy that favors
us. Cheniere’s directors and officers have a fiduciary duty to make these decisions in favor of the owners of Cheniere,
which may be contrary to our interests:
our general partner controls the interpretation and enforcement of contractual obligations between us, on the one hand,
and Cheniere, on the other hand, including provisions governing administrative services and acquisitions;
our general partner is allowed to take into account the interests of parties other than us, such as Cheniere and its
affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us and our unitholders;
our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also
restricting the remedies available to our unitholders for actions that, without these limitations, might constitute
breaches of fiduciary duty;
Cheniere is not limited in its ability to compete with us. Please read “Cheniere is not restricted from competing with
us and is free to develop, operate and dispose of, and is currently developing, LNG facilities, pipelines and other assets
without any obligation to offer us the opportunity to develop or acquire those assets”;
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings,
issuances of additional partnership securities, and the establishment, increase or decrease in the amounts of reserves,
each of which can affect the amount of cash that is distributed to our unitholders;
our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is
a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does
not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;
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,
circumstances, is entitled to be indemnified by us;
in some
our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more
than 80% of the common units; and
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
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,
In those circumstances
services agreements, as well as other agreements and arrangements that cannot now be anticipated.
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where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest may 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.
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 pipeline 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:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as
our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has
no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited
partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it
owns, the exercise of its registration rights and its determination whether or not to consent to any merger or
consolidation of the partnership or amendment to the partnership agreement;
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity
as general partner, as long as it acted in good faith, meaning that it believed the decision was in the best interests of our
partnership;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts
committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no
less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and
reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general
partner may consider the totality of the relationships between the parties involved, including other transactions that
may be particularly favorable or advantageous to us;
provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages
to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad
faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that such
conduct was criminal; and
provides that in resolving conflicts of interest, it will be presumed that in making its decision the conflicts committee
or the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us,
the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
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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 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 trade could be
diminished because of the absence or reduction of a control premium in the trading price.
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 (including any units owned by our general
partner and its affiliates), voting together as a single class is required to remove our general partner. Cheniere owns 48.6% of
our outstanding common units, but it is contractually prohibited from voting our units that it holds in favor of the removal of
our general partner.
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
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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 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.
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:
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our unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available per unit to pay distributions may decrease;
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, during the three-year period ended December 31, 2020, the market price of our common units ranged between $17.75
and $49.30. Such fluctuations may continue as a result of a variety of factors, some of which are beyond our control, including:
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our quarterly distributions;
domestic and worldwide supply of and demand for natural gas and corresponding fluctuations in the price of natural
gas;
fluctuations in our quarterly or annual financial results or those of other companies in our industry;
issuance of additional equity securities which causes further dilution to our unitholders;
sales of a high volume of our common units by our unitholders;
operating and unit price performance of companies that investors deem comparable to us;
events affecting other companies that the market deems comparable to us;
changes in government regulation or proposals applicable to us;
actual or potential non-performance by any customer or a counterparty under any agreement;
announcements made by us or our competitors of significant contracts;
changes in accounting standards, policies, guidance, interpretations or principles;
general conditions in the industries in which we operate;
general economic conditions;
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the failure of securities analysts to cover our common units or changes in financial or other estimates by analysts;
changes in investor sentiment regarding the energy industry and fossil fuels; 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 or affiliates of Blackstone or Brookfield 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 or affiliates of Blackstone of a substantial number of our common 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. As of December 31, 2020, Cheniere owned
239,872,502 of our common units. We also filed a registration statement for the resale of 202,450,687 common units owned by
Blackstone and its affiliates in 2017. 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.
corporation for federal income tax purposes,
substantially reduced.
If we were treated as a
then our cash available for distribution to our unitholders would be
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 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.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash
available for distribution.
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.
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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. Members of Congress have
frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly
traded partnerships or an investment in our common units, including proposals that would eliminate our ability to qualify for
partnership tax treatment.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that
affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax
laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to
qualify as a partnership in the future.
Any changes 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 or otherwise adversely affect us. We are unable to predict whether any changes, or other proposals, will ultimately be
enacted. Any such changes or interpretations thereof could negatively impact the value of an investment in our common units.
Unitholders are urged to consult with their own tax advisor with respect to the status of regulatory or administrative
developments and proposals and their potential effect on investments 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 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 all aspects 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 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.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some
states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit
adjustment directly from us, in which case we may either pay the taxes directly to the IRS or elect to have our unitholders
and former unitholders take such audit adjustment into account and pay any resulting taxes. If we bear such payment our
cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit
adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties
and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general
partner may either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, elect
to issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner
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may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes
(including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be
no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current
unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own
common units in us during the tax year under audit.
If, as a result of any such audit adjustment, we are required to make
payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.
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.
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.
Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.
Our ability to deduct interest paid or accrued on our debt may be limited in certain circumstances. Should our ability to
deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the
limitation is in effect may increase. In certain circumstances, a unitholder may be able to utilize a portion of a business interest
deduction subject to this limitation in future taxable years. Unitholders should consult their tax advisors regarding the impact of
this business interest deduction limitation on an investment in our units.
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. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our
common units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income
effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain,
loss and deduction, and any gain from the sale or disposition of our common units will generally be considered to be
“effectively connected” with a U.S. trade or business and subject to U.S. federal income tax. As a result, distributions to a non-
U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or
otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or
disposition of that common unit.
Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, the transferee is
generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign
person. While the determination of a unitholder’s “amount realized” generally includes any decrease of a partner’s share of the
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partnership’s liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a
publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker
effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that
partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on a
transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and
after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Non-U.S.
unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
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.
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.
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.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of
common 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 there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a
unitholder whose common units are the subject of a securities loan 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 and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the
loan, 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
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income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are
urged to consult with their tax advisor to determine whether it is advisable to modify any applicable brokerage account
agreements to prohibit their brokers from borrowing and loaning 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.
LDEQ Matter
Certain of our subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of
the Sabine Pass LNG terminal and the commissioning of the Liquefaction Project, and relating to certain requirements under its
Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time
period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of our subsidiaries received a Consolidated
Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported
during that time period. Certain of our subsidiaries continue to work with LDEQ to resolve the matters identified in the
Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.
PHMSA Matter
In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG
leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal. These two tanks have been
taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA
executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019,
PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to
service. We continue to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak,
including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and
remediation will have a material adverse impact on our financial results or operations.
ITEM 4.
MINE SAFETY DISCLOSURE
Not applicable.
41
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 American under the symbol “CQP” commencing with our initial public
offering on March 21, 2007. As of February 19, 2021, we had 484.0 million common units outstanding held by 9 record
owners.
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 2019 CQP Credit Facilities described in “Management’s Discussion and Analysis of Financial Conditions and
Results of Operations” may also limit our ability to make distributions.
Upon the closing of our initial public offering, Cheniere received 135.4 million subordinated units.
In July 2020, the
board of directors of our general partner confirmed and approved that, following the distribution with respect to the three
months ended June 30, 2020, the financial tests required for conversion of our subordinated units had been met under the terms
of the partnership agreement. Accordingly, effective August 17, 2020, the first business day following the payment of the
distribution, all of our subordinated units were automatically converted into common units on a one-for-one basis and the
subordination period was terminated.
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.
General Partner Units and Incentive Distribution Rights
IDRs 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 IDRs but may transfer these rights
separately from its general partner interest.
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
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
Marginal Percentage
Interest Distributions
Common and
Subordinated
Unitholders
98%
98%
85%
75%
50%
General Partner
2%
2%
15%
25%
50%
42
ITEM 6.
SELECTED FINANCIAL DATA
Selected financial data set forth below are derived from our audited Consolidated Financial Statements for the periods
indicated (in millions, except per unit data). 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.
Consolidated Statement of Income Data:
Revenues (including transactions with affiliates)
Income from operations
Interest expense, net of capitalized interest
Net income (loss)
Common Unit Data:
Net income (loss) per common unit
Weighted average units outstanding
Consolidated Balance Sheet Data:
Property, plant and equipment, net
Total assets
Current debt, net
Long-term debt, net
2020
2019
2018
2017
2016
Year Ended December 31,
$
$
$
$
$
$
6,167
2,125
(909)
1,183
2.32
399.3
2020
16,723
19,145
—
17,580
$
$
$
$
$
6,838
2,040
(885)
1,175
2.25
348.6
6,426
1,979
(733)
1,274
2.51
348.6
2019
December 31,
2018
$
16,368
19,384
—
17,579
15,390
17,974
—
16,066
$
4,304
1,156
(614)
490
(1.32) $
178.5
1,100
250
(357)
(171)
(0.20)
57.1
2017
2016
$
15,139
17,553
—
16,046
14,158
15,542
224
14,209
43
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. 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:
• Overview of Business
• Overview of Significant Events
• Impact of COVID-19 and Market Environment
• Results of Operations
• Liquidity and Capital Resources
• Contractual Obligations
• Off-Balance Sheet Arrangements
• Summary of Critical Accounting Estimates
• Recent Accounting Standards
Overview of Business
We are a publicly traded Delaware limited partnership formed by Cheniere in 2006. We provide clean, secure and
affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct
our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our
customers.
The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four
miles from the Gulf Coast. Through our subsidiary, SPL, we are currently operating five natural gas liquefaction Trains and are
constructing one additional Train that is expected to be substantially completed in the second half of 2022, for a total
production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal, one of the
largest LNG production facilities in the world. Through our subsidiary, SPLNG, we own and operate regasification facilities at
the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of
approximately 17 Bcfe, two existing marine berths and one under construction that can each accommodate vessels with nominal
capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4 Bcf/d. We also own a
94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large
interstate pipelines.
Overview of Significant Events
Our significant events since January 1, 2020 and through the filing date of this Form 10-K include the following:
Strategic
•
In August 2020, SPL entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited
circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations
at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i)
115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price,
whichever is greater.
Operational
• As of February 19, 2021, more than 1,175 cumulative LNG cargoes totaling over 80 million tonnes of LNG have been
produced, loaded and exported from the Liquefaction Project.
44
Financial
• In February 2021, SPL entered into a note purchase agreement for the sale of approximately $147 million aggregate
principal amount of 2.95% Senior Secured Notes due 2037 (the “2.95% SPL 2037 Senior Secured Notes”) on a private
placement basis. The 2.95% SPL 2037 Senior Secured Notes are expected to be issued in December 2021, and the net
proceeds are expected to be used to refinance a portion of SPL’s outstanding Senior Secured Notes due 2022. The
2.95% SPL 2037 Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years.
• In July 2020, the board of directors of our general partner confirmed and approved that, following the distribution with
respect to the three months ended June 30, 2020, the financial tests required for conversion of our subordinated units
were met under the terms of our partnership agreement. Accordingly, effective August 17, 2020, the first business day
following the payment of the distribution, all of our subordinated units were automatically converted into common
units on a one-for-one basis and the subordination period was terminated.
• In May 2020, SPL issued an aggregate principal amount of $2.0 billion of 4.500% Senior Secured Notes due 2030 (the
“2030 SPL Senior Notes”). Net proceeds of the offering, along with available cash, were used to redeem all of SPL’s
outstanding 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”).
• In March 2020, SPL entered into a $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement
Agreement (the “2020 SPL Working Capital Facility”), which refinanced its previous working capital facility, reduced
the interest rate and extended the maturity date to March 2025.
• In February 2021, Fitch Ratings upgraded the outlook of SPL’s senior secured notes rating to positive from stable.
Impact of COVID-19 and Market Environment
The LNG business environment in 2020 was impacted by the coronavirus pandemic and its economic ramifications.
Lockdown measures across the globe reduced economic activity and resulted in lower energy needs throughout most of the
year. However, LNG demand proved relatively resilient as compared to other hydrocarbons, showing an annual gain of
approximately 1.4%, or 5 MT, to 364 MT in 2020. While the economic recovery in Asia, and particularly in China, lifted LNG
demand in the second half of the year, uncertainty about the pandemic’s track remains the primary near-term risk to LNG trade.
A slow return towards normal is expected to occur in the coming months, depending on the speed of vaccine rollout within
regions, vaccine effectiveness against mutations and the speed and shape of economic recovery across the LNG importing
nations. The continued improvements in global economic indicators seen in the fourth quarter is encouraging especially in
China, which represents one of the key countries for LNG demand growth.
In the fourth quarter of 2020, natural gas and LNG spot prices significantly increased in line with the increase in
economic activity and with seasonal norms. After falling to all-time lows in the second quarter, global LNG price benchmarks
have made an impressive climb and exited the year at the highest levels since March 2019. As an example, the Dutch Title
Transfer Facility (“TTF”), a virtual trading point for natural gas in the Netherlands, settled December at $5.08/MMBtu, $3.94/
MMBtu higher than its June 2020 settlement. Similarly, the Japan Korea Marker (“JKM”), an LNG benchmark price
assessment for spot physical cargoes delivered ex-ship into certain key markets in Asia, settled December at $6.90/MMBtu,
which is $4.84/MMBtu higher than its all-time low July 2020 settlement. Record-low winter temperatures, supply outages and
transportation bottlenecks contributed to drive JKM prices up to all-time highs by mid-January 2021. In a projection published
in July 2020, IHS Markit estimated LNG demand to reach 383 MT in 2021, implying a return to higher growth in 2021.
We have limited exposure to the fluctuations in oil and LNG spot prices as we have contracted a significant portion of
our LNG production capacity under long-term sale and purchase agreements linked to a Henry Hub price. For this reason, we
do not expect price fluctuations to have a material impact on our forecasted financial results for 2021.
The number of LNG cargoes for which customers notified us that they would not take delivery has reduced from this
summer, a sign that the market is continuing to adjust and rebalance toward equilibrium. We do not expect these events to have
a material adverse impact on our forecasted financial results for 2021, due to the highly contracted nature of our business and
the fact that customers continue to be obligated to pay fixed fees for cargoes with respect to which they have exercised their
contractual right to cancel. As such, during the year ended December 31, 2020, we recognized $553 million in LNG revenues
associated with LNG cargoes for which customers notified us that they would not take delivery. We experienced decreased
revenues during the year ended December 31, 2020 associated with LNG cargoes that were scheduled for delivery for which
customers notified us that they would not take delivery of such cargoes.
45
In addition, in response to the COVID-19 pandemic, Cheniere has modified certain business and workforce practices to
protect the safety and welfare of its employees who continue to work at its facilities and offices worldwide, as well as
implemented certain mitigation efforts to ensure business continuity. In March 2020, Cheniere began consulting with a medical
advisor, and implemented social distancing through revised shift schedules, work from home policies and designated remote
work locations where appropriate, restricted non-essential business travel and began requiring self-screening for employees and
contractors.
In April 2020, Cheniere began providing temporary housing for its workforce for our facilities, implemented
temperature testing, incorporated medical and social workers to support employees, implemented prior self-isolation and
screening for temporary housing and implemented marine operations with zero contact during loading activities. These
measures have resulted in increased costs. While response measures continue to evolve and in most cases have moderated or
ceased, we expect Cheniere to incur incremental operating costs associated with business continuity and protection of its
workforce until the risks associated with the pandemic diminish. We have incurred approximately $36 million of such costs
during the year ended December 31, 2020.
46
Results of Operations
The following charts summarize the number of Trains that were in operation during the years ended December 31, 2020,
2019 and 2018 and total revenues and total LNG volumes loaded (including both operational and commissioning volumes) for
the respective periods:
Total Revenues
LNG Volumes Loaded (1)
$6,426
$6,838
$6,167
)
s
n
o
i
l
l
i
m
n
i
(
s
e
u
n
e
v
e
r
l
a
t
o
T
$8,000
$7,000
$6,000
$5,000
$4,000
$3,000
$2,000
$1,000
$0
1,190
968
974
)
u
t
B
T
n
i
(
e
m
u
l
o
V
1,500
1,000
500
0
2018
2019
2020
Year Ended December 31,
2018
2019
2020
Year Ended December 31,
(1) The year ended December 31, 2020 excludes 17
TBtu that was loaded at our affiliate’s facility.
Our consolidated net income was $1.2 billion, or $2.32 per common unit (basic and diluted), for the year ended
December 31, 2020, compared to $1.2 billion, or $2.25 per common unit (basic and diluted), for the year ended December 31,
2019. Although net income stayed relatively consistent between the periods, there were increased margins due to lower pricing
of natural gas feedstock and additional LNG volume available to be sold from an additional Train that has reached substantial
completion between the periods, a portion of which the customers elected not to take delivery but were required to pay a fixed
fee with respect to the contracted volumes, partially offset by increases in (1) loss on modification or extinguishment of debt
incurred in conjunction with the refinancing of the 2021 SPL Senior Notes, (2) interest expense, net of capitalized interest and
(3) depreciation and amortization expense.
47
Our consolidated net income was $1.3 billion, or $2.51 per common unit (basic and diluted), in the year ended December
31, 2018. The $99 million decrease in net income for the year ended December 31, 2019 from the comparable 2018 period was
primarily a result of an increase in (1) operating and maintenance expense, (2) interest expense, net of capitalized interest and
(3) depreciation and amortization expense, partially offset by increased gross margins due to higher volumes of LNG sold but
decreased pricing on LNG.
We enter into derivative instruments to manage our exposure to commodity-related marketing and price risk. Derivative
instruments are reported at fair value on our Consolidated Financial Statements.
In some cases, the underlying transactions
economically hedged receive accrual accounting treatment, whereby revenues and expenses are recognized only upon delivery,
receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect
of recognizing gains or losses relating to future period exposure, use of derivative instruments may increase the volatility of our
results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.
Revenues
(in millions, except volumes)
LNG revenues
LNG revenues—affiliate
Regasification revenues
Other revenues
Total revenues
Year Ended December 31,
2020
2019
Change
2018
Change
$
$
5,195
662
269
41
6,167
$
$
5,211
1,312
266
49
6,838
$
$
(16) $
(650)
3
(8)
(671) $
4,827
1,299
261
39
6,426
$
$
384
13
5
10
412
225
LNG volumes recognized as revenues (in TBtu) (1)
991
1,180
(189)
955
(1)
Excludes volume associated with cargoes for which customers notified us that they would not take delivery and
includes volume that was loaded at our affiliate’s facility.
2020 vs. 2019 and 2019 vs. 2018
Total revenues decreased during the year ended December 31, 2020 from the comparable 2019 period, primarily as a
result of decreased volumes recognized as revenues between the periods due to LNG cargoes for which customers notified us
that they would not take delivery, although the decrease due to volume was partially offset by the revenues associated with such
cargoes. During the year ended December 31, 2020, we recognized $553 million in such revenues. LNG revenues—affiliate
also decreased during the year ended December 31, 2020 from the comparable periods due to less sales made to Cheniere
Marketing at lower pricing. The increase in LNG revenues during the year ended December 31, 2019 from the comparable
2018 period was primarily attributable to the increased volume of LNG sold following the achievement of substantial
completion of the Trains, partially offset by decreased revenues per MMBtu. We expect our LNG revenues to increase in the
future upon Train 6 of the Liquefaction Project becoming operational.
Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are
offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for
the construction of that Train. During the years ended December 31, 2019 and 2018, we realized offsets to LNG terminal costs
of $48 million corresponding to 10 TBtu of LNG and $94 million corresponding to 13 TBtu of LNG, respectively, that were
related to the sale of commissioning cargoes. We did not realize any offsets to LNG terminal costs during the year ended
December 31, 2020.
Also included in LNG revenues are sales of unutilized natural gas procured for the liquefaction process and gains and
losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that
settle through physical delivery. We recognized revenues of $255 million, $150 million and $151 million during the years
ended December 31, 2020, 2019 and 2018, respectively, related to these transactions.
48
Operating costs and expenses
(in millions)
Cost of sales
Cost of sales—affiliate
Operating and maintenance expense
Operating and maintenance expense—affiliate
Operating and maintenance expense—related party
Development expense
General and administrative expense
General and administrative expense—affiliate
Depreciation and amortization expense
Impairment expense and loss on disposal of assets
Total operating costs and expenses
2020 vs. 2019 and 2019 vs. 2018
Year Ended December 31,
2020
2019
Change
2018
Change
$
$
2,505
77
629
152
13
—
14
96
551
5
4,042
$
$
3,374
7
632
138
—
—
11
102
527
7
4,798
$
$
(869) $
70
(3)
14
13
—
3
(6)
24
(2)
(756) $
3,403
—
409
117
—
2
11
73
424
8
4,447
$
$
(29)
7
223
21
—
(2)
—
29
103
(1)
351
Our total operating costs and expenses decreased during the year ended December 31, 2020 from the year ended
December 31, 2019, primarily as a result of decreased cost of sales from lower volumes and pricing of natural gas feedstock.
Total operating costs and expenses increased during the year ended December 31, 2019 from the year ended December 31,
2018 primarily as a result of additional Trains that were operating between the periods. During the year ended December 31,
2019, we further incurred increased TUA reservation charges paid to SPLNG and to Total Gas & Power North America, Inc.
(“Total”) from payments under the partial TUA assignment agreement and increased third-party service and maintenance costs
from turnaround and related activities at the Liquefaction Project.
Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to
the extent those costs are not utilized for the commissioning process. Cost of sales decreased during the year ended December
31, 2020 from the comparable period in 2019 primarily due to decreases in both the volumes and pricing of natural gas
feedstock. Partially offsetting these decreases was increased losses from commodity derivatives to secure natural gas feedstock
for the Liquefaction Project, primarily due to an unfavorable shift in long-term forward prices relative to our hedged position
and increases in costs associated with a portion of derivative instruments that settle through physical delivery. Cost of sales
decreased during the year ended December 31, 2019 from the comparable period in 2018 due to increased derivative gains from
an increase in fair value of the derivatives associated with economic hedges to secure natural gas feedstock for the Liquefaction
Project, primarily due to a favorable shift in long-term forward prices. Partially offsetting this increase was a decrease in
pricing of natural gas feedstock between the years, which in turn was partially offset by increased volumes of natural gas
feedstock for our LNG sales as a result of substantial completion of Train 5 of the Liquefaction Project. Cost of sales also
includes variable transportation and storage costs and other costs to convert natural gas into LNG.
Cost of sales—affiliate increased during the year ended December 31, 2020 for the cost of cargoes procured from our
affiliate to fulfill our commitments to our long-term customers during operational interruption, such as the one we experienced
during the shutdown of the Liquefaction Project during Hurricane Laura in September 2020.
Operating and maintenance expense (including affiliate) primarily includes costs associated with operating and
maintaining the Liquefaction Project. The increase in operating and maintenance expense (including affiliates) during the year
ended December 31, 2020 from the comparable 2019 and 2018 periods was primarily related to increased natural gas
transportation and storage capacity demand charges paid to third parties from operating Train 5 of the Liquefaction Project
following its substantial completion and increased TUA reservation charges due to Total under the partial TUA assignment
agreement.
In addition, operating and maintenance expense (including affiliate) was higher in 2019 due to increase in third-
party service and maintenance costs associated with turnaround activities at the Liquefaction Project during 2019 and higher in
2020 due to costs incurred in response to the COVID-19 pandemic, as further described above in Impact of COVID-19 and
Market Environment. Operating and maintenance expense (including affiliates) also includes payroll and benefit costs of
operations personnel, insurance and regulatory costs and other operating costs.
49
Depreciation and amortization expense increased during each of the years ended December 31, 2020 and 2019 as a result
of an increase in operational Trains, as the related assets began depreciating upon reaching substantial completion.
Other expense
(in millions)
Interest expense, net of capitalized interest
Loss on modification or extinguishment of debt
Derivative gain, net
Other income, net
Other income—affiliate
Total other expense
2020 vs. 2019 and 2019 vs. 2018
Year Ended December 31,
2020
2019
Change
2018
Change
$
$
909
43
—
(8)
(2)
942
$
$
885
13
—
(31)
(2)
865
$
$
24
30
—
23
—
77
$
$
733
12
(14)
(26)
—
705
$
$
152
1
14
(5)
(2)
160
Interest expense, net of capitalized interest, increased during the year ended December 31, 2020 from the comparable
period in 2019 primarily as a result of higher interest costs as a result of the issuance of the $1.5 billion of 4.500% Senior Notes
due 2029 (the “2029 CQP Senior Notes”) in September 2019. This increase was partially offset by an increase in the portion of
total interest costs that was eligible for capitalization as the construction of Train 6 commenced in May 2019. Interest expense,
net of capitalized interest, increased during the year ended December 31, 2019 from the comparable 2018 period primarily as a
result of a decrease in the portion of total interest costs that could be capitalized as additional Trains of the Liquefaction Project
completed construction between the periods. During the years ended December 31, 2020, 2019 and 2018, we incurred $1,005
million, $972 million and $936 million of total interest cost, respectively, of which we capitalized $96 million, $87 million and
$203 million, respectively, which was primarily related to interest costs incurred to construct the remaining assets of the
Liquefaction Project.
Loss on modification or extinguishment of debt increased during the year ended December 31, 2020 from the
comparable 2019 and 2018 periods. The loss on modification or extinguishment of debt recognized in each of the years
included the incurrence fees paid to lenders, third party fees and write off of unamortized debt issuance costs recognized upon
refinancing our credit facilities with senior notes, refinancing of senior notes or upon amendment and restatement of our credit
facilities.
Derivative gain, net decreased during the years ended December 31, 2020 and 2019 compared to the year ended
December 31, 2018, as we no longer held interest rate swaps used to hedge a portion of the variable interest payments on our
credit facilities, as they were terminated in October 2018.
Other expense, net decreased during the year ended December 31, 2020 from the comparable periods in 2019 and 2018,
due to a decrease in interest income earned on our cash and cash equivalents.
Liquidity and Capital Resources
The following table provides a summary of our liquidity position at December 31, 2020 and 2019 (in millions):
Cash and cash equivalents
Restricted cash designated for the Liquefaction Project
Available commitments under the following credit facilities:
December 31,
2020
2019
$
$
1,210
97
1,781
181
$1.2 billion Amended and Restated SPL Working Capital Facility (“2015 SPL Working
Capital Facility”)
2020 SPL Working Capital Facility
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”)
—
787
750
786
—
750
50
CQP Senior Notes
The $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”), $1.1 billion of 5.625% Senior Notes
due 2026 (the “2026 CQP Senior Notes”) and the 2029 CQP Senior Notes (collectively, the “CQP Senior Notes”), are jointly
and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing its guarantee,
Sabine Pass LP (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are governed by the same
base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental
Indenture, the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture and the 2029 CQP Senior
Notes are further governed by the Third Supplemental Indenture. The indentures governing the CQP Senior Notes contain
terms and events of default and certain covenants that, among other things, limit our ability and the CQP Guarantors’ ability to
incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or
sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.
At any time prior to October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior
Notes, we may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate
principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures
governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time
prior to October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, we may redeem
up to 35% of the aggregate principal amount of the CQP Senior Notes with an amount of cash not greater than the net cash
proceeds from certain equity offerings at a redemption price equal to 105.625% of the aggregate principal amount of the 2026
CQP Senior Notes and 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus accrued and
unpaid interest, if any, to the date of redemption. We also may at any time through the maturity date of October 1, 2025 for the
2025 CQP Senior Notes, October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes and
October 1, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes, redeem the CQP Senior Notes, in
whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.
The CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future
unsubordinated debt and senior to any of our future subordinated debt. In the event that the aggregate amount of our secured
indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes
issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net
tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit
Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted
encumbrances) with liens on substantially all our existing and future tangible and intangible assets and our rights and the rights
of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set
forth in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and
ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit
Facilities obligations and any future additional senior secured debt obligations.
The CQP Guarantors’ guarantees are full and unconditional, subject to certain release provisions including (1) the sale,
disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the
CQP Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its
guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the indenture
governing the CQP Senior Notes. In the event of a default in payment of the principal or interest by us, whether at maturity of
the CQP Senior Notes or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted
against the CQP Guarantors to enforce the guarantee.
The rights of holders of the CQP Senior Notes against the CQP Guarantors may be limited under the U.S. Bankruptcy
Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s
liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a
fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a
court will apply in making a determination of the maximum liability of the CQP Guarantors. Moreover, this provision may not
be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire
guarantee may be set aside, in which case the entire liability may be extinguished.
The following tables include summarized financial information of Cheniere Partners (“Parent Issuer”), and the CQP
Investments in and equity in the
Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis.
51
earnings of SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-
Intercompany balances and
Guarantors”), which are not currently members of the Obligor Group, have been excluded.
transactions between entities in the Obligor Group have been eliminated. Although the creditors of the Obligor Group have no
claim against the Non-Guarantors, the Obligor Group may gain access to the assets of the Non-Guarantors upon bankruptcy,
liquidation or reorganization of the Non-Guarantors due to its investment in these entities. However, such claims to the assets
of the Non-Guarantors would be subordinated to the any claims by the Non-Guarantors’ creditors, including trade creditors.
See Sabine Pass LNG Terminal—SPL Senior Notes for additional detail on restrictions of Non-Guarantor debt.
Summarized Balance Sheets (in millions)
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable from Non-Guarantors
Other current assets
Current assets—affiliate
Total current assets
Property, plant and equipment, net
Other non-current assets, net
Total assets
LIABILITIES
Current liabilities
Due to affiliates
Deferred revenue from Non-Guarantors
Deferred revenue—affiliate
Other current liabilities
Total current liabilities
Long-term debt, net
Other non-current liabilities
Non-current liabilities—affiliate
Total liabilities
December 31,
2020
2019
$
$
$
$
1,210
46
42
137
1,435
2,493
117
4,045
156
22
—
100
278
4,060
85
17
4,440
$
$
$
$
1,781
43
33
145
2,002
2,533
122
4,657
158
21
1
111
291
4,055
83
20
4,449
Summarized Statement of Income (in millions)
Year Ended December 31, 2020
Revenues
Revenues from Non-Guarantors
Total revenues
Operating costs and expenses
Operating costs and expenses—affiliate
Total operating costs and expenses
Income from operations
Net income
2019 CQP Credit Facilities
$
310
518
828
181
194
375
453
238
In May 2019, we entered into the 2019 CQP Credit Facilities, which consisted of the $750 million term loan (“CQP
Term Facility”), which was prepaid and terminated upon issuance of the 2029 CQP Senior Notes in September 2019, and the
$750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be
used to fund the development and construction of Train 6 of the Liquefaction Project and for general corporate purposes,
52
subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit. As of both
December 31, 2020 and 2019, we had $750 million of available commitments and no letters of credit issued or loans
outstanding under the 2019 CQP Credit Facilities.
The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at
any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain
conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit our ability to
make restricted payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain
conditions are satisfied.
The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted
encumbrances) on substantially all of our and the CQP Guarantors’ existing and future tangible and intangible assets and rights
and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP
Credit Facilities).
Sabine Pass LNG Terminal
Liquefaction Facilities
The Liquefaction Project is one of the largest LNG production facilities in the world. We are currently operating five
Trains and two marine berths at the Liquefaction Project, and are constructing one additional Train that is expected to be
substantially completed in the second half of 2022, and a third marine berth. We have received authorization from the FERC to
site, construct and operate Trains 1 through 6, as well as for the construction of the third marine berth. We have achieved
substantial completion of the first five Trains of the Liquefaction Project and commenced commercial operating activities for
each Train at various times starting in May 2016. The following table summarizes the project completion and construction
status of Train 6 of the Liquefaction Project as of December 31, 2020:
Overall project completion percentage
Completion percentage of:
Engineering
Procurement
Subcontract work
Construction
Date of expected substantial completion
Train 6
77.6%
99.0%
99.9%
54.9%
49.2%
2H 2022
The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from
the Sabine Pass LNG terminal:
• Trains 1 through 4—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a
combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).
• Trains 1 through 4—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a
combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).
• Trains 5 and 6—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a combined
total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
In December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations
separately from long-term authorizations. Accordingly, the DOE amended each of SPL’s long-term authorizations to include
short-term export authority, and vacated the short-term orders.
An application was filed in September 2019 seeking authorization to make additional exports from the Liquefaction
Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of
approximately 153 Bcf/yr of natural gas, for a total Liquefaction Project export capacity of approximately 1,662 Bcf/yr. The
terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of
the volumes contemplated in the application.
In April 2020, the DOE issued an order authorizing SPL to export to FTA
countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet
53
issued an order authorizing SPL to export to non-FTA countries for the corresponding LNG volume. A corresponding
application for authorization to increase the total LNG production capacity of the Liquefaction Project from the currently
authorized level to approximately 1,662 Bcf/yr was also submitted to the FERC and is currently pending.
Customers
SPL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a
weighted average remaining contract length of approximately 17 years (plus extension rights) with eight third parties for Trains
1 through 6 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 75% of the total
production capacity from these Trains, potentially increasing up to approximately 85% after giving effect to an SPA that
Cheniere has committed to provide to us. Under these SPAs, the customers will purchase LNG from SPL for a price consisting
of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per
MMBtu of LNG generally equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend
deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be
required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or
suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries
under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable
only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees
under SPL’s SPAs were generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases
and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted
volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally
commences upon the date of first commercial delivery of a specified Train.
In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion for
Trains 1 through 5. After giving effect to an SPA that Cheniere has committed to provide to SPL, the annual fixed fee portion
to be paid by the third-party SPA customers would increase to at least $3.3 billion, which is expected to occur upon the date of
first commercial delivery of Train 6.
In addition, Cheniere Marketing has agreements with SPL to purchase: (1) at Cheniere Marketing’s option, any LNG
produced by SPL in excess of that required for other customers and (2) up to 30 cargoes scheduled for delivery in 2021 at a
price of 115% of Henry Hub plus $0.728 per MMBtu.
Natural Gas Transportation, Storage 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 and other agreements to secure firm pipeline transportation capacity with CTPL and third-party
pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in
natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply
contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2020, SPL
had secured up to approximately 4,950 TBtu of natural gas feedstock through long-term and short-term natural gas supply
contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.
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 6 of the Liquefaction Project, under which Bechtel charges a lump sum for
all work performed and generally bears project cost, schedule and performance risks 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 price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion,
including estimated costs for the third marine berth that is currently under construction. As of December 31, 2020, we have
incurred $1.9 billion under this contract.
54
Regasification Facilities
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG
storage capacity of approximately 17 Bcfe. Approximately 2 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 and Chevron U.S.A. Inc. (“Chevron”) has reserved
approximately 1 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating
approximately $125 million annually, prior to inflation adjustments, 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 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, prior to inflation adjustments,
continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial
completion of Train 5 of the Liquefaction Project, SPL gained access to substantially all of Total’s capacity and other services
provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the
Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading
activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6.
Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to
be made by Total to SPLNG in accordance with its TUA. During the years ended December 31, 2020, 2019 and 2018, SPL
recorded $129 million, $104 million and $30 million, respectively, as operating and maintenance expense under this partial
TUA assignment agreement.
Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.
Capital Resources
We currently expect that SPL’s capital resources requirements with respect to the Liquefaction Project will be financed
through project debt and borrowings, cash flows under the SPAs and equity contributions from us. We believe that with the net
proceeds of borrowings, available commitments under the 2020 SPL Working Capital Facility, 2019 CQP Credit Facilities,
cash flows from operations and equity contributions from us, SPL will have adequate financial resources available to meet its
currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the Liquefaction
Project. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.
The following table provides a summary of our capital resources from borrowings and available commitments for the
Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in
Sources and Uses of Cash), at December 31, 2020 and 2019 (in millions):
Senior notes (1)
Credit facilities outstanding balance (2)
Letters of credit issued (3)
Available commitments under credit facilities (3)
Total capital resources from borrowings and available commitments (4)
December 31,
2020
2019
17,750
—
413
1,537
19,700
$
$
17,750
—
414
1,536
19,700
$
$
(1)
(2)
Includes SPL’s 2021 SPL Senior Notes, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due
2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes
due 2026 (the “2026 SPL Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”),
4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”), 2030 SPL Senior Notes and 5.00% Senior
Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”) and our CQP Senior
Notes.
Includes outstanding balances under the 2015 SPL Working Capital Facility, 2020 SPL Working Capital Facility and
2019 CQP Credit Facilities, inclusive of any portion of the 2020 SPL Working Capital Facility and 2019 CQP Credit
Facilities that may be used for general corporate purposes.
55
(3)
(4)
Consists of 2015 SPL Working Capital Facility, 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities.
Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash
equivalents.
SPL Senior Notes
The SPL Senior Notes are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior
Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037
SPL Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit SPL’s
ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain
investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital
stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by
restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all
or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes
are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially
all of SPL’s assets. SPL may not make any distributions until, among other requirements, deposits are made into debt service
reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.
At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except
for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2030 SPL Senior Notes and 2037 SPL Senior
Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such
series of the SPL Senior Notes at a redemption price equal to the ‘make-whole’ price (except for the 2037 SPL Senior Notes, in
which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the
SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three
months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027
SPL Senior Notes, 2028 SPL Senior Notes, 2030 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period
is within six months of the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a
redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued
and unpaid interest, if any, to the date of redemption.
Both the 2037 SPL Senior Notes Indenture and the SPL Indenture include 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 and the 2020 SPL Working Capital Facility. Semi-annual principal payments for the 2037 SPL
Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025 and are fully amortizing
according to a fixed sculpted amortization schedule.
2015 SPL Working Capital Facility
In March 2020, SPL terminated the remaining commitments under the 2015 SPL Working Capital Facility. As of
December 31, 2019, SPL had $786 million of available commitments, $414 million aggregate amount of issued letters of credit
and no outstanding borrowings under the 2015 SPL Working Capital Facility.
2020 SPL Working Capital Facility
In March 2020, SPL entered into the 2020 SPL Working Capital Facility with aggregate commitments of $1.2 billion,
which replaced the 2015 SPL Working Capital Facility. The 2020 SPL Working Capital Facility is intended to be used for
loans to SPL, swing line loans to SPL and the issuance of letters of credit on behalf of SPL, primarily for (1) the refinancing of
the 2015 SPL Working Capital Facility, (2) fees and expenses related to the 2020 SPL Working Capital Facility, (3) SPL and its
future subsidiaries’ gas purchase obligations and (4) SPL and certain of its future subsidiaries’ general corporate purposes. SPL
may, from time to time, request increases in the commitments under the 2020 SPL Working Capital Facility of up to $800
million. As of December 31, 2020, SPL had $787 million of available commitments, $413 million aggregate amount of issued
letters of credit and no outstanding borrowings under the 2020 SPL Working Capital Facility.
56
The 2020 SPL Working Capital Facility matures on March 19, 2025, but may be extended with consent of the lenders.
The 2020 SPL Working Capital Facility provides for mandatory prepayments under customary circumstances.
The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as
customary affirmative and negative covenants. SPL is restricted from making certain distributions under agreements governing
its indebtedness generally until, among other requirements, satisfaction of a 12-month forward-looking and backward-looking
1.25:1.00 debt service reserve ratio test. The obligations of SPL under the 2020 SPL Working Capital Facility are secured by
substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries
of SPL on a pari passu basis by a first priority lien with the SPL Senior Notes.
Restrictive Debt Covenants
As of December 31, 2020, we and SPL were in compliance with all covenants related to our respective debt agreements.
LIBOR
The use of LIBOR is expected to be phased out by the end of 2021.
It is currently unclear whether LIBOR will be
utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue working with our lenders to
pursue any amendments to our debt agreements that are currently subject to LIBOR and will continue to monitor, assess and
plan for the phase out of LIBOR.
Sources and Uses of Cash
The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the years
ended December 31, 2020, 2019 and 2018 (in millions). 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.
2020
Year Ended December 31,
2019
2018
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities
Proceeds from issuances of debt
Other
Uses of cash, cash equivalents and restricted cash:
Property, plant and equipment, net
Repayments of debt
Debt issuance and other financing costs
Debt extinguishment costs
Distributions to owners
Other
$
$
$
1,751
1,995
4
3,750
$
$
(972) $
(2,000)
(35)
(39)
(1,359)
—
(4,405)
Net increase (decrease) in cash, cash equivalents and restricted cash
$
(655) $
Operating Cash Flows
1,547
2,230
5
3,782
$
$
(1,331) $
(730)
(35)
(4)
(1,260)
(1)
(3,361)
421
$
1,874
1,100
—
2,974
(804)
(1,090)
(8)
(7)
(1,113)
—
(3,022)
(48)
Our operating cash net inflows during the years ended December 31, 2020, 2019 and 2018 were $1,751 million, $1,547
million and $1,874 million, respectively. The $204 million increase in operating cash inflows in 2020 compared to 2019 was
primarily related to decreased operating costs and expenses. The $327 million decrease in operating cash inflows in 2019
compared to 2018 was primarily related to increased operating costs and expenses, which were partially offset by increased
cash receipts from the sale of LNG cargoes, as a result of an additional Train that was operating at the Liquefaction Project in
2019.
57
Proceeds from Issuance of Debt, Repayments of Debt, Debt Issuance and Other Financing Costs and Debt Extinguishment
Costs
During the year ended December 31, 2020, we issued an aggregate principal amount of $2.0 billion of the 2030 SPL
Senior Notes, which was used to redeem all of the outstanding 2021 SPL Senior Notes. We incurred $35 million of debt
issuance costs primarily related to up-front fees paid and $39 million of debt extinguishment costs upon the closing of this
transaction.
During the year ended December 31, 2019, we issued an aggregate principal amount of $1.5 billion in senior notes to
prepay the outstanding indebtedness under our credit facilities. Borrowings of $730 million under our credit facilities were
used for funding future capital expenditures in connection with the construction costs for the Liquefaction Project. We incurred
$35 million of debt issuance costs primarily related to up-front fees paid and $4 million of debt extinguishment costs upon the
closing of these transactions.
During the year ended December 31, 2018, we issued an aggregate principal amount of $1.1 billion in senior notes to
prepay the outstanding indebtedness under our credit facilities. We incurred $8 million of debt issuance costs primarily related
to up-front fees paid and $7 million of debt extinguishment costs upon the closing of this transaction.
Property, Plant and Equipment, net
Cash outflows for property, plant and equipment were primarily for the construction costs for the Liquefaction Project.
These costs are capitalized as construction-in-process until achievement of substantial completion.
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, 2020, 2019 and
2018:
Date Paid
November 13, 2020
August 14, 2020
May 15, 2020
February 14, 2020
Period Covered by Distribution
July 1 - September 30, 2010
April 1 - June 30, 2020
January 1 - March 31, 2020
October 1- December 31, 2019
November 14, 2019
August 14, 2019
May 15, 2019
July 1 - September 30, 2019
April 1 - June 30, 2019
January 1 - March 31, 2019
February 14, 2019 October 1 - December 31, 2018
November 14, 2018
August 14, 2018
May 15, 2018
July 1 - September 30, 2018
April 1 - June 30, 2018
January 1 - March 31, 2018
February 14, 2018 October 1 - December 31, 2017
Distribution
Per
Common
Unit
Distribution
Per
Subordinated
Unit
Common
Units
Subordinated
Units
General
Partner
Units
Incentive
Distribution
Rights
Total Distribution (in millions)
$
$
$
$
$
$
0.65
0.645
0.64
0.63
0.62
0.61
0.60
0.59
0.58
0.56
0.55
0.50
$
$
$
— $
0.645
0.64
0.63
$
$
0.62
0.61
0.60
0.59
0.58
0.56
0.55
0.50
315
225
223
220
216
213
209
206
202
195
192
174
— $
88
86
85
$
$
84
83
81
80
79
76
74
68
$
$
$
7
7
7
6
6
6
6
6
5
6
5
5
25
22
20
18
16
15
13
12
11
7
6
1
On January 27, 2021, we declared a $0.655 distribution per common unit and the related distribution to our general
partner and incentive distribution right holders that was paid on February 12, 2021 to unitholders of record as of February 8,
2021 for the period from October 1, 2020 to December 31, 2020.
In July 2020, the board of directors of our general partner confirmed and approved that, following the distribution with
respect to the three months ended June 30, 2020, the financial tests required for conversion of our subordinated units were met
under the terms of our partnership agreement. Accordingly, effective August 17, 2020, the first business day following the
58
payment of the distribution, all of our subordinated units were automatically converted into common units on a one-for-one
basis and the subordination period was terminated.
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 place as of December 31, 2020 (in millions):
Debt (2)
Interest payments (2)
Operating lease obligations (3)
Purchase obligations: (4)
Construction obligations (5)
Natural gas supply, transportation and
storage service agreements (6)
Other purchase obligations (7)
Other non-current liabilities—affiliate (8)
Total
Total
2021
2022-2023
2024-2025
Thereafter
Payments Due By Period (1)
$
$
17,750
5,304
171
625
9,889
2,221
19
35,979
,
$
— $
932
11
362
2,949
199
2
4,455
$
$
2,500
1,729
22
263
3,079
398
5
7,996
,
$
$
5,523
1,342
22
—
1,651
392
5
8,935
,
$
$
9,727
1,301
116
—
2,210
1,232
7
14,593
,
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Agreements in force as of December 31, 2020 that have terms dependent on project milestone dates are based on the
estimated dates as of December 31, 2020.
Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2020. A discussion
of our debt obligations can be found in Note 11—Debt of our Notes to Consolidated Financial Statements.
Operating lease obligations primarily consist of land sites related to the Sabine Pass LNG terminal as further discussed
in Note 12—Leases of our Notes to Consolidated Financial Statements.
Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that
specify fixed or minimum quantities to be purchased. We include only contracts for which conditions precedent have
been met. As project milestones and other conditions precedent are achieved, our obligations are expected to increase
accordingly. We include contracts for which we have an early termination option if the option is not expected to be
exercised.
Construction obligations primarily consist of the estimated remaining cost pursuant to our EPC contracts as of
December 31, 2020 for projects with respect to which we have made an FID to commence construction. A discussion
of these obligations can be found at Note 16—Commitments and Contingencies of our Notes to Consolidated
Financial Statements.
Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31,
2020. Natural gas transportation and storage service agreements includes $366 million in payments under agreements
with a related party as discussed in Note 14—Related Party Transactions of our Notes to Consolidated Financial
Statements.
Other purchase obligations primarily relate to payments under SPL’s partial TUA assignment agreement with Total as
discussed in Note 13—Revenues from Contracts with Customers of our Notes to Consolidated Financial Statements.
Other non-current liabilities—affiliate primarily relate to obligations to Cheniere Marketing related to the Cooperative
Endeavor Agreement, as discussed in Note 14—Related Party Transactions of our Notes to Consolidated Financial
Statements.
In addition, as of December 31, 2020, we had $413 million aggregate amount of issued letters of credit under our credit
facilities.
Off-Balance Sheet Arrangements
As of December 31, 2020, 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.
59
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 valuation of
derivative instruments. 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 of 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
approaches. Such evaluations may involve significant judgment and the results are based on expected future events or
conditions, particularly for those valuations using inputs unobservable in the market.
Our derivative instruments consist of financial commodity derivative contracts transacted in an over-the-counter market
and physical commodity contracts. Valuation of our financial commodity derivative contracts is determined using observable
commodity price curves and other relevant data.
Valuation of our physical commodity contracts is predominantly driven by observable and unobservable market
commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair
value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of
our physical commodity contracts incorporates risk premiums related to the satisfaction of conditions precedent, such as
completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. A
portion of our physical commodity contracts require us to make critical accounting estimates that involve significant judgment,
as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances
where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing
the asset or liability. This includes assumptions about market risks, such as future Henry Hub basis spread for unobservable
periods, liquidity, volatility and contract duration.
Gains and losses on derivative instruments are recognized 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 interest rates and commodity prices change.
Recent Accounting Standards
For descriptions of recently issued accounting standards, see Note 3—Summary of Significant Accounting Policies of
our Notes to Consolidated Financial Statements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and
operation of 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
commodity price for natural gas for each delivery location as follows (in millions):
Liquefaction Supply Derivatives
December 31, 2020
December 31, 2019
Fair Value
Change in Fair Value
4
(21) $
$
$
Fair Value
Change in Fair Value
1
$
24
See Note 8—Derivative Instruments for additional details about our derivative instruments.
60
ITEM 8.
CONSOLIDATED 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
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Partners’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Note 1—Organization and Nature of Operations
Note 2—Unitholders’ Equity
Note 3—Summary of Significant Accounting Policies
Note 4—Restricted Cash
Note 5—Accounts and Other Receivables
Note 6—Inventory
Note 7—Property, Plant and Equipment
Note 8—Derivative Instruments
Note 9—Other Non-current Assets
Note 10—Accrued Liabilities
Note 11—Debt
Note 12—Leases
Note 13—Revenues from Contracts with Customers
Note 14—Related Party Transactions
Note 15—Net Income per Common Unit
Note 16—Commitments and Contingencies
Note 17—Customer Concentration
Note 18—Supplemental Cash Flow Information
Note 19—Subsequent Events
Supplemental Information to Consolidated Financial Statements—Quarterly Financial Data
62
63
67
68
69
70
71
71
71
71
77
77
77
77
78
81
82
82
84
86
89
93
94
96
97
97
98
61
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, 2020, 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, 2020, 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/ Jack A. Fusco
Jack A. Fusco
President and Chief Executive Officer
(Principal Executive Officer)
By:
/s/ Zach Davis
Zach Davis
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
62
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Unitholders of Cheniere Energy Partners, L.P. and
Board of Directors of Cheniere Energy Partners GP, LLC
Cheniere Energy Partners, L.P.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Cheniere Energy Partners, L.P. and subsidiaries (the
Partnership) as of December 31, 2020 and 2019, the related consolidated statements of income, partners’ equity, and cash flows
for each of the years in the three-year period ended December 31, 2020, and the related notes and financial statement schedule I
(collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all
material respects, the financial position of the Partnership as of December 31, 2020 and 2019, and the results of its operations
and its cash flows for each of the years in the three-year period ended December 31, 2020, in conformity with U.S. generally
accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2020, based on criteria established in
Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 23, 2021 expressed an unqualified opinion on the effectiveness of the Partnership’s
internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 3 to the consolidated financial statements, the Partnership has changed its method of accounting for leases
as of January 1, 2019 due to the adoption of ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto.
Basis for Opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws
and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial
statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or
disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or
complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate
opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Fair value of the level 3 physical liquefaction supply derivatives
As discussed in Notes 3 and 8 to the consolidated financial statements, the Partnership recorded fair value of level 3
physical liquefaction supply derivatives of $(21) million, as of December 31, 2020. The physical liquefaction supply
derivatives consist of natural gas supply contracts for the operation of the liquefied natural gas facility. The fair value of the
level 3 physical liquefaction supply derivatives is developed through the use of internal models, which incorporate
significant unobservable inputs.
63
We identified the evaluation of the fair value of the level 3 physical liquefaction supply derivatives as a critical audit
matter. Specifically, there is subjectivity in certain assumptions used to estimate the fair value, including assumptions for
future prices of energy units for unobservable periods and liquidity.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and
tested the operating effectiveness of certain internal controls over the valuation of the level 3 physical liquefaction supply
derivatives. This included controls related to the assumptions for significant unobservable inputs. For the level 3
liquefaction supply derivatives selected, we involved valuation professionals with specialized skills who assisted in:
•
•
developing independent fair value estimates and comparing the independently developed estimates to the Partnership’s
fair value estimates
testing the future prices of energy units for unobservable periods and liquidity assumptions by comparing to market
data, including quoted or published forward prices for similar commodities.
In addition, we evaluated the Partnership’s assumptions for future prices of energy units for unobservable periods and
liquidity by comparing to market or third-party data, including adjustments for third party quoted transportation prices.
/s/ KPMG LLP
KPMG LLP
We have served as the Partnership’s auditor since 2014.
Houston, Texas
February 23, 2021
64
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Unitholders of Cheniere Energy Partners, L.P. and
Board of Directors of Cheniere Energy Partners GP, LLC
Cheniere Energy Partners, L.P.:
Opinion on Internal Control Over Financial Reporting
We have audited Cheniere Energy Partners, L.P. and subsidiaries’ (the Partnership) internal control over financial
reporting as of December 31, 2020, based on criteria established in Internal Control—Integrated Framework (2013) issued by
the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in
Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2020 and 2019, the related
consolidated statements of income, partners’ equity, and cash flows for each of the years in the three-year period ended
the consolidated financial
December 31, 2020, and the related notes and financial statement schedule I (collectively,
statements), and our report dated February 23, 2021 expressed an unqualified opinion on those consolidated financial
statements.
Basis for Opinion
The Partnership’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 are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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 of internal control over financial reporting 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.
Definition and Limitations of Internal Control Over Financial Reporting
A partnership’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 partnership’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 partnership; (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 partnership are being made only in accordance with authorizations of management and directors of the
partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the partnership’s assets that could have a material effect on the financial statements.
65
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.
/s/ KPMG LLP
KPMG LLP
Houston, Texas
February 23, 2021
66
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per unit data)
Revenues
LNG revenues
LNG revenues—affiliate
Regasification revenues
Other revenues
Total revenues
Operating costs and expenses
Cost of sales (excluding items shown separately below)
Cost of sales—affiliate
Operating and maintenance expense
Operating and maintenance expense—affiliate
Operating and maintenance expense—related party
Development expense
General and administrative expense
General and administrative expense—affiliate
Depreciation and amortization expense
Impairment expense and loss on disposal of assets
Total operating costs and expenses
Income from operations
Other income (expense)
Interest expense, net of capitalized interest
Loss on modification or extinguishment of debt
Derivative gain, net
Other income, net
Other income—affiliate
Total other expense
Net income
Basic and diluted net income per common unit
$
Year Ended December 31,
2019
2018
2020
$
5,195
662
269
41
6,167
2,505
77
629
152
13
—
14
96
551
5
4,042
2,125
(909)
(43)
—
8
2
(942)
$
5,211
1,312
266
49
6,838
3,374
7
632
138
—
—
11
102
527
7
4,798
2,040
(885)
(13)
—
31
2
(865)
4,827
1,299
261
39
6,426
3,403
—
409
117
—
2
11
73
424
8
4,447
1,979
(733)
(12)
14
26
—
(705)
$
$
1,183
2.32
$
$
1,175
2.25
$
$
1,274
2.51
Weighted average number of common units outstanding used for basic and diluted
net income per common unit calculation
399.3
348.6
348.6
The accompanying notes are an integral part of these consolidated financial statements.
67
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash
Accounts and other receivables, net
Accounts receivable—affiliate
Advances to affiliate
Inventory
Derivative assets
Other current assets
Other current assets—affiliate
Total current assets
Property, plant and equipment, net
Operating lease assets, net
Debt issuance costs, net
Non-current derivative assets
Other non-current assets, net
Total assets
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable
Accrued liabilities
Accrued liabilities—related party
Due to affiliates
Deferred revenue
Deferred revenue—affiliate
Current operating lease liabilities
Derivative liabilities
Total current liabilities
Long-term debt, net
Non-current operating lease liabilities
Non-current derivative liabilities
Other non-current liabilities
Other non-current liabilities—affiliate
Commitments and contingencies (see Note 16)
Partners’ equity
Common unitholders’ interest (484.0 million and 348.6 million units issued and
outstanding at December 31, 2020 and 2019, respectively)
Subordinated unitholders’ interest (zero and 135.4 million units issued and
outstanding at December 31, 2020 and 2019, respectively)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at
December 31, 2020 and 2019)
Total partners’ equity
Total liabilities and partners’ equity
December 31,
2020
2019
$
$
$
$
$
$
1,210
97
318
184
144
107
14
61
—
2,135
16,723
99
17
11
160
19,145
12
658
4
53
137
1
7
11
883
17,580
90
35
1
17
714
—
(175)
539
19,145
$
$
1,781
181
297
105
158
116
17
51
1
2,707
16,368
94
15
32
168
19,384
40
709
—
46
155
1
6
9
966
17,579
87
16
1
20
1,792
(996)
(81)
715
19,384
The accompanying notes are an integral part of these consolidated financial statements.
68
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
(in millions)
Balance at December 31, 2017
Net income
Distributions
Common units, $2.19/unit
Subordinated units, $2.19/unit
General partner units
Balance at December 31, 2018
Net income
Distributions
Common units, $2.42/unit
Subordinated units, $2.42/unit
General partner units
Balance at December 31, 2019
Net income
Conversion of subordinated units into
common units
Distributions
Common units, $2.565/unit
Subordinated units, $1.915/unit
General partner units
Balance at December 31, 2020
Common Unitholders’
Interest
Subordinated Unitholder’s
Interest
Units
Amount
Units
348.6 $
—
1,670
899
—
—
—
348.6
—
—
—
—
348.6
—
(763)
—
—
1,806
829
(843)
—
—
1,792
930
135.4
—
—
—
—
135.4
—
—
—
—
135.4
—
Amount
$ (1,043)
349
—
(296)
—
(990)
322
—
(328)
—
(996)
229
135.4
(1,026)
(135.4)
1,026
—
—
—
484.0 $
(982)
—
—
714
—
—
—
— $
—
(259)
—
—
General Partner’s Interest
Units
Amount
Total
Partners’
Equity
9.9
—
—
—
—
9.9
—
—
—
—
9.9
—
—
—
—
—
9.9
$
$
12
26
639
1,274
—
—
(54)
(16)
24
—
—
(89)
(81)
24
—
—
—
(118)
(175) $
$
(763)
(296)
(54)
800
1,175
(843)
(328)
(89)
715
1,183
—
(982)
(259)
(118)
539
The accompanying notes are an integral part of these consolidated financial statements.
69
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
1,183
$
1,175
$
1,274
Year Ended December 31,
2019
2018
2020
Depreciation and amortization expense
Amortization of debt issuance costs, premium and discount
Loss on modification or extinguishment of debt
Total losses (gains) on derivatives, net
Net cash provided by (used for) settlement of derivative instruments
Impairment expense and loss on disposal of assets
Other
Other—affiliate
Changes in operating assets and liabilities:
Accounts and other receivables, net
Accounts receivable—affiliate
Advances to affiliate
Inventory
Accounts payable and accrued liabilities
Accrued liabilities—related party
Due to affiliates
Deferred revenue
Other, net
Other, net—affiliate
Net cash provided by operating activities
Cash flows from investing activities
Property, plant and equipment, net
Other
Net cash used in investing activities
Cash flows from financing activities
Proceeds from issuances of debt
Repayments of debt
Debt issuance and other financing costs
Debt extinguishment costs
Distributions to owners
Other
Net cash provided by (used in) financing activities
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash—beginning of period
Cash, cash equivalents and restricted cash—end of period
Balances per Consolidated Balance Sheets:
Cash and cash equivalents
Restricted cash
Total cash, cash equivalents and restricted cash
$
$
$
551
32
43
49
(4)
5
14
(2)
(21)
(80)
8
8
—
4
9
(18)
(28)
(2)
1,751
(972)
—
(972)
1,995
(2,000)
(35)
(39)
(1,359)
4
(1,434)
527
34
13
(72)
5
7
11
(2)
16
9
(41)
(16)
(126)
—
6
39
(36)
(2)
1,547
(1,331)
(1)
(1,332)
2,230
(730)
(35)
(4)
(1,260)
5
206
(655)
1,962
1,307
$
421
1,541
1,962
$
424
30
12
87
32
8
5
—
(122)
47
(84)
(5)
183
—
(6)
3
(12)
(2)
1,874
(804)
—
(804)
1,100
(1,090)
(8)
(7)
(1,113)
—
(1,118)
(48)
1,589
1,541
December 31,
2020
2019
1,210
97
1,307
$
$
1,781
181
1,962
The accompanying notes are an integral part of these consolidated financial statements.
70
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 formed by Cheniere in 2006. The Sabine Pass LNG terminal is
located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Through our
subsidiary, SPL, we are currently operating five natural gas liquefaction Trains and are constructing one additional Train that is
expected to be substantially completed in the second half of 2022, for a total production capacity of approximately 30 mtpa of
LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal. Through our subsidiary, SPLNG, we own and operate
regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks,
two marine berths and vaporizers and an additional marine berth that is under construction. We also own a 94-mile pipeline
through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the
“Creole Trail Pipeline”).
As of December 31, 2020, Cheniere owned 48.6% of our limited partner interest in the form of 239.9 million of our
common units. Cheniere also owns 100% of our general partner interest and our incentive distribution rights (“IDRs”).
NOTE 2—UNITHOLDERS’ EQUITY
The common units represent limited partner interests in us. The holders of the units are entitled to participate in
partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement.
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as
defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a quarter less the amount
of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating
surplus as defined in the partnership agreement.
In July 2020, the board of directors of our general partner confirmed and approved that, following the distribution with
respect to the three months ended June 30, 2020, the financial tests required for conversion of our subordinated units had been
met under the terms of the partnership agreement. Accordingly, effective August 17, 2020, the first business day following the
payment of the distribution, all of our subordinated units were automatically converted into common units on a one-for-one
basis and the subordination period was terminated.
Although common unitholders are not obligated to fund losses of the Partnership, its capital account, which would be
considered in allocating the net assets of the Partnership were it to be liquidated, continues 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 IDRs, which allow the general partner to receive a higher percentage of quarterly distributions of available cash from
operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met, but may
transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of
the general partner interest.
As of December 31, 2020, our total securities beneficially owned in the form of common units were held 48.6% by
Cheniere, 41.9% by BX CQP Target Holdco L.L.C. (“BX CQP Target Holdco”) and other affiliates of The Blackstone Group
Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 7.5% by the public. All of our 2% general
partner interest was held by Cheniere. BX CQP Target Holdco’s equity interests are 50.01% owned by BIP Chinook Holdco
L.L.C., an affiliate of Blackstone and 49.99% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of
Brookfield. The ownership of BX CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with
the SEC.
NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial
Statements include the accounts of Cheniere Partners and its majority owned subsidiaries. All intercompany accounts and
transactions have been eliminated in consolidation.
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Recent Accounting Standards
In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)
2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.
This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to
existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional
expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have
not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified
contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until
December 31, 2022, at which time the optional expedients are no longer available.
Use of Estimates
The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain
estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying
notes. Management evaluates its estimates and related assumptions regularly,
including those related to fair value
leases and asset retirement
measurements, revenue recognition, property, plant and equipment, derivative instruments,
obligations (“AROs”), as further discussed under the respective sections within this note. Changes in facts and circumstances
or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to
measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy
Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included
within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market
data.
In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market
participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use
of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 8—Derivative
Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable
reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would
have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between
the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 11—Debt, are
based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using
observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets
and AROs.
Revenue Recognition
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that
reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale
of LNG are recognized as LNG revenues. LNG regasification capacity payments are recognized as regasification revenues.
See Note 13—Revenues from Contracts with Customers for further discussion of revenues.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Restricted Cash
Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been
presented separately from cash and cash equivalents on our Consolidated Balance Sheets.
Accounts Receivable
Accounts receivable is reported net of any current expected credit losses. Current expected credit losses consider the risk
of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is
assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our
assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial
assurances. Adjustments to current expected credit
losses are recorded in general and administrative expense in our
Consolidated Statements of Income. As of December 31, 2020 and 2019, we had current expected credit losses on our accounts
receivable of $5 million and zero, respectively.
Inventory
LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials
and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued.
Accounting for LNG Activities
Generally, we begin capitalizing the costs of our LNG terminal once the individual project meets the following criteria:
(1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to
commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred.
These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of
securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG
terminal.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include:
land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. The
costs of lease options are amortized over the life of the lease once obtained.
If no land or lease is obtained, the costs are
expensed.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major
renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs
(including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are
generally expensed as incurred. We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned
or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We
depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition
of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting
gains or losses are recorded in impairment expense and loss (gain) on disposal of assets.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have
indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest
level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for
purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the
expected undiscounted future cash flows of the asset.
If the carrying value of the asset is not recoverable, the amount of
impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.
We did not record any impairments related to property, plant and equipment during the years ended December 31, 2020,
2019 and 2018.
73
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Interest Capitalization
We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-
process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and
interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.
Regulated Natural Gas Pipelines
The Creole Trail Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and
the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets
those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts
that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in
which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result
from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually
assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes
and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing
regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated
Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP and consider
factors such as regulatory changes and the effect of competition.
If cost-based regulation ends or competition increases, we
may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and
liabilities.
Items that may influence our assessment are:
inability to recover cost increases due to rate caps and rate case moratoriums;
inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and
the FERC proceedings;
excess capacity;
increased competition and discounting in the markets we serve; and
impacts of ongoing regulatory initiatives in the natural gas industry.
•
•
•
•
•
Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction
(“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the
FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during
construction. AFUDC is capitalized as a part of the cost of our natural gas pipeline. Under regulatory rate practices, we
generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after the natural gas pipelines are
placed in service.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk.
Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities
depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the
normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and
liabilities are reported on a net basis.
Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge
accounting and meet specified criteria. We did not have any derivative instruments designated as cash flow or fair value hedges
during the years ended December 31, 2020, 2019 and 2018. See Note 8—Derivative Instruments for additional details about
our derivative instruments.
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Leases
We adopted ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019
using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective
adjustments to prior periods. The adoption of the standard resulted in the recognition of right-of-use assets and lease liabilities
for operating leases of approximately $100 million on our Consolidated Balance Sheets, with no material impact on our
Consolidated Statements of Income or Consolidated Statements of Cash Flows.
We determine if an arrangement is, or contains, a lease at inception of the arrangement. When we determine the
arrangement is, or contains, a lease, we classify the lease as either an operating lease or a finance lease. We did not have any
financing leases as of December 31, 2020. Operating leases are recognized on our Consolidated Balance Sheets by recording a
lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the
underlying asset for the lease term. Operating lease right-of-use assets and liabilities are generally recognized based on the
present value of lease payments over the lease term. In determining the present value of lease payments, we use the implicit
interest rate in the lease if readily determinable. In the absence of a readily determinable implicitly interest rate, we discount
our expected future lease payments using our relevant subsidiary’s incremental borrowing rate. The incremental borrowing rate
is an estimate of the interest rate that a given subsidiary would have to pay to borrow on a collateralized basis over a similar
term to that of the lease term. Options to renew a lease are included in the lease term and recognized as part of the right-of-use
asset and lease liability, only to the extent they are reasonably certain to be exercised. We have elected practical expedients to
(1) omit leases with an initial term of 12 months or less from recognition on our balance sheet and (2) to combine both the lease
and non-lease components of an arrangement in calculating the right-of-use asset and lease liability for all classes of leased
assets.
Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Operating leases
are included in operating lease assets, net, current operating lease liabilities and non-current operating lease liabilities on our
Consolidated Balance Sheets. See Note 12—Leases for additional details about our leases.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash
equivalents, restricted cash, derivative instruments and accounts receivable. We maintain cash balances at financial institutions,
which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to
meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts
which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial
institutions. Collateral deposited for such contracts is recorded within other current assets. Our interest rate derivative
instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor
counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’
creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in
counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our
derivative instruments.
SPL has entered into fixed price long-term SPAs generally with terms of 20 years with eight third parties and has entered
into agreements with Cheniere Marketing.
SPL is dependent on the respective customers’ creditworthiness and their
willingness to perform under their respective SPAs. See Note 17—Customer Concentration for additional details about our
customer concentration.
SPLNG has entered into two long-term TUAs with third parties for regasification capacity at the Sabine Pass LNG
terminal. SPLNG is dependent on the respective customers’ creditworthiness and their willingness to perform under their
respective TUAs. SPLNG has mitigated this credit risk by securing TUAs for a significant portion of its regasification capacity
with creditworthy third-party customers with a minimum Standard & Poor’s rating of A.
75
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Debt
Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and
other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional
and retail investors.
Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net
of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees,
If debt issuance costs are incurred in connection with a line of credit
professional fees, legal fees and printing costs.
arrangement or on undrawn funds, they are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums
and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest
expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification
of debt are recorded in gain (loss) on modification or extinguishment of debt on our Consolidated Statements of Income.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the
acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method
of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an
ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the
liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the
estimated useful life of the asset.
We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease
agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG
terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at
the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to
surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is
immaterial.
We have not recorded an ARO associated with the Creole Trail Pipeline. We believe that it is not feasible to predict
when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our
right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. We intend to operate
the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it
regularly.
Income Taxes
We are not subject to federal or state income taxes, as our partners are taxed individually on their allocable share of our
taxable income. At December 31, 2020, the tax basis of our assets and liabilities was $8.2 billion less than the reported
amounts of our assets and liabilities. See Note 14—Related Party Transactions for details about income taxes under our tax
sharing agreements.
On September 14, 2020, U.S. Department of the Treasury (“Treasury”) and the Internal Revenue Service (“IRS”) issued
final and proposed regulations (“Regulations”) that modified the deductibility of interest expense in certain circumstances under
the Tax Cuts and Jobs Act (“TCJA”). Cheniere Partners has elected to conform with the Regulations which allow the
partnership to deduct additional interest expense for tax years ended December 31, 2019 and 2018. As required under the
Bipartisan Budget Act of 2015, Cheniere Partners adopted the Regulations by filing an Administrative Adjustment Request
(“AAR”) and Forms 8985, Pass-Through Statement—Transmittal/Partnership Adjustment Tracking Report, and 8986,
Partner’s share of Adjustment(s) to Partnership Related Item(s), for the tax years ended December 31, 2019 and 2018.
Cheniere Partners also furnished Form 8986 to each of its partners at the same time the AAR was filed with the IRS.
Unitholders are urged to consult their tax advisor regarding steps needed to account for these changes.
76
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Business Segment
Our liquefaction and regasification operations at the Sabine Pass LNG terminal represent a single reportable segment.
Our chief operating decision maker reviews the financial results of Cheniere Partners in total when evaluating financial
performance and for purposes of allocating resources.
NOTE 4—RESTRICTED CASH
Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been
presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2020 and 2019,
we had $97 million and $181 million of current restricted cash, respectively.
Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of SPL’s debt holders, SPL is
required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such
cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.
NOTE 5—ACCOUNTS AND OTHER RECEIVABLES
As of December 31, 2020 and 2019, accounts and other receivables, net consisted of the following (in millions):
SPL trade receivable
Other accounts receivable
Total accounts and other receivables, net
NOTE 6—INVENTORY
December 31,
2020
2019
$
$
300
18
318
$
$
As of December 31, 2020 and 2019, inventory consisted of the following (in millions):
Natural gas
LNG
Materials and other
Total inventory
December 31,
2020
2019
$
$
17
8
82
107
$
$
NOTE 7—PROPERTY, PLANT AND EQUIPMENT
As of December 31, 2020 and 2019, property, plant and equipment, net consisted of the following (in millions):
LNG terminal costs
LNG terminal and interconnecting pipeline facilities
LNG terminal construction-in-process
Accumulated depreciation
Total LNG terminal costs, net
Fixed assets
Fixed assets
Accumulated depreciation
Total fixed assets, net
Property, plant and equipment, net
December 31,
2020
2019
$
$
16,908
2,154
(2,344)
16,718
29
(24)
5
16,723
$
$
283
14
297
9
27
80
116
16,894
1,275
(1,807)
16,362
27
(21)
6
16,368
77
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows depreciation expense and offsets to LNG terminal costs during the years ended December 31,
2020, 2019 and 2018 (in millions):
Depreciation expense
Offsets to LNG terminal costs (1)
2020
$
Year Ended December 31,
2019
2018
$
547
—
$
523
48
413
94
(1)
We realize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were
earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during
the testing phase for its construction.
LNG Terminal Costs
The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG
terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal have depreciable lives
between 7 and 50 years, as follows:
Components
LNG storage tanks
Natural gas pipeline facilities
Marine berth, electrical, facility and roads
Water pipelines
Regasification processing equipment
Sendout pumps
Liquefaction processing equipment
Other
Fixed Assets and Other
Useful life (yrs)
50
40
35
30
30
20
7-50
10-30
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 8—DERIVATIVE INSTRUMENTS
We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and
operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges
(collectively, the “Liquefaction Supply Derivatives”).
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None
of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are
recorded within our Consolidated Statements of Income to the extent not utilized for the commissioning process.
The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a
recurring basis as of December 31, 2020 and 2019, which are classified as derivative assets, non-current derivative assets,
derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).
December 31, 2020
December 31, 2019
Fair Value Measurements as of
Quoted
Prices in
Active
Markets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Total
Quoted
Prices in
Active
Markets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Total
Liquefaction Supply
Derivatives asset (liability)
$
1
$
(1) $
(21) $
(21) $
3
$
(3) $
24
$
24
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as
needed, using observable commodity price curves, when available, and other relevant data.
The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable
market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events
deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The
fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions
precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable
physical gas flow. As of December 31, 2020 and 2019, some of our Physical Liquefaction Supply Derivatives existed within
markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.
We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the
fair value is developed through the use of internal models which incorporate significant unobservable inputs.
In instances
where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing
the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable
periods, liquidity, volatility and contract duration.
The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could
be materially impacted by a significant change in certain natural gas prices. The following table includes quantitative
information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2020:
Physical Liquefaction
Supply Derivatives
Net Fair Value
Liability
(in millions)
$(21)
Valuation Approach
Market approach incorporating
present value techniques
Significant
Unobservable Input
Henry Hub basis
spread
Range of Significant
Unobservable Inputs /
Weighted Average (1)
$(0.350) - $0.092 /
$(0.005)
(1)
Unobservable inputs were weighted by the relative fair value of the instruments.
Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical
Liquefaction Supply Derivatives.
The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during
the years ended December 31, 2020, 2019 and 2018 (in millions):
Balance, beginning of period
Realized and mark-to-market gains (losses):
Included in cost of sales
Purchases and settlements:
Purchases
Settlements
Transfers into Level 3, net (1)
Balance, end of period
Change in unrealized gain (loss) relating to instruments still held at end
of period
$
$
2020
$
Year Ended December 31,
2019
24
$
(25) $
2018
(43)
5
(7)
—
(21) $
(43) $
6
—
42
1
24
6
$
$
43
(3)
(37)
(29)
1
(25)
(3)
(1)
Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the
underlying natural gas purchase agreements.
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net
basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. The use of
derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its
commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that
we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We
incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value
79
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered
the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
Interest Rate Derivatives
We previously had interest rate swaps (“CQP Interest Rate Derivatives”) to hedge a portion of the variable interest
payments on our credit facilities. In October 2018, we terminated the CQP Interest Rate Derivatives related to the 2016 CQP
Credit Facilities.
The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in
derivative gain (loss), net on our Consolidated Statements of Income during the years ended December 31, 2020, 2019 and
2018 (in millions):
CQP Interest Rate Derivatives gain
$
— $
— $
14
Year Ended December 31,
2020
2019
2018
Liquefaction Supply Derivatives
SPL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges to
purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical
natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of
affairs.
The notional natural gas position of our Liquefaction Supply Derivatives was approximately 4,970 TBtu and 3,663 TBtu
as of December 31, 2020 and 2019, respectively, of which 91 TBtu and zero TBtu, respectively, were for a natural gas supply
contract that SPL has with a related party.
The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated
Balance Sheets (in millions):
Consolidated Balance Sheets Location
Derivative assets
Non-current derivative assets
Total derivative assets
Derivative liabilities
Non-current derivative liabilities
Total derivative liabilities
Derivative asset (liability), net
Fair Value Measurements as of (1)
December 31, 2020
December 31, 2019
$
14
11
25
(11)
(35)
(46)
(21) $
17
32
49
(9)
(16)
(25)
24
$
$
(1)
Does not include collateral posted with counterparties by us of $4 million and $2 million for such contracts, which are
included in other current assets in our Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively.
Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of December
31, 2020.
80
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives
recorded on our Consolidated Statements of Income during the years ended December 31, 2020, 2019 and 2018 (in millions):
Liquefaction Supply Derivatives gain (loss)
Liquefaction Supply Derivatives gain (loss)
Consolidated Statements of Income
Location (1)
LNG revenues
Cost of sales
$
Year Ended December 31,
2019
2018
2020
— $
(49)
$
1
71
(1)
(100)
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair
value fluctuations associated with commodity derivative activities are classified and presented consistently with the
item economically hedged and the nature and intent of the derivative instrument.
Consolidated Balance Sheets Presentation
Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The
following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):
Liquefaction Supply Derivatives
As of December 31, 2020
Gross assets
Offsetting amounts
Net assets
Gross liabilities
Offsetting amounts
Net liabilities
As of December 31, 2019
Gross assets
Offsetting amounts
Net assets
Gross liabilities
Offsetting amounts
Net liabilities
$
$
$
$
$
$
$
$
NOTE 9—OTHER NON-CURRENT ASSETS
As of December 31, 2020 and 2019, other non-current assets, net consisted of the following (in millions):
Advances made to municipalities for water system enhancements
Advances and other asset conveyances to third parties to support LNG terminal
Tax-related prepayments and receivables
Information technology service prepayments
Advances made under EPC and non-EPC contracts
Other
Total other non-current assets, net
$
$
84
33
17
6
9
11
160
$
$
December 31,
2020
2019
81
69
(44)
25
(48)
2
(46)
51
(2)
49
(27)
2
(25)
87
35
17
6
15
8
168
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 10—ACCRUED LIABILITIES
As of December 31, 2020 and 2019, accrued liabilities consisted of the following (in millions):
Interest costs and related debt fees
Accrued natural gas purchases
LNG terminal and related pipeline costs
Other accrued liabilities
Total accrued liabilities
NOTE 11—DEBT
December 31,
2020
2019
$
$
203
374
71
10
658
$
$
241
325
135
8
709
As of December 31, 2020 and 2019, our debt consisted of the following (in millions):
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due between 2022 and 2037 and
working capital facility (“2020 SPL Working Capital Facility”)
Cheniere Partners — 4.500% to 5.625% senior notes due between 2025 and 2029 and
credit facilities (“2019 CQP Credit Facilities”)
Unamortized premium, discount and debt issuance costs, net
Total long-term debt, net
Current debt:
SPL — $1.2 billion Amended and Restated SPL Working Capital Facility (“2015 SPL
Working Capital Facility”)
Total debt, net
December 31,
2020
2019
$
13,650
4,100
(170)
17,580
13,650
4,100
(171)
17,579
—
17,580
$
—
17,579
$
$
Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules,
on our outstanding debt at December 31, 2020 (in millions):
Years Ending December 31,
Principal Payments
2021
2022
2023
2024
2025
Thereafter
Total
$
$
—
1,000
1,500
2,000
3,523
9,727
17,750,
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Issuances and Redemptions
The following table shows the issuances and redemptions of long-term debt during the year ended December 31, 2020
(in millions):
Issuances
SPL — 4.500% Senior Secured Notes due 2030 (the “2030 SPL Senior Notes”) (1)
Year Ended December 31, 2020 total
Redemptions
SPL — 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”) (1)
Year Ended December 31, 2020 total
Principal Amount Issued
2,000
$
$
$
$
,
2,000
Amount Redeemed
(2,000)
(2,000)
)
( ,
(1)
Proceeds of the 2030 SPL Senior Notes, along with available cash, were used to redeem all of SPL’s outstanding 2021
SPL Senior Notes, resulting in the recognition of debt extinguishment costs of $43 million for the year ended
December 31, 2020 relating to the payment of early redemption fees and write off of unamortized debt premium and
issuance costs.
Credit Facilities
Below is a summary of our credit facilities outstanding as of December 31, 2020 (in millions):
2020 SPL Working Capital Facility (1)
2019 CQP Credit Facilities
Original facility size
Less:
Outstanding balance
Commitments prepaid or terminated
Letters of credit issued
Available commitment
$
$
1,200
$
—
—
413
787
$
1,500
—
750
—
750
Priority ranking
Interest rate on available balance
Weighted average interest rate of
outstanding balance
Maturity date
Senior secured
Senior secured
LIBOR plus 1.125% - 1.750% or base rate plus
0.125% - 0.750%
LIBOR plus 1.25% - 2.125% or base rate plus
0.25% - 1.125%
n/a
March 19, 2025
n/a
May 29, 2024
(1)
The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as
customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3%
(depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the
sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal
amount of swing line loans.
Restrictive Debt Covenants
The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events
of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain
investments or pay dividends or distributions.
As of December 31, 2020, we and SPL were in compliance with all covenants related to our respective debt agreements.
83
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Interest Expense
Total interest expense, net of capitalized interest consisted of the following (in millions):
Total interest cost
Capitalized interest
Total interest expense, net of capitalized interest
Fair Value Disclosures
2020
Year Ended December 31,
2019
2018
$
$
1,005
(96)
909
$
$
972
(87)
885
$
$
936
(203)
733
The following table shows the carrying amount and estimated fair value of our debt (in millions):
Senior notes — Level 2 (1)
Senior notes — Level 3 (2)
Credit facilities (3)
December 31, 2020
December 31, 2019
Carrying
Amount
Estimated
Fair Value
Carrying
Amount
Estimated
Fair Value
$
$
16,950
800
—
$
19,113
1,036
—
$
16,950
800
—
18,320
934
—
(1)
(2)
(3)
The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior
notes and other similar instruments.
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be
derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties
with comparable credit ratings to us and inputs that are not observable in the market.
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 12—LEASES
Our leased assets consist primarily of tug vessels and land sites, all of which are classified as operating leases.
Our policy is to recognize leases on our balance sheet by recording a lease liability representing the obligation to make
future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. As our leases
generally do not provide an implicit rate, in order to calculate the lease liability, we discounted our expected future lease
payments using our relevant subsidiary’s incremental borrowing rate at the later of January 1, 2019 or the commencement date
of the lease. The incremental borrowing rate is an estimate of the rate of interest that a given subsidiary would have to pay to
borrow on a collateralized basis over a similar term to that of the lease term.
Many of our leases contain renewal options exercisable at our sole discretion. Options to renew a lease are included in
the lease term and recognized as part of the right-of-use asset and lease liability only to the extent they are reasonably certain to
be exercised, such as when necessary to satisfy obligations that existed at the execution of the lease or when the non-renewal
would otherwise result in a significant economic penalty.
We have elected the practical expedient to omit leases with an initial term of 12 months or less (“short-term lease”) from
recognition on the balance sheet. We recognize short-term lease payments on a straight-line basis over the lease term and
variable payments under short-term leases in the period in which the obligation is incurred.
Certain of our leases contain non-lease components which are not separated from the lease components when calculating
the right-of-use asset and lease liability per our use of the practical expedient to combine both components of an arrangement
for all classes of leased assets.
84
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Certain of our leases also contain variable payments, such as inflation, that are not included when calculating the right-
of-use asset and lease liability unless the payments are in-substance fixed. We recognize lease expense for operating leases on
a straight-line basis over the lease term.
The following table shows the classification and location of our right-of-use assets and lease liabilities on our
Consolidated Balance Sheets (in millions):
Right-of-use assets—Operating
Current operating lease liabilities
Non-current operating lease liabilities
Consolidated Balance Sheets Location
Operating lease assets, net
Current operating lease liabilities
Non-current operating lease liabilities
$
December 31,
2020
2019
$
99
7
90
94
6
87
The following table shows the classification and location of our lease cost on our Consolidated Statements of Income (in
millions):
Operating lease cost (1)
Consolidated Statements of Income Location
Operating costs and expenses (2)
Year Ended December 31,
2020
2019
$
12
$
11
(1)
(2)
Includes $1 million and $1 million of variable lease costs paid to the lessor during the years ended December 31, 2020
and 2019, respectively.
Presented in cost of sales, operating and maintenance expense, general and administrative expense or general and
administrative expense—affiliate consistent with the nature of the asset under lease.
During the year ended December 31, 2018, we recognized rental expense for all operating leases of $16 million.
Future annual minimum lease payments for operating leases as of December 31, 2020 are as follows (in millions):
Years Ending December 31,
2021
2022
2023
2024
2025
Thereafter
Total lease payments
Less: Interest
Present value of lease liabilities
Operating Leases
11
11
11
11
11
116
171
(74)
97
$
$
The following table shows the weighted-average remaining lease term and the weighted-average discount rate for our
operating leases:
Weighted-average remaining lease term (in years)
Weighted-average discount rate
December 31,
2020
2019
24.5
4.1 %
26.4
4.8%
The following table includes other quantitative information for our operating leases (in millions):
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
$
11
$
10
Year Ended December 31,
2020
2019
85
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 13—REVENUES FROM CONTRACTS WITH CUSTOMERS
The following table represents a disaggregation of revenue earned from contracts with customers during the years ended
December 31, 2020, 2019 and 2018 (in millions):
LNG revenues (1)
LNG revenues—affiliate
Regasification revenues
Other revenues
Total revenues from customers
Net derivative gain (loss) (2)
Total revenues
2020
Year Ended December 31,
2019
2018
5,195
662
269
41
6,167
—
6,167
$
$
5,210
1,312
266
49
6,837
1
6,838
$
$
4,828
1,299
261
39
6,427
(1)
6,426
$
$
(1)
LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take
delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31,
2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that
they would not take delivery. Revenue is generally recognized upon receipt of irrevocable notice that a customer will
not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods
and our performance obligations with respect to such LNG cargo have been satisfied.
(2)
See Note 8—Derivative Instruments for additional information about our derivatives.
LNG Revenues
We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”)
(delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price
consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable
fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us
regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount
generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and
contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA
generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with
Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 14—Related Party
Transactions for additional information regarding these agreements.
Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the
Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to
the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price
(including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling
price for LNG at the time the contract was negotiated. We have concluded that the variable fees meet the exception for
allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is
allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer.
Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction
price.
Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective
Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of
construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and
bring the asset to the condition necessary for its intended use.
Regasification Revenues
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d. Approximately 2 Bcf/d
of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated
86
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal.
Each of the customers has reserved approximately 1 Bcf/d of regasification capacity. The customers are each obligated to make
monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009,
which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is
considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for
which the associated revenues are eliminated in consolidation.
Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of
transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over
time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service
to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a
straight-line basis over the term of the respective TUAs.
In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”),
whereby upon substantial completion of Train 5 of the Liquefaction Project, SPL gained access to substantially all of Total’s
capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing
and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo
loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the
development of Train 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to
SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments
received from Total as revenue. During the years ended December 31, 2020, 2019 and 2018, SPL recorded $129 million,
$104 million and $30 million, respectively, as operating and maintenance expense under this partial TUA assignment
agreement.
Deferred Revenue Reconciliation
The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our
Consolidated Balance Sheets (in millions):
Deferred revenues, beginning of period
Cash received but not yet recognized
Revenue recognized from prior period deferral
Deferred revenues, end of period
Year Ended December 31, 2020
155
137
(155)
137
$
$
We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a
customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred
revenue during the years ended December 31, 2020 and 2019 are primarily attributable to differences between the timing of
revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.
87
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Transaction Price Allocated to Future Performance Obligations
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future
consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the
transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2020 and 2019:
LNG revenues
LNG revenues—affiliate
Regasification revenues
Total revenues
December 31, 2020
December 31, 2019
Unsatisfied
Transaction Price
(in billions)
Weighted Average
Recognition
Timing (years) (1)
Unsatisfied
Transaction Price
(in billions)
$
$
52.1
0.1
2.1
54.3
9 $
1
5
$
55.0
—
2.4
57.4
Weighted Average
Recognition
Timing (years) (1)
10
0
5
(1)
The weighted average recognition timing represents an estimate of the number of years during which we shall have
recognized half of the unsatisfied transaction price.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1) We omit from the table above all performance obligations that are part of a contract that has an original expected
duration of one year or less.
(2) The table above excludes substantially all variable consideration under our SPAs and TUAs. We omit from the
table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to
a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation
when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not
included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to
the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of
our contracts contain additional variable consideration based on the outcome of contingent events and the
movement of various indexes. We have not included such variable consideration in the transaction price to the
the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt.
extent
Approximately 42% and 52% of our LNG revenues from contracts included in the table above during the years
ended December 31, 2020 and 2019, respectively, were related to variable consideration received from customers.
During each of the years ended December 31, 2020 and 2019, approximately 3% of our regasification revenues
were related to variable consideration received from customers.
We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones
such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial
completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition
purposes and are included in the transaction price above when the conditions are considered probable of being met.
88
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 14—RELATED PARTY TRANSACTIONS
Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the years
ended December 31, 2020, 2019 and 2018 (in millions):
LNG revenues—affiliate
Cheniere Marketing Agreements
Contracts for Sale and Purchase of Natural Gas and LNG
Total LNG revenues—affiliate
$
$
632
30
662
$
1,309
3
1,312
1,299
—
1,299
Year Ended December 31,
2019
2018
2020
Cost of sales—affiliate
Cheniere Marketing Agreements
Contracts for Sale and Purchase of Natural Gas and LNG
Total Cost of sales—affiliate
Operating and maintenance expense—affiliate
Services Agreements
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements
General and administrative expense—affiliate
Services Agreements
Other income—affiliate
Cooperative Endeavor Agreement
61
16
77
152
13
96
2
—
7
7
138
—
102
2
—
—
—
117
—
73
—
As of December 31, 2020 and 2019, we had $184 million and $105 million, respectively, of accounts receivable—
affiliate, under the agreements described below.
Cheniere Marketing Agreements
Cheniere Marketing SPA
Cheniere Marketing has an SPA (“Base SPA”) with SPL to purchase, at Cheniere Marketing’s option, any LNG
produced by SPL in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of
LNG.
In May 2019, SPL and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions
related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere
Marketing under the Base SPA can be sold by SPL to Cheniere Marketing at a contract price equal to a portion of the estimated
net profits from the sale of such cargo.
Cheniere Marketing Master SPA
SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by
executing and delivering confirmations under this agreement. SPL executed a confirmation with Cheniere Marketing that
obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas
and Chemicals, Inc. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project.
Cheniere Marketing Letter Agreements
In December 2020, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes
scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu.
89
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In December 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes that were
delivered in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.
In May 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling
approximately 70 million MMBtu that were delivered between May 3 and December 31, 2019 at a price of 115% of Henry Hub
plus $2.00 per MMBtu.
Facility Swap Agreement
In August 2020, SPL entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited
circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either
the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the
applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Natural Gas Transportation and Storage Agreements
SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing
agreement with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial
primary terms of up to 10 years with extension rights. We recorded operating and maintenance expense—related party of
$13 million in the year ended December 31, 2020 and accrued liabilities—related party of $4 million as of December 31, 2020
with this related party.
Services Agreements
As of December 31, 2020 and 2019, we had $144 million and $158 million of advances to affiliates, respectively, under
the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in
general and administrative expense—affiliate.
Cheniere Partners Services Agreement
We have a services agreement with Cheniere Terminals, a subsidiary of Cheniere, pursuant to which Cheniere Terminals
is entitled to a quarterly non-accountable overhead reimbursement charge of $3 million (adjusted for inflation) for the provision
of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for
all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the
agreement.
Cheniere Investments Information Technology Services Agreement
Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere
Investments’ subsidiaries receive certain information technology services. On a quarterly basis, the various entities receiving
the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement.
In
addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services
under the agreement.
SPLNG O&M Agreement
SPLNG has a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere
Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG
receiving terminal. SPLNG pays a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement
and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between
SPLNG and Cheniere Investments at the beginning of each operating year.
In addition, SPLNG is required to reimburse
Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the
services required under the SPLNG O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of
Cheniere. All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to
such subsidiary.
90
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
SPLNG MSA
SPLNG has a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals, pursuant to
which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided
for under the SPLNG O&M Agreement. SPLNG pays a monthly fixed fee of $520,000 (indexed for inflation) under the
SPLNG MSA.
SPL O&M Agreement
SPL has an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments pursuant to
which SPL receives all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before
each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining
governmental approvals on behalf of SPL, preparing an operating plan for certain periods, obtaining insurance, preparing
staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required
to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to
reimbursement of operating expenses, SPL is required to pay a monthly fee equal to 0.6% of the capital expenditures incurred
in the previous month. After substantial completion of each Train, for services performed while the Train is operational, SPL
will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for
services with respect to the Train. Cheniere Investments provides the services required under the SPL O&M Agreement
pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere
Investments under the SPL O&M Agreement are required to be remitted to such subsidiary.
SPL MSA
SPL has a management services agreement (the “SPL MSA”) with Cheniere Terminals pursuant to which Cheniere
Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the
SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s affairs and
business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s
business and operations, entering into financial derivatives on SPL’s behalf and providing contract administration services for
all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction
Project, SPL pays a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial
completion of each Train, SPL will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such
Train.
CTPL O&M Agreement
CTPL has an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere
Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline.
CTPL is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses.
Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement
with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M
Agreement are required to be remitted to such subsidiary.
Natural Gas Supply Agreement
SPL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain feed gas
for the operation of the Liquefaction Project. The term of the agreement is for five years, which can commence no earlier than
November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions
precedent.
Agreement to Fund SPLNG’s Cooperative Endeavor Agreements
SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing
authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This
initiative represented an aggregate commitment of $25 million over 10 years in order to aid in their reconstruction efforts
91
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish may grant
SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal as early as
2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which
Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the
Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere
Marketing, SPLNG will make payments to Cheniere Marketing equal to ad valorem tax levied on our LNG terminal in the year
the Cameron Parish dollar-for-dollar credit is applied.
On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from
Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as obligations. We had $2
million and $2 million in due to affiliates and $17 million and $20 million of other non-current liabilities—affiliate resulting
from these payments received from Cheniere Marketing as of December 31, 2020 and 2019, respectively.
Contracts for Sale and Purchase of Natural Gas and LNG
SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these
agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price
paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing
with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.
SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas
purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for
purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold
under this agreement is recorded as LNG revenues—affiliate.
Terminal Marine Services Agreement
In connection with its tug boat lease, Tug Services entered into an agreement with Cheniere Terminals to provide its
LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. The agreement also provides that Tug
Services shall contingently pay Cheniere Terminals a portion of its future revenues. Accordingly, Tug Services distributed $6
million, $8 million and $6 million during the years ended December 31, 2020, 2019 and 2018, respectively, to Cheniere
Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated
Statements of Partners’ Equity.
LNG Terminal Export Agreement
SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to
export LNG from the Sabine Pass LNG terminal. SPLNG did not record any revenues associated with this agreement during
the years ended December 31, 2020, 2019 and 2018.
State Tax Sharing Agreements
SPLNG has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file
all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the
combined state and local tax liability.
If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an
amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were calculated
on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have
demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from
SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.
SPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all
state and local tax returns which SPL and Cheniere are required to file on a combined basis and to timely pay the combined
state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPL will pay to Cheniere an amount equal to
the state and local tax that SPL would be required to pay if SPL’s state and local tax liability were calculated on a separate
company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment
92
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
from SPL under this agreement; therefore, Cheniere has not demanded any such payments from SPL. The agreement is
effective for tax returns due on or after August 2012.
CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all
state and local tax returns which CTPL and Cheniere are required to file on a combined basis and to timely pay the combined
state and local tax liability. If Cheniere, in its sole discretion, demands payment, CTPL will pay to Cheniere an amount equal to
the state and local tax that CTPL would be required to pay if CTPL’s state and local tax liability were calculated on a separate
company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment
from CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is
effective for tax returns due on or after May 2013.
NOTE 15—NET INCOME PER COMMON UNIT
Net income 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 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 27, 2021, we declared a $0.655 distribution per common unit and the related
distribution to our general partner and IDR holders that was paid on February 12, 2021 to unitholders of record as of February
8, 2021 for the period from October 1, 2020 to December 31, 2020.
The two-class method dictates that net income for a period be reduced by the amount of available cash that will be
distributed with respect to that period and that any residual amount representing undistributed net income to be allocated to
common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net
income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to
participating securities based on the distribution waterfall for available cash specified in the partnership agreement.
Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and
other participating securities on a pro rata basis based on provisions of the partnership agreement. Distributions are treated as
distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived
from current or prior period earnings.
The following table provides a reconciliation of net income and the allocation of net income to the common units, the
subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income per unit (in
millions, except per unit data).
93
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Limited Partner Units
Total
Common Units
Subordinated
Units
General Partner
Units
IDR
Year Ended December 31, 2020
Net income
Declared distributions
Assumed allocation of undistributed net loss (1)
Assumed allocation of net income
Weighted average units outstanding
Basic and diluted net income per unit
Year Ended December 31, 2019
Net income
Declared distributions
Assumed allocation of undistributed net loss (1)
Assumed allocation of net income
Weighted average units outstanding
Basic and diluted net income per unit
Year Ended December 31, 2018
Net income
Declared distributions
Assumed allocation of undistributed net income (1)
Assumed allocation of net income
Weighted average units outstanding
Basic and diluted net income per unit
$
$
$
$
$
$
1,183
1,375
(192)
1,175
1,278
)
(
(103)
1,274
1,162
112
$
$
$
$
$
$
1,080
(155)
925
399.3
2.32
858
(73)
785
348.6
2.25
795
79
874
348.6
2.51
$
$
$
$
$
$
27
(4)
23
$
174
(33)
141
$
84.7
1.67
333
(28)
305
$
26
(2)
24
$
135.4
2.25
309
31
340
$
22
2
24
$
135.4
2.51
94
—
94
62
—
62
36
—
36
(1)
Under our partnership agreement, the IDRs participate in net income only to the extent of the amount of cash
distributions actually declared, thereby excluding the IDRs from participating in undistributed net income.
NOTE 16—COMMITMENTS AND CONTINGENCIES
We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements.
Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability
as of December 31, 2020, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.
LNG Terminal Commitments and Contingencies
Obligations under EPC Contract
SPL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 6 of the
Liquefaction Project. The EPC contract price for Train 6 of the Liquefaction Project is approximately $2.5 billion, reflecting
amounts incurred under change orders through December 31, 2020, and including estimated costs for the third marine berth that
is currently under construction. As of December 31, 2020, we have incurred $1.9 billion under this contract. SPL has the right
to terminate the EPC contract for its convenience, in which case Bechtel will be paid (1) the portion of the contract price for the
work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump
sum of up to $30 million depending on the termination date.
94
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Obligations under SPAs
SPL has third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver
contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the
Liquefaction Project.
Obligations under LNG TUAs
SPLNG has third-party TUAs with Total and Chevron U.S.A. Inc. to provide berthing for LNG vessels and for the
unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.
Obligations under Natural Gas Supply, Transportation and Storage Service Agreements
SPL has physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The
remaining terms of these contracts range up to 10 years, some of which commence upon the satisfaction of certain events or
states of affairs. As of December 31, 2020, SPL has secured up to approximately 4,950 TBtu of natural gas feedstock through
natural gas supply contracts, a portion of which are considered purchase obligations if the certain events or states of affairs are
satisfied.
Additionally, SPL has natural gas transportation and storage service agreements for the Liquefaction Project. The initial
terms of the natural gas transportation agreements range up to 20 years, with renewal options for certain contracts, and
commence upon the occurrence of conditions precedent. The initial terms of the SPL natural gas storage service agreements
range up to 10 years.
As of December 31, 2020, SPL’s obligations under natural gas supply, transportation and storage service agreements for
contracts in which conditions precedent were met were as follows (in millions):
Years Ending December 31,
2021
2022
2023
2024
2025
Thereafter
Total
Payments Due (1)
2,949
1,785
1,294
884
767
2,210
9,889
$
$
(1)
Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread.
Amounts included are based on estimated forward prices and basis spreads as of December 31, 2020. Some of our
contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural
gas supply, transportation and storage services.
Services Agreements
We have certain services agreements with affiliates. See Note 14—Related Party Transactions for information regarding
such agreements.
Restricted Net Assets
At December 31, 2020, our restricted net assets of consolidated subsidiaries were approximately $982 million.
95
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Other Commitments
State Tax Sharing Agreements
SPLNG, SPL and CTPL have state tax sharing agreements with Cheniere. See Note 14—Related Party Transactions for
information regarding such agreements.
Other Agreements
In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of
which are considered material to our financial position.
Environmental and Regulatory Matters
The Sabine Pass LNG Terminal and CTPL are subject to extensive regulation under federal, state and local statutes, rules,
regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that
we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal
proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with
these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.
Legal Proceedings
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, 2020, there were no pending legal matters that
would reasonably be expected to have a material impact on our operating results, financial position or cash flows.
NOTE 17—CUSTOMER CONCENTRATION
The following table shows customers with revenues of 10% or greater of total revenues from external customers and
customers with accounts receivable, net balances of 10% or greater of total accounts receivable, net from external customers:
Percentage of Total Revenues from External Customers
Year Ended December 31,
2019
27%
18%
19%
20%
*
*
2018
28%
21%
23%
19%
—%
*
2020
24%
15%
17%
18%
*
11%
Percentage of Accounts Receivable, Net
from External Customers
December 31,
2020
31%
21%
*
22%
*
*
2019
21%
13%
22%
13%
13%
14%
Customer A
Customer B
Customer C
Customer D
Customer E
Customer F
* Less than 10%
96
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows revenues from external customers attributable to the country in which the revenues were
derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable
agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.
United States
India
South Korea
Ireland
Total
Revenues from External Customers
Year Ended December 31,
2020
2019
2018
2,769
970
924
842
,
5,505
$
$
2,354
1,113
1,071
988
,
5,526
$
$
1,880
981
1,168
1,098
,
5,127
$
$
NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in millions):
Cash paid during the period for interest, net of amounts capitalized
$
2020
Year Ended December 31,
2019
904
$
829
$
2018
719
The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including
affiliate) was $212 million, $291 million and $263 million as of December 31, 2020, 2019 and 2018, respectively.
NOTE 19—SUBSEQUENT EVENTS
In February 2021, SPL entered into a note purchase agreement for the sale of approximately $147 million aggregate
principal amount of 2.95% Senior Secured Notes due 2037 (the “2.95% SPL 2037 Senior Secured Notes”) on a private
placement basis. The 2.95% SPL 2037 Senior Secured Notes are expected to be issued in December 2021, and the net proceeds
are expected to be used to refinance a portion of SPL’s outstanding Senior Secured Notes due 2022. The 2.95% SPL 2037
Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years.
97
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
SUMMARIZED QUARTERLY FINANCIAL DATA
(unaudited)
Summarized Quarterly Financial Data—(in millions, except per unit amounts)
Year Ended December 31, 2020:
Revenues
Income from operations
Net income (loss)
Net income (loss) per common unit—basic and diluted (1)
Year Ended December 31, 2019:
Revenues
Income from operations
Net income
Net income per common unit—basic and diluted (1)
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$
$
$
$
1,718
664
435
0.84
1,749
563
385
0.75
$
$
1,470
684
406
0.78
1,705
455
232
0.44
$
$
982
152
(67)
(0.08)
1,476
346
110
0.19
1,997
625
409
0.77
1,908
676
448
0.87
(1) The sum of the quarterly net income per common unit may not equal the full year amount as the undistributed income and
loss allocations and computations of the weighted average common units outstanding for basic and diluted common units
outstanding for each quarter and the full year are performed independently.
98
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, 2020, 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 and is incorporated herein by reference.
ITEM 9B.
OTHER INFORMATION
On February 23, 2021, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to thirty-one (31)
cargoes to be scheduled for delivery between 2021 and 2026 at a price equal to 115% of Henry Hub plus $1.72 per MMBtu.
99
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND CORPORATE
GOVERNANCE
Management of Cheniere Partners
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 American
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 American, respectively.
The audit committee assists the board of directors of our general partner in its oversight of the integrity of our
Consolidated 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/.
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, James R. Ball, Lon McCain and Oliver G. Richard, III,
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 American, 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.
CMI SPA Committee
The board of directors of our general partner has formed a CMI SPA Committee, composed of James Ball, chairman,
Eric Bensaude and Scott Peak, to approve LNG sales entered into between Cheniere Marketing and SPL.
Other
We do not have a nominating committee because the directors of our general partner manage our 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.
100
Directors and Executive Officers of Our General Partner
The following sets forth information, as of February 19, 2021, regarding the individuals who currently serve on the board
of directors and as executive officers of our general partner. The appointments of Messrs. Henderson, Murski and Peak 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
Jack A. Fusco
James R. Ball
Eric Bensaude
Zach Davis
Wallace C. Henderson
Lon McCain
Mark Murski
Vincent Pagano, Jr.
Scott Peak
Oliver G. Richard, III
Aaron Stephenson
Age
58
70
54
36
58
72
45
70
40
68
65
Election Date
May 2016
Chairman of the Board and President and Chief Executive Officer
Position with Our General Partner
September 2012 Director
September 2016 Director
August 2020
Director and Senior Vice President and Chief Financial Officer
March 2007
September 2020 Director
Director
September 2020 Director
December 2012 Director
September 2020 Director
September 2012 Director
November 2019 Director and Senior Vice President, Operations
Jack A. Fusco
Chairman of the Board and President and Chief Executive Officer of our general partner
Mr. Fusco serves as a director and President and Chief Executive Officer of Cheniere; Chief Executive Officer of SPL
and a manager and President and Chief Executive Officer of the general partner of SPLNG. Mr. Fusco served as Chairman,
President and Chief Executive Officer of Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) from June 2016
to September 2018. Mr. Fusco served as the Executive Chairman of Calpine Corporation (“Calpine”) from May 2014 through
May 2016, Chief Executive Officer of Calpine from August 2008 to May 2014, President of Calpine from August 2008 to
December 2012 and director of Calpine from August 2008 to March 2018. From July 2004 to February 2006, Mr. Fusco served
as the Chairman and Chief Executive Officer of Texas Genco LLC. From 2002 through July 2004, Mr. Fusco was an exclusive
energy investment advisor for Texas Pacific Group. From November 1998 until February 2002, he served as founder, President
and Chief Executive Officer of Orion Power Holdings, Inc. Prior to his founding of Orion Power Holdings, Inc., Mr. Fusco
was a Vice President at Goldman Sachs Power, an affiliate of Goldman, Sachs & Co. Prior to joining Goldman, Sachs & Co.,
Mr. Fusco was employed by Pacific Gas & Electric Company or its affiliates in various engineering and management roles for
approximately 13 years. Mr. Fusco obtained a Bachelor of Science degree in Mechanical Engineering from California State
University, Sacramento. Mr. Fusco served as a director on the board of Foster Wheeler Ltd., a global engineering and
construction contractor and power equipment supplier, until February 2009 and on the board of Graphics Packaging Holdings, a
paper and packaging company, until 2008. It was determined that Mr. Fusco should serve as a director of our general partner
because of his prior experience leading successful energy industry companies and his perspective as President and Chief
Executive Officer of Cheniere.
James R. Ball
Director of our general partner, Chairman of the Executive Committee and the CMI SPA Committee and a member of the
Conflicts Committee
Mr. Ball served as a senior advisor to Tachebois Limited, an energy and equities advisory firm, from 2011 to 2019. 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, a company he founded and where he spent his career advising on financing and developing many of
the world’s largest LNG projects. 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.
101
Eric Bensaude
Director of our general partner and a member of the CMI SPA Committee
Mr. Bensaude joined Cheniere in September 2013 and currently serves as Managing Director, Commercial Operations
and Asset Optimization of Cheniere Marketing Ltd., a subsidiary of Cheniere. Mr. Bensaude also serves as Senior Vice
President, Commercial Operations of SPL. Mr. Bensaude has more than 20 years of experience in the energy, oil and natural
gas trading and marketing business. Prior to joining Cheniere, Mr. Bensaude served as Head of Global LNG at EDF Trading
where he set up and ran the LNG trading and marketing department and General Manager for natural gas and LNG origination.
Prior to EDF Trading, Mr. Bensaude was an Associate at Booz Allen & Hamilton in the Energy Practice, working on a variety
of gas & power assignments. Mr. Bensaude started his career in energy as a trader of middle distillates for Total and previously
served as the representative for the French bank, Société Générale, in Canton, People’s Republic of China. He held the position
of Vice-Chairman of the European Federation of Energy Traders Gas Committee while at EDF Trading. Mr. Bensaude holds
an MBA from ESSEC business school in France, and studied Mandarin at Paris 7 Jussieu. It was determined that Mr. Bensaude
should serve as a director of our general partner because of his experience in the energy, oil and natural gas trading and
marketing industry. Mr. Bensaude has not held any other directorship positions in the past five years.
Zach Davis
Senior Vice President and Chief Financial Officer and a Director of our general partner and a member of the Executive
Committee
Mr. Davis currently serves as Senior Vice President and Chief Financial Officer of Cheniere. Mr. Davis joined Cheniere
in November 2013. He previously served as Senior Vice President, Finance from February 2020 to August 2020 and as Vice
President, Finance and Planning from October 2016 to February 2020. Mr. Davis has over 13 years of energy finance
experience, focusing on strategic advisory assignments and financings for companies, projects and assets in the LNG, power,
renewable energy, midstream and infrastructure sectors. Prior to joining Cheniere, Mr. Davis held energy investment banking
and project finance roles at Credit Suisse, Marathon Capital and HSH Nordbank. Mr. Davis received a B.S. in Economics from
Duke University.
Wallace C. Henderson
Director of our general partner and a member of the Executive Committee
Mr. Henderson has served as a Senior Managing Director at Blackstone Infrastructure Partners since January 2018 and
leads the fund's investment activities in the midstream sector. From May 2011 to December 2017, Mr. Henderson served in
various roles at EIG Global Energy Partners, LLC, most recently as Managing Director and member of the firm's Executive
Committee. At EIG, Mr. Henderson led the company's global investment activities in midstream energy infrastructure,
including a significant investment in Cheniere Energy's Corpus Christi LNG facility in 2015. Prior to joining EIG, Mr.
Henderson was a senior financial consultant to Coskata, Inc., an energy technology company, from May 2009 until May 2011.
Prior to Coskata, Mr. Henderson was an energy investment banker at UBS Investment Bank for five years following 18 years at
Credit Suisse where he specialized in oil and gas project finance, corporate capital raising and mergers and acquisitions for
large U.S. and international oil companies. Mr. Henderson currently serves as a director of Tallgrass Energy, L.P., a midstream
energy infrastructure company. Mr. Henderson served as a director of Southcross Energy Partners GP, LLC, the general
partner of Southcross Energy Partners, L.P., from August 2014 to November 2017. Mr. Henderson holds a Bachelor's degree in
Economics from Kenyon College and a Master of Business Administration degree from Columbia University.
Lon McCain
Director of our general partner, Chairman of the Audit Committee and a member of the Conflicts Committee
Mr. McCain 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. 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. 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.
102
Mark Murski
Director of our general partner and a member of the Executive Committee
Mr. Murski is a Managing Partner and Chief Operating Officer in the Americas for Brookfield Infrastructure, where he is
responsible for North American infrastructure operations. From 2006 to 2015 he worked for Brookfield's global advisory
practice, where he ran the mergers and acquisitions practice. Mr. Murski joined Brookfield in 2003 where he focused on
financings, acquisitions and divestitures. Mr. Murski currently serves as a director of City Office REIT Inc., a real estate
company focused on office properties in the southern and western United States. Mr. Murski is a Chartered Professional
Accountant, a CFA charterholder and is a graduate of the Richard Ivey School of Business.
Vincent Pagano, Jr.
Director of our general partner, Chairman of the Conflicts Committee and 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. Mr. Pagano also serves as a director of
Hovnanian Enterprises, Inc., a publicly traded homebuilding company.
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.
Scott Peak
Director of our general partner and a member of the Executive Committee and CMI SPA Committee
Mr. Peak is a Managing Partner and Chief Investment Officer for Brookfield Infrastructure, where he is responsible for
utilities and energy infrastructure investments. Prior to joining Brookfield in January 2016, Mr. Peak spent almost a decade at
Macquarie Group Ltd. based in New York and Houston focused on the infrastructure sector. Previously, Mr. Peak worked in
the mergers and acquisitions group at Dresdner Kleinwort Wasserstein in New York. Mr. Peak holds a Master of Finance with
distinction from INSEAD and a B.A. in Economics from Bates College.
Oliver G. Richard, III
Director of our general partner and a member of the Audit Committee and Conflicts Committee
Mr. Richard is 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, and as a director of Buckeye Partners, L.P., a publicly traded petroleum product
pipeline and terminal company, from 2009 through its acquisition in 2019. Mr. Richard was a Commissioner on the FERC
from 1982 until 1985. Mr. Richard currently serves as a director of American Electric Power Company, Inc., a publicly traded
electric utility. Mr. Richard received a B.S. in Journalism, 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.
Aaron Stephenson
Senior Vice President, Operations and a Director of our general partner
Mr. Stephenson joined Cheniere in April 2013 as Director, Production, Sabine Pass Operations, leading the effort to
prepare for liquefaction operations. In May 2016, he moved into the position of Vice President and General Manager for the
Sabine Pass facility. Mr. Stephenson has over 40 years of experience in the energy industry, focusing for the past 17 years on
LNG. He has worked in various locations around the world, including Yemen, London and Peru. Before joining Cheniere, he
served as Plant Manager at Peru LNG. His professional experience includes filling the roles of LNG Plant Manager, E&P
Manager, Commissioning Manager, Plant Engineering Manager and Project Engineer. Prior company affiliations include
Cities Service Oil Co., Oxy USA and Hunt Oil Co. Mr. Stephenson has a B.S. in Mechanical Engineering from Lamar
University. It was determined that Mr. Stephenson should serve as a director of our general partner because of his background
in the LNG industry. Mr. Stephenson has not held any other directorship positions in the past five years.
103
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 of our
directors, officers and employees, 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.
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 $3 million (adjusted for inflation). For a description of the services agreement,
see Note 14—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:
Jack A. Fusco
James R. Ball
Eric Bensaude
Zach Davis
Wallace C. Henderson
Lon McCain
Mark Murski
Vincent Pagano, Jr.
Scott Peak
Oliver G. Richard, III
Aaron Stephenson
104
Compensation Committee Interlocks and Insider Participation
If any
As discussed above, the board of directors of our general partner does not have a compensation committee.
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. 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 2020.
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; $2,500 per meeting for the
non-employee members of the executive committee, including the chairman; and $30,000 for the chairman of the CMI SPA
Committee. 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, Messrs. Ball, McCain, Pagano and Richard each
receive 3,000 phantom units annually. 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. Henderson
serves as a Senior Managing Director at Blackstone Infrastructure Partners, Mr. Murski serves as a Managing Partner and Chief
Operating Officer in the Americas for Brookfield Infrastructure and Mr. Peak serves as a Managing Partner and Chief
Investment Officer for Brookfield Infrastructure. They do not receive additional compensation for service as directors.
Additionally, our former directors Philip Meier, John-Paul Munfa and Jamie Welch, who resigned from the board of
directors of our general partner in September 2020, were previously appointed to the board 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. As such, Mr. Munfa and Mr. Welch did not receive any
additional compensation for their service as directors. Philip Meier and Meier Consulting LLC entered into a letter agreement,
dated June 14, 2013, as amended (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 received no additional
compensation for his service as a director.
105
The following table shows the compensation paid for service as a member of the board of directors of our general partner
for the 2020 fiscal year:
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
$
— $
— $
117,500
—
—
—
107,500
—
102,500
—
92,500
—
—
—
—
—
103,470
—
—
—
101,220
—
112,710
—
103,470
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Total
—
220,970
—
—
—
208,720
—
215,210
—
195,970
—
—
—
—
—
Name
Jack A. Fusco (2)
James R. Ball (3)
Eric Bensaude (2)
Zach Davis (2)
Wallace C. Henderson (4)
Lon McCain (5)
Mark Murski (4)
Vincent Pagano, Jr. (6)
Scott Peak (4)
Oliver G. Richard, III (7)
Aaron Stephenson (2)
Michael J. Wortley (2)
Philip Meier (8)
John-Paul Munfa (9)
Jamie Welch (9)
(1) Reflects aggregate grant date fair value. The phantom units are to be settled, at the director’s election, in common
units, cash, or an equal amount of both. The units are valued using the closing unit price on the date of grant and are
revalued on a quarterly basis through the date of vesting.
(2) Mr. Fusco served as an executive officer of our general partner and as an executive officer of Cheniere during fiscal
year 2020. Mr. Bensaude served as an officer of Cheniere Marketing Ltd., a subsidiary of Cheniere during fiscal year
2020. Mr. Davis served as an executive officer of our general partner and as an executive officer of Cheniere from
since August 6, 2020. Mr. Stephenson served as an officer of our general partner and as an executive officer of
Cheniere during fiscal year 2020. Mr. Wortley served as an executive officer of our general partner and as an
executive officer of Cheniere until his resignation on August 6, 2020. Cheniere compensates these officers for the
performance of their duties as employees of Cheniere, which includes managing our partnership. They do not receive
additional compensation for service as directors.
(3) Mr. Ball was granted 3,000 phantom units in 2020 with a grant date fair value of $103,470.
In addition, Mr. Ball
received $51,735 in cash and 1,500 common units on account of 3,000 phantom units granted in earlier years that
vested in 2020. As of December 31, 2020, he held 7,500 phantom units and 6,450 common units for a total of 13,950
units.
(4) Mr. Henderson is a Senior Managing Director at Blackstone Infrastructure Partners, Mr. Murski is a Managing Partner
and Chief Operating Officer in the Americas for Brookfield Infrastructure and Mr. Peak is a Managing Partner and
Chief Investment Officer for Brookfield Infrastructure. They do not receive additional compensation for service as
directors.
(5) Mr. McCain was granted 3,000 phantom units in 2020 with a grant date fair value of $101,220.
In addition, Mr.
McCain received $50,610 in cash and 1,500 common units on account of 3,000 phantom units granted in earlier years
that vested in 2020. As of December 31, 2020, he held 7,500 phantom units and 8,250 common units for a total of
15,750 units.
(6) Mr. Pagano was granted 3,000 phantom units in 2020 with a grant date fair value of $112,710.
In addition, Mr.
Pagano received $56,355 in cash and 1,500 common units on account of 3,000 phantom units granted in earlier years
that vested in 2020. As of December 31, 2020, he held 7,500 phantom units and 7,125 common units for a total of
14,625 units.
(7) Mr. Richard was granted 3,000 phantom units in 2020 with a grant date fair value of $103,470.
In addition, Mr.
Richard received $38,801 in cash and 1,875 common units on account of 3,000 phantom units granted in earlier years
106
that vested in 2020. As of December 31, 2020, he held 7,500 phantom units and 11,250 common units for a total of
18,750 units.
(8) Effective as of September 24, 2020, Mr. Meier resigned as a member of the board of directors of our general partner.
Mr. Meier was 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.
(9) Effective as of September 24, 2020, Messrs. Munfa and Welch resigned as members of the board of directors of our
general partner. Mr. Munfa was a Managing Director in the Private Equity Group of Blackstone Group, and Mr.
Welch served as a Senior Advisor to Blackstone Group. They did not receive additional compensation for their service
as directors.
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, selling unitholder, 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 19, 2021, the following units were
outstanding: 484.0 million common units and 9.9 million general partner units.
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.
107
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 and/or
general partner units as of February 19, 2021:
Name of Beneficial Owner
Cheniere Energy, Inc. (1)
The Blackstone Group Inc. (2)
Brookfield Asset Management Inc. (3)
* Less than 1%
Common Units
Beneficially Owned
239,872,502
206,080,463
204,321,313
Percentage of Common
Units Beneficially Owned
50%
43%
42%
Percentage of Total
Securities Beneficially
Owned
51%
42%
41%
(1)
(2)
(3)
Cheniere Energy, Inc. also owns 9,877,677 of our general partner units.
Information is based on the Schedule 13D/A filed with the SEC on September 28, 2020 by BX Rockies Platform Co
LLC (record holder of 2,250,419 common units), Blackstone CQP Common Holdco L.P. (record holder of 2,011,447
common units), Blackstone CQP Common Holdco GP LLC, BX CQP Common Holdco Parent L.P., BX CQP Common
Holdco Parent GP LLC, Blackstone CQP Holdco LP (record holder of 185,808,450 common units), Blackstone CQP
Holdco II GP LLC, Blackstone CQP FinanceCo LP, Blackstone CQP Holdco GP LLC, BX CQP Target Holdco L.L.C.,
BIP Chinook Holdco L.L.C., BIP-V Chinook Holdco L.L.C. (record holder of 13,170,436 common units), BIP Holdings
Manager L.L.C., Blackstone Infrastructure Associates L.P., BIA GP L.P., BIA GP L.L.C., BX Rockies Platform Co
Holdings Manager L.L.C., BX CQP Common Holdco Holdings Manager L.L.C., BX CQP SuperHoldCo Holdings
Manager L.L.C., Blackstone Management Associates VI L.L.C., Blackstone Energy Management Associates L.L.C.,
BMA VI L.L.C., Blackstone EMA L.L.C., Blackstone Holdings III L.P., Blackstone Holdings III GP L.P, Blackstone
Holdings III GP Management L.L.C., GSO Credit-A Partners LP (record holder of 953,855 common units), GSO Credit-
A Associates LLC, GSO Palmetto Opportunistic Investment Partners LP (record holder of 953,855 common units), GSO
Palmetto Opportunistic Associates LLC, GSO Credit Alpha Fund AIV-2 LP (record holder of 462,922 common units),
GSO Credit Alpha Associates LLC, GSO Holdings I L.L.C., Blackstone Holdings II L.P., Blackstone Holdings I/II GP
L.L.C., The Blackstone Group Inc., Blackstone Group Management L.L.C. and Stephen A. Schwarzman, and filings of
Form 4 on December 31, 2020, January 5, 2021 and January 6, 2021 by BIP Holdings Manager, L.L.C., BIA GP L.L.C.,
BIA GP L.P., Blackstone Infrastructure Associates L.P., BX Rockies Platform Co LLC, BIP Chinook Holdco L.L.C.
(record holder of 138,772 common units) and BIP-V Chinook Holdco II L.L.C. (record holder of 48,544 common units).
In addition, Harvest Fund Advisors LLC, an indirect subsidiary of The Blackstone Group Inc., is the beneficial owner of
281,763 common units. The address of the various persons identified in this footnote is 345 Park Avenue, New York,
New York 10154.
Information is based on the Schedule 13D/A filed with the SEC on September 30, 2020 by Brookfield Asset
Management Inc. (“Brookfield”), BIF IV Cypress Aggregator (Delaware) LLC (“BIF Aggregator”), Brookfield
Infrastructure Fund IV GP LLC (“BIF”), Brookfield Asset Management Private Institutional Capital Adviser (Canada),
L.P. (“BAMPIC Canada”) and Partners Limited (“Partners”). Investment funds managed by Brookfield Public Securities
Group LLC are the beneficial owners of 1,080,561 common units. 2,011,447 of the Common Units reported herein as
being beneficially owned by the Reporting Persons are directly held by BX Rockies Platform Co LLC, a Delaware
limited liability company (“BX Rockies”). 185,808,450 of the Common Units reported herein as being beneficially
owned by the Reporting Persons are directly held by Blackstone CQP Holdco LP, a Delaware limited partnership
(“Blackstone Holdco”). 2,250,419 of the Common Units reported herein as being beneficially owned by the Reporting
Persons are directly held by Blackstone CQP Common Holdco L.P., a Delaware limited partnership (“Blackstone
Common Holdco”). 13,170,436 of the Common Units reported herein as being beneficially owned by the Reporting
Persons are directly held by BIP-V Chinook Holdco L.L.C., a Delaware limited liability company (“BIP-V”). BX CQP
Target Holdco L.L.C. (“Target Holdco”) is the indirect equityholder of all of the equity interests in each of BX Rockies,
Blackstone Common Holdco and Blackstone Holdco and, by virtue of its relationship with BIP-V, may be deemed to
share beneficial ownership over the Common Units held by BIP-V. BIF IV Cypress Aggregator is a member of Target
Holdco. BIF serves as the indirect general partner of BIF IV Cypress Aggregator. BAMPIC Canada serves as the
investment adviser to BIF. Brookfield is the ultimate parent of BIF and BAMPIC Canada. As a result, BIF IV Cypress
Aggregator, BIF, BAMPIC Canada, Brookfield and Partners may be deemed to beneficially own the Common Units held
of record by each of BX Rockies, Blackstone Common Holdco, Blackstone Holdco and BIP-V. The address of the
various persons identified in this footnote is 181 Bay Street, Suite 300, Brookfield Place, Toronto, Ontario M5J 2T3,
Canada.
108
Directors and Executive Officers
The following table sets forth information with respect to our common units beneficially owned as of February 19, 2021,
by each director and executive officer of our general partner and by all current directors and executive officers of our general
partner as a group. On February 19, 2021, the current directors and executive officers of Cheniere Partners beneficially owned
an aggregate of 33,075 common units (less than 1% of the outstanding common units at the time).
The table also presents information with respect to Cheniere Energy, Inc.’s common stock beneficially owned as of
February 19, 2021, by each current director and executive officer of our general partner and by all directors and executive
officers of our general partner as a group. As of February 19, 2021, Cheniere Energy, Inc. had 254 million shares of common
stock outstanding.
Name of Beneficial Owner
Jack A. Fusco (1)
Michael J. Wortley (2)
Zach Davis
Eric Bensaude
Aaron Stephenson
James R. Ball
Wallace C. Henderson (3)
Lon McCain
Mark Murski (3)
Vincent Pagano, Jr.
Scott Peak (3)
Oliver G. Richard, III
All current directors and executive officers as a
group (11 persons) (4)
Cheniere Energy Partners, L.P.
Cheniere Energy, Inc.
Amount and Nature of
Beneficial Ownership
Percent of
Class
Amount and Nature of
Beneficial Ownership
Percent of
Class
—
—
—
—
—
6,450
—
8,250
—
7,125
—
11,250
33,075
— %
—
—
—
—
—
—
—
*
*
*
*
1,040,540 (1)
551,798
110,492
—
76,895
—
—
—
—
—
—
—
*%
1,227,927
*%
*
*
—
*
—
—
—
—
—
—
—
*%
*
(1)
(2)
(3)
(4)
Less than 1%
Includes 198,778 shares held by trust.
The number of shares set forth for Mr. Wortley is based on the Form 4 filed on February 18, 2020 for Mr. Wortley.
Mr. Wortley ceased to be employed by our general partner on August 31, 2020 and is no longer required to report his
holdings in Cheniere Partner’s or Cheniere Energy Inc.’s securities pursuant to Section 16(a) of the Securities Act.
Messrs. Henderson, Murski and Peak 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.
Excludes shares owned by Mr. Wortley, who was no longer an executive officer of our general partner on February 19,
2021.
109
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, 2020 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
—
15,000
15,000
N/A
N/A
N/A
Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in the first
column) (2)
—
1,194,500
1,194,500
(1)
(2)
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.
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 inNot e 14
—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:
•
•
•
whether the related party transaction is on terms no less favorable than the terms generally available to an unaffiliated
third-party under the same or similar circumstances;
whether the transaction is material to the Company or the related party; and
the extent of the related person’s interest in the transaction.
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 Compliance
If a conflict or potential conflict of interest arises between us and a
Officer any conflict or potential conflict of interest.
110
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.
Arrangements involving Mr. Meier and Meier Consulting LLC
As noted above, Blackstone CQP Holdco, our former director 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 and an annual performance consulting
fee in Blackstone CQP Holdco’s discretion. In 2020, Blackstone CQP Holdco paid Mr. Meier $541,667 as a base consulting
fee. Mr. Meier resigned from the board of directors of our general partner effective September 24, 2020.
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 2020 under the Blackstone Consultant Letter Agreement.
Independent Directors
Because we are a limited partnership, the NYSE American 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 American. The board of our
general partner has determined that Messrs. Ball, McCain, Pagano and Richard are independent directors in accordance with the
following NYSE American independence standards. A director would not be independent if any of the following relationships
exists:
•
•
•
•
•
•
a director who is, or during the past three years was, employed by the partnership, general partner or by any parent or
subsidiary of the partnership or general partner, other than prior employment as an interim executive officer (provided
the interim employment did not last longer than one year);
a director who accepts, or has an immediate family member who accepts, any compensation from the partnership,
general partner or any parent or subsidiary of the partnership or general partner in excess of $120,000 during any
twelve consecutive-month period within the three years preceding the determination of independence, other than
compensation for board or committee services, or compensation paid to an immediate family member who is a non-
executive employee of the partnership, general partner or any parent or subsidiary of the partnership or general partner,
among other exceptions;
a director who is an immediate family member of an individual who is, or at any time during the past three years was,
employed by the partnership, general partner or any parent or subsidiary of the partnership or general partner as an
executive officer;
a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive
officer of, any organization to which the partnership, general partner or any parent or subsidiary of the partnership or
general partner made, or from which the partnership, general partner or any parent or subsidiary of the partnership or
general partner received, payments (other than those arising solely from investments in our common units or payments
under non-discretionary charitable contribution matching programs) that exceed 5% of the organization’s consolidated
gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years;
a director who is, or has an immediate family member who is, employed as an executive officer of another entity
where at any time during the most recent three fiscal years any of the executive officers of the partnership, general
partner or any parent or subsidiary of the partnership or general partner serves on the compensation committee of such
other entity; or
a director who is, or has an immediate family member who is, a current partner of the outside auditor of the
partnership, general partner or parent or subsidiary of the partnership or general partner, or was a partner or employee
of the outside auditor of the partnership, general partner or any parent or subsidiary of the partnership or general
partner who worked on our audit at any time during any of the past three years.
111
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
KPMG LLP served as our independent auditor for the fiscal years ended December 31, 2020 and 2019. The following
table sets forth the fees paid to KPMG LLP for professional services rendered for 2020 and 2019 (in millions):
Audit Fees
Fiscal 2020
Fiscal 2019
$
3
$
3
Audit Fees—Audit fees for 2020 and 2019 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 2020 and 2019.
Tax Fees—There were no tax fees in 2020 and 2019.
Other Fees—There were no other fees in 2020 and 2019.
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,
2020 and 2019 were pre-approved.
112
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
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Partners’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements—Quarterly Financial Data
(2)
Financial Statement Schedules:
Schedule I—Condensed Financial Information of Registrant for the years ended December 31, 2020, 2019 and 2018
62
63
67
68
69
70
71
98
121
(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:
•
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one
of the parties if those statements prove to be inaccurate;
• may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the
agreements, which disclosures are not necessarily reflected in the agreements;
• may apply standards of materiality that differ from those of a reasonable investor; and
•
were made only as of specified dates contained in the agreements and are subject to subsequent developments and
changed circumstances.
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
2.2
Incorporated by Reference (1)
Description
Contribution and Conveyance Agreement, by and among the
Partnership, Cheniere LNG Holdings, LLC, Cheniere Partners GP,
Cheniere Investments, Sabine Pass LNG-GP, Inc. and Sabine Pass
LNG-LP, LLC, effective as of March 26, 2007
Amended and Restated Purchase and Sale Agreement, dated as of
August 9, 2012, by and among the Partnership, Cheniere Pipeline
Company, Grand Cheniere Pipeline, LLC and Cheniere
Entity
Cheniere
Partners
Cheniere
Partners
Form Exhibit Filing Date
3/26/2007
8-K
10.4
8-K
10.2
8/9/2012
113
Exhibit
No.
Description
3.1
Certificate of Limited Partnership of the Partnership
3.2
3.3
3.4
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
Fourth Amended and Restated Agreement of Limited Partnership
of the Partnership, dated as of February 14, 2017
Certificate of Formation of Cheniere Partners GP
Third Amended and Restated Limited Liability Company
Agreement of Cheniere Partners GP, dated as of August 9, 2012
Form of common unit certificate (Included as Exhibit A to Exhibit
3.2 above)
Indenture, dated as of February 1, 2013, by and among SPL, the
guarantors that may become party thereto from time to time and
The Bank of New York Mellon, as trustee
First Supplemental Indenture, dated as of April 16, 2013, between
SPL and The Bank of New York Mellon, as Trustee
Second Supplemental Indenture, dated as of April 16, 2013,
between SPL and The Bank of New York Mellon, as Trustee
Form of 5.625% Senior Secured Note due 2023 (Included as
Exhibit A-1 to Exhibit 4.4 above)
Third Supplemental Indenture, dated as of November 25, 2013,
between SPL and The Bank of New York Mellon, as Trustee
Form of 6.25% Senior Secured Note due 2022 (Included as Exhibit
A-1 to Exhibit 4.6 above)
Fourth Supplemental Indenture, dated as of May 20, 2014, between
SPL and The Bank of New York Mellon, as Trustee
Form of 5.750% Senior Secured Note due 2024 (Included as
Exhibit A-1 to Exhibit 4.8 above)
Fifth Supplemental Indenture, dated as of May 20, 2014, between
SPL and The Bank of New York Mellon, as Trustee
Form of 5.625% Senior Secured Note due 2023 (Included as
Exhibit A-1 to Exhibit 4.10 above)
Sixth Supplemental Indenture, dated as of March 3, 2015, between
SPL and The Bank of New York Mellon, as Trustee
Form of 5.625% Senior Secured Note due 2025 (Included as
Exhibit A-1 to Exhibit 4.12 above)
Seventh Supplemental Indenture, dated as of June 14, 2016,
between SPL and The Bank of New York Mellon, as Trustee under
the Indenture
Form of 5.875% Senior Secured Note due 2026 (Included as
Exhibit A-1 to Exhibit 4.13 above)
Eighth Supplemental Indenture, dated as of September 19, 2016,
between SPL and The Bank of New York Mellon, as Trustee under
the Indenture
Ninth Supplemental Indenture, dated as of September 23, 2016,
between SPL and The Bank of New York Mellon, as Trustee under
the Indenture
Form of 5.00% Senior Secured Note due 2027 (Included as Exhibit
A-1 to Exhibit 4.17 above)
Tenth Supplemental Indenture, dated as of March 6, 2017, between
SPL and The Bank of New York Mellon, as Trustee under the
Indenture
Form of 4.200% Senior Secured Note due 2028 (Included as
Exhibit A-1 to Exhibit 4.19 above)
114
Incorporated by Reference (1)
Entity
Cheniere
Partners
(SEC File No.
333-139572)
Cheniere
Partners
Cheniere
Partners
(SEC File No.
333-139572)
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Form Exhibit Filing Date
12/21/2006
S-1
3.1
8-K
S-1
8-K
8-K
8-K
3.1
2/21/2017
3.3
12/21/2006
3.2
3.1
4.1
8/9/2012
2/21/2017
2/4/2013
8-K
4.1.1
4/16/2013
8-K
4.1.2
4/16/2013
8-K
4.1.2
4/16/2013
8-K
8-K
8-K
8-K
8-K
8-K
8-K
8-K
8-K
8-K
8-K
4.1
4.1
4.1
4.1
4.2
4.2
4.1
4.1
4.1
4.1
4.1
11/25/2013
11/25/2013
5/22/2014
5/22/2014
5/22/2014
5/22/2014
3/3/2015
3/3/2015
6/14/2016
6/14/2016
9/23/2016
8-K
4.2
9/23/2016
8-K
8-K
4.2
4.1
9/23/2016
3/6/2017
8-K
4.1
3/6/2017
Exhibit
No.
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
Description
Eleventh Supplemental Indenture, dated as of May 8, 2020,
between SPL and The Bank of New York Mellon, as Trustee under
the Indenture
Form of 4.500% Senior Secured Note due 2030 (Included as
Exhibit A-1 to Exhibit 4.21 above)
Indenture, dated as of February 24, 2017, between SPL,
the
guarantors that may become party thereto from time to time and
The Bank of New York Mellon, as Trustee under the Indenture
Form of 5.00% Senior Secured Note due 2037 (Included as Exhibit
A-1 to Exhibit 4.23 above)
Indenture, dated as of September 18, 2017, between the
Partnership, the guarantors party thereto and The Bank of New
York Mellon, as Trustee under the Indenture
First Supplemental Indenture, dated as of September 18, 2017,
between the Partnership, the guarantors party thereto and The Bank
of New York Mellon, as Trustee under the Indenture
Form of 5.250% Senior Note due 2025 (Included as Exhibit A-1 to
Exhibit 4.26 above)
Second Supplemental Indenture, dated as of September 11, 2018,
among the Partnership, the guarantors party thereto and The Bank
of New York Mellon, as Trustee under the Indenture
Form of 5.625% Senior Note due 2026 (Included as Exhibit A-1 to
Exhibit 4.28 above)
Third Supplemental Indenture, dated as of September 12, 2019,
among the Partnership, the guarantors party thereto and The Bank
of New York Mellon, as Trustee under the Indenture
Fourth Supplemental Indenture, dated as of November 5, 2020,
between the Partnership, the guarantors party thereto and The Bank
of New York Mellon, as Trustee under the Indenture
Description of the Registrant’s Securities Registered Pursuant to
Section 12 of the Securities Exchange Act of 1934
LNG Terminal Use Agreement, dated September 2, 2004, by and
between Total LNG USA, Inc. and SPLNG
Amendment of LNG Terminal Use Agreement, dated January 24,
2005, by and between Total LNG USA, Inc. and SPLNG
Amendment of LNG Terminal Use Agreement, dated June 15,
2010, by and between Total Gas & Power North America, Inc. and
SPLNG
Omnibus Agreement, dated September 2, 2004, by and between
Total LNG USA, Inc. and SPLNG
Parent Guarantee, dated as of November 5, 2004, by Total S.A. in
favor of SPLNG
Letter Agreement, dated September 11, 2012, between Total Gas
& Power North America, Inc. and SPLNG
LNG Terminal Use Agreement, dated November 8, 2004, between
Chevron U.S.A. Inc. and SPLNG
Amendment to LNG Terminal Use Agreement, dated December 1,
2005, by and between Chevron U.S.A. Inc. and SPLNG
Amendment of LNG Terminal Use Agreement, dated June 16,
2010, by and between Chevron U.S.A. Inc. and SPLNG
Omnibus Agreement, dated November 8, 2004, between Chevron
U.S.A. Inc. and SPLNG
Guaranty Agreement, dated as of December 15, 2004, from
ChevronTexaco Corporation to SPLNG
Second Amended and Restated LNG Terminal Use Agreement,
dated as of July 31, 2012, between SPL and SPLNG
115
Incorporated by Reference (1)
Entity
SPL
SPL
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Form Exhibit Filing Date
8-K
5/8/2020
4.1
8-K
8-K
8-K
8-K
4.1
4.1
4.1
4.1
5/8/2020
2/27/2017
2/27/2017
9/18/2017
8-K
4.2
9/18/2017
8-K
8-K
8-K
8-K
4.2
4.1
4.1
4.1
9/18/2017
9/12/2018
9/12/2018
9/12/2019
10-Q
4.1
11/6/2020
10-K
4.30
2/25/2020
10-Q
10.1
11/15/2004
Cheniere
10-K
10.40
3/10/2005
Cheniere
10-Q
10.2
8/6/2010
Cheniere
10-Q
10.2
11/15/2004
Cheniere
10-Q
10.3
11/15/2004
Cheniere
Partners
Cheniere
10-Q
10.1
11/2/2012
10-Q
10.4
11/15/2004
SPLNG
S-4
10.28
11/22/2006
Cheniere
10-Q
10.3
8/6/2010
Cheniere
10-Q
10.5
11/15/2004
SPLNG
S-4
10.12
11/22/2006
SPLNG
8-K
10.1
8/6/2012
Incorporated by Reference (1)
Entity
SPLNG
Form Exhibit Filing Date
10-Q
8/2/2013
10.1
SPLNG
8-K
10.2
8/6/2012
Cheniere
Partners
8-K
10.2
3/23/2020
Cheniere
Partners
8-K
10.1
3/23/2020
Cheniere
Partners
Cheniere
Partners
8-K
10.3
3/23/2020
8-K
10.1
6/3/2019
SPL
8-K
10.1
5/8/2020
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
8-K
10.3
3/26/2007
10-Q
10.9
11/2/2012
10-Q
10.8
11/2/2012
10-Q
10.7
11/2/2012
10-K
10.41
2/20/2015
10-K
10.42
2/20/2015
10-K
10.42
2/19/2016
8-K
10.1
11/9/2018
Cheniere
Partners
10-Q
10.4
8/8/2019
Exhibit
No.
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20†
10.21†
10.22†
10.23†
10.24†
10.25†
10.26†
10.27
10.28
Description
Letter Agreement, dated May 28, 2013, by and between SPL and
SPLNG
Guarantee Agreement, dated as of July 31, 2012, by the
Partnership in favor of SPLNG
Third Amended and Restated Common Terms Agreement, among
SPL, as borrower, the Secured Debt Holder Group Representatives
party thereto, the Secured Hedge Representatives party thereto, the
Secured Gas Hedge Representatives party thereto and Société
Générale, as the Common Security Trustee and the Intercreditor
Agent
Working Capital Revolving Credit
and Letter of Credit
Reimbursement Agreement, among SPL, as borrower, certain
subsidiaries of SPL, The Bank of Nova Scotia, as Senior Facility
Agent, Société Générale, as the Common Security Trustee, the
issuing banks and lenders from time to time party thereto and other
participants
Third Amended and Restated Accounts Agreement, among SPL,
certain subsidiaries of SPL, Société Générale, as the Common
Security Trustee, and Citibank, N.A. as the Accounts Bank
Credit and Guaranty Agreement, dated May 29, 2019, among the
Partnership, as Borrower, certain subsidiaries of the Partnership, as
Subsidiary Guarantors, the lenders from time to time party thereto,
Natixis, Société Générale, The Bank of Nova Scotia, Wells Fargo
Bank, as Issuing Banks, MUFG Bank, LTD as Administrative
Agent and Sole Coordinating Lead Arranger, and certain arrangers
and other participants
Registration Rights Agreement, dated as of May 8, 2020, between
SPL and Morgan Stanley & Co. LLC
Cheniere Energy Partners, L.P. 2007 Long-Term Incentive Plan
Form of Phantom Units Agreement under the Cheniere Energy
Partners, L.P. Long-Term Incentive Plan (2012 Reload Award)
Form of Phantom Units Agreement under the Cheniere Energy
Partners, L.P. Long-Term Incentive Plan
Form of Amendment to Phantom Units Agreement
Form of Phantom Units Agreement under the Cheniere Energy
Partners, L.P. Long-Term Incentive Plan (Units Settlement)
Form of Phantom Units Agreement under the Cheniere Energy
Partners, L.P. Long-Term Incentive Plan (Reload Units Settlement)
Form of Indemnification Agreement for officers and/or directors of
Cheniere Partners GP
Lump Sum Turnkey Agreement for the Engineering, Procurement
and Construction of the Sabine Pass LNG Stage 4 Liquefaction
Facility, dated November 7, 2018, by and between SPL 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.)
Change order to the Lump Sum Turnkey Agreement for the
Engineering, Procurement and Construction of the Sabine Pass
LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by
and between SPL and Bechtel Oil Gas and Chemicals, Inc.: the
Change Order CO-00001 Modifications to Insurance Language
Change Order, dated June 3, 2019
116
Exhibit
No.
10.29
10.30
10.31
10.32
(vii)
Description
Change order to the Lump Sum Turnkey Agreement for the
Engineering, Procurement and Construction of the Sabine Pass
LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by
and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the
Change Order CO-00002 Fuel Provisional Sum Closure, dated July
8, 2019, (ii) the Change Order CO-00003 Currency Provisional
Sum Closure, dated July 8, 2019, (iii) the Change Order CO-00004
Foreign Trade Zone, dated July 2, 2019, (iv) the Change Order
CO-00005 NGPL Gate Access Security Coordination Provisional
Sum, dated July 17, 2019, (v) the Change Order CO-00006
Alternate to Adams Valves, dated August 14, 2019, (vi) the
Change Order CO-00007 E-1503 to HRU Permanent Drain Piping,
dated August 14, 2019,
the Change Order CO-00008
Differing Subsurface Soil Conditions - Train 6 ISBL, dated August
27, 2019, (viii) the Change Order CO-00009 LNG Berth 3, dated
September 25, 2019 and (iv) the Change Order CO-00010 Cold
Box Redesign and Addition of Inspection Boxes on Methane Cold
Box, dated September 16, 2019
Change order to the Lump Sum Turnkey Agreement for the
Engineering, Procurement and Construction of the Sabine Pass
LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by
and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the
Change Order CO-00011 Insurance Provisional Sum Interim
Adjustment, dated October 1, 2019 and (ii) the Change Order
CO-00012 Replacement of Timber Piles with Pre-Stressed
Concrete Piles, dated October 30, 2019
Change order to the Lump Sum Turnkey Agreement for the
Engineering, Procurement and Construction of the Sabine Pass
LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by
and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the
Change Order CO-00013 Cost to Comply with SPL FTZ (FTZ
entries, bonded transports and receipts for AG Pipe Spools Only),
the Change Order CO-00014
dated February 10, 2020,
Permanent Access Road to Third Berth, dated February 10, 2020,
(iii) the Change Order CO-00015 Modifications to Schedule Bonus
Language, dated February 10, 2020,
the Change Order
CO-00016 LNG Berth 3 LNTP No 3, dated January 31, 2020 and
(v) the Change Order CO-00017 Construction Doc Fender Guards
and LP Fuel Gas Overpressure Interlock, dated March 18, 2020
Change order to the Lump Sum Turnkey Agreement for the
Engineering, Procurement and Construction of the Sabine Pass
LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by
and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the
Change Order CO-00018 Electrical Studies
for GTG Grid
Modification, dated April 2, 2020,
the Change Order
CO-00019 Third Berth - Change in 5kV Electrical Tie-In, dated
April 30, 2020, (iii) the Change Order CO-00020 LNG Berth 3
LNTP No. 4, dated May 4, 2020, (iv) the Change Order CO-00021
Train 6 P1601 A/B/ Flange Changes, dated May 27, 2020 and (v)
the Change Order CO-00022 Train 6 H2S Skid Modifications to
Level Transmitters & GTG Pressure Range Change on PT-573 A/
B, dated June 4, 2020
(iv)
(ii)
(ii)
Incorporated by Reference (1)
Entity
Cheniere
Partners
Form Exhibit Filing Date
11/1/2019
10-Q
10.2
Cheniere
Partners
10-K
10.34
2/25/2020
Cheniere
Partners
10-Q
10.4
4/30/2020
Cheniere
Partners
10-Q
10.2
8/6/2020
117
Exhibit
No.
10.33
10.34*
10.35
10.36
10.37
10.38
10.39
10.40
10.41
10.42
10.43
Description
Change order to the Lump Sum Turnkey Agreement for the
Engineering, Procurement and Construction of the Sabine Pass
LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by
and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the
Change Order CO-00023 Third Berth Vapor Fence Provisional
Sum Scope Removal and Closeout, dated June 22, 2020, (ii) the
Change Order CO-00024 Train 6 Thermowell Upgrades, dated
June 22, 2020, (iii) the Change Order CO-00025 Third Berth
Bubble Curtain, dated June 22, 2020, (iv) the Change Order
CO-00026 Third Berth Fuel Provisional Sum Closure Change
Order, dated July 14, 2020, (v) the Change Order CO-00027 Third
Berth Currency Provisional Sum Closure Change Order, dated July
20, 2020, (vi) the Change Order CO-00028 Train 6 Hot Oil
WHRU PSV Bypass, dated August 11, 2020 and (vii) the Change
Order CO-00029 Change in Law IMO 2020 Regulatory Change –
Low Sulphur Emissions on Marine Vessels, dated August 25, 2020
Change order to the Lump Sum Turnkey Agreement for the
Engineering, Procurement and Construction of the Sabine Pass
LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by
and between the SPL and Bechtel Oil Gas and Chemicals, Inc.: (i)
the Change Order CO-00030 Third Berth Soil Preparation
Provisional Sum Interim Adjustment Change Order, dated
September 16, 2020, (ii) the Change Order CO-00031 Provisional
Sum Consolidation (PAB, Taxes & Insurance), dated October 2,
2020, (iii) the Change Order CO-00032 COVID-19 Impacts, dated
October 2, 2020, (iv) the Change Order CO-00033 Third Berth -
Jetty Building (00A-4041) - Clean Agent System, dated November
2, 2020 and (v) the Change Order CO-00034 Vanessa Spare
Valves, dated November 18, 2020
LNG Sale and Purchase Agreement (FOB), dated November 21,
2011, between SPL (Seller) and Gas Natural Aprovisionamientos
SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG
GOM, Limited) (Buyer)
Amendment No. 1 of LNG Sale and Purchase Agreement (FOB),
dated April 3, 2013, between SPL (Seller) and Gas Natural
Aprovisionamientos SDG S.A. (subsequently assigned to Gas
Natural Fenosa LNG GOM, Limited) (Buyer)
Amendment of LNG Sale and Purchase Agreement (FOB), dated
January 12, 2017, between SPL (Seller) and Gas Natural Fenosa
LNG GOM, Limited (assignee of Gas Natural Aprovisionamientos
SDG S.A.) (Buyer)
LNG Sale and Purchase Agreement (FOB), dated December 11,
2011, between SPL (Seller) and GAIL (India) Limited (Buyer)
Amendment No. 1 of LNG Sale and Purchase Agreement (FOB),
dated February 18, 2013, between SPL (Seller) and GAIL (India)
Limited (Buyer)
Amended and Restated LNG Sale and Purchase Agreement (FOB),
dated January 25, 2012, between SPL (Seller) and BG Gulf Coast
LNG, LLC (Buyer)
LNG Sale and Purchase Agreement (FOB), dated January 30,
2012, between SPL (Seller) and Korea Gas Corporation (Buyer)
Amendment No. 1 of LNG Sale and Purchase Agreement (FOB),
dated February 18, 2013, between SPL (Seller) and Korea Gas
Corporation (Buyer)
Amended and Restated LNG Sale and Purchase Agreement (FOB),
dated August 5, 2014, between SPL (Seller) and Cheniere
Marketing, LLC (Buyer)
118
Incorporated by Reference (1)
Entity
Cheniere
Partners
Form Exhibit Filing Date
11/6/2020
10-Q
10.1
Cheniere
Partners
Cheniere
Partners
SPL
(SEC File No.
333-215882)
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
8-K
10.1
11/21/2011
10-Q
10.1
5/3/2013
S-4
10.3
2/3/2017
8-K
10.1
12/12/2011
10-K
10.18
2/22/2013
8-K
10.1
1/26/2012
8-K
10.1
1/30/2012
10-K
10.19
2/22/2013
SPL
8-K
10.1
8/11/2014
Exhibit
No.
10.44
10.45
10.46
10.47*
10.48
10.49
10.50
10.51
10.52
10.53
10.54
10.55
10.56
10.57
10.58
10.59
10.60
10.61
Description
Letter agreement, dated December 8, 2016, amending the
Amended and Restated LNG Sale and Purchase Agreement (FOB),
dated August 5, 2014, between SPL and Cheniere Marketing
International LLP (as assignee of Cheniere Marketing, LLC)
Amendment No. 1 of Amended and Restated LNG Sale and
Purchase Agreement, dated May 3, 2019, by and between SPL and
Cheniere Marketing International LLP
regarding the
Letter Agreement, dated December 9, 2020,
Amended and Restated LNG Sale and Purchase Agreement (FOB),
dated August 5, 2014, between SPL and Cheniere Marketing
International LLP (as assignee of Cheniere Marketing, LLC).
Letter Agreement, dated February 23, 2021,
regarding the
Amended and Restated LNG Sale and Purchase Agreement (FOB),
dated August 5, 2014, between SPL and Cheniere Marketing
International LLP (as assignee of Cheniere Marketing, LLC)
Management Services Agreement, dated May 14, 2012, by and
between Cheniere Terminals and SPL
Amendment to Management Services Agreement, dated September
28, 2015, between Cheniere Terminals and SPL
Amended and Restated Management Services Agreement, dated as
of August 9, 2012, by and between Cheniere Terminals and
SPLNG
Management Services Agreement, dated May 27, 2013, by and
between Cheniere Terminals and CTPL
Operation and Maintenance Agreement (Sabine Pass Liquefaction
Facilities), dated May 14, 2012, by and between Cheniere LNG
O&M Services, LLC, Cheniere Partners GP and SPL
Assignment and Assumption Agreement (Sabine Pass Liquefaction
O&M Agreement), dated as of November 20, 2013, by and
between Cheniere Partners GP and Cheniere Investments
Amendment to Operation and Maintenance Agreement (Sabine
Pass Liquefaction Facilities), dated September 28, 2015, by and
among Cheniere LNG O&M Services, LLC, Cheniere Investments
and SPL
Amended and Restated Operation and Maintenance Agreement
(Sabine Pass LNG Facilities), dated as of August 9, 2012, by and
among Cheniere Partners GP, Cheniere LNG O&M Services, LLC,
and SPLNG
Assignment and Assumption Agreement (Sabine Pass LNG O&M
Agreement), dated as of November 20, 2013, by and between
Cheniere Partners GP and Cheniere Investments
Amended and Restated Management and Administrative Services
Agreement, dated as of August 9, 2012, by and between Cheniere
Terminals, the Partnership and Cheniere
Amended and Restated Operation and Maintenance Services
Agreement (Cheniere Creole Trail Pipeline), dated May 27, 2013,
by and between CTPL and Cheniere Partners GP
Assignment and Assumption Agreement
(Creole Trail O&M
Agreement), dated as of November 20, 2013, between Cheniere
Partners GP and Cheniere Investments
Cooperative Endeavor Agreement & Payment
in Lieu of Tax
Agreement with eleven Cameron Parish taxing authorities, dated
October 23, 2007, by and between Cheniere Marketing, Inc. and
SPLNG
Amended and Restated Services and Secondment Agreement,
dated as of August 9, 2012, between Cheniere LNG O&M
Services, LLC and Cheniere Partners GP
119
Incorporated by Reference (1)
Entity
SPL
Form Exhibit Filing Date
2/24/2017
10-K
10.14
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
SPL
Cheniere
Partners
Cheniere
Partners
Cheniere
Partners
Cheniere
Holdings
10-Q
10.1
5/9/2019
8-K
10.1
12/9/2020
8-K
10.6
5/15/2012
10-Q/A 10.8
11/9/2015
10-Q
10.6
11/2/2012
10-Q
10.2
8/2/2013
8-K
10.5
5/15/2012
S-1/A 10.76
12/2/2013
SPL
10-Q/A 10.7
11/9/2015
Cheniere
Partners
Cheniere
Holdings
Cheniere
Partners
Cheniere
Partners
Cheniere
Holdings
10-Q
10.5
11/2/2012
S-1/A 10.75
12/2/2013
10-Q
10.4
11/2/2012
10-Q
10.1
8/2/2013
S-1/A 10.74
12/2/2013
Cheniere
10-Q
10.7
11/6/2007
Cheniere
Partners
10-Q
10.3
11/2/2012
Incorporated by Reference (1)
Entity
Cheniere
Holdings
Cheniere
Partners
Form Exhibit Filing Date
12/2/2013
S-1/A 10.73
8-K
10.1
8/6/2012
Cheniere
Partners
10-Q
22.1
8/6/2020
Exhibit
No.
10.62
10.63
21.1*
22.1
23.1*
31.1*
31.2*
32.1**
32.2**
Description
(Services
and Assumption Agreement
Assignment
and
Secondment Agreement), dated as of November 20, 2013, by and
between Cheniere Partners GP and Cheniere Investments
Investors’ and Registration Rights Agreement, dated as of July 31,
2012, by and among Cheniere, Cheniere Partners GP,
the
Partnership, Cheniere Class B Units Holdings, LLC, Blackstone
CQP Holdco LP and the other investors party thereto from time to
time
Subsidiaries of the Partnership
List of Issuers and Guarantor Subsidiaries
required by Rule
Consent of KPMG LLP
Certification by Chief Executive Officer
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* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Labels Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
104*
Cover Page Interactive Data File (formatted as Inline XBRL and
contained in Exhibit 101)
(1)
*
**
†
Exhibits are incorporated by reference to reports of Cheniere (SEC File No. 001-16383), Cheniere Partners (SEC
File No. 001-33366), Cheniere Holdings (SEC File No. 333-191298), SPL (SEC File No. 333-192373) and SPLNG
(SEC File No. 333-138916), as applicable, unless otherwise indicated.
Filed herewith.
Furnished herewith.
Management contract or compensatory plan or arrangement.
120
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY PARTNERS, L.P.
CONDENSED STATEMENTS OF INCOME
(in millions)
Operating costs and expenses
General and administrative expense
General and administrative expense—affiliate
Depreciation and amortization expense
Total operating costs and expenses
Other income
Interest expense, net of capitalized interest
Loss on modification or extinguishment of debt
Derivative gain, net
Other income
Equity income of affiliates
Total other income
Year Ended December 31,
2019
2018
2020
$
$
3
14
3
20
$
3
13
3
19
(217)
—
—
7
1,413
1,203
(174)
(13)
—
21
1,360
1,194
4
12
2
18
(139)
(12)
14
13
1,416
1,292
Net income
$
1,183
$
1,175
$
1,274
The accompanying notes are an integral part of these condensed financial statements.
121
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY PARTNERS, L.P.
CONDENSED BALANCE SHEETS
(in millions)
ASSETS
Current assets
Cash and cash equivalents
Other current assets
Total current assets
Property, plant and equipment, net
Debt issuance costs, net
Investment in affiliates
Total assets
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accrued liabilities
Due to affiliates
Total current liabilities
Long-term debt, net
Partners’ equity
Total liabilities and partners’ equity
December 31,
2020
2019
$
$
$
$
$
$
$
1,208
1
1,209
79
7
3,359
4,654
52
3
55
4,060
539
4,654
$
1,778
—
1,778
79
9
2,963
4,829
56
3
59
4,055
715
4,829
The accompanying notes are an integral part of these condensed financial statements.
122
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY PARTNERS, L.P.
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
Cash flows provided by operating activities
Cash flows from investing activities
Property, plant and equipment, net
Investments in subsidiaries
Distributions received from affiliates
Net cash provided by (used in) investing activities
Cash flows from financing activities
Proceeds from issuance of debt
Repayments of debt
Debt issuance and deferred financing costs
Debt extinguishment costs
Distributions to owners
Other
Net cash provided by (used in) financing activities
Year Ended December 31,
2019
2018
2020
$
1,190
$
1,220
$
714
(3)
(689)
291
(401)
—
—
—
—
(1,359)
—
(1,359)
(2)
(1,273)
853
(422)
2,230
(730)
(35)
—
(1,260)
(4)
201
—
(304)
454
150
1,100
(1,090)
(8)
(7)
(1,113)
—
(1,118)
(254)
1,033
779
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash—beginning of period
Cash and cash equivalents—end of period
(570)
1,778
1,208
$
999
779
1,778
$
$
The accompanying notes are an integral part of these condensed financial statements.
123
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY PARTNERS, L.P.
NOTES TO CONDENSED FINANCIAL STATEMENTS
NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Condensed Financial Statements represent
Commission Regulation S-X 5-04 for Cheniere Partners.
the financial
information required by Securities and Exchange
In the Condensed Financial Statements, Cheniere Partners’ investments in affiliates are presented at the net amount
attributable to Cheniere Partners. Under this method, the assets and liabilities of affiliates are not consolidated. The
investments in net assets of the affiliates are recorded on the Condensed Balance Sheets. The gain from operations of the
affiliates is reported on a net basis as equity income of affiliates.
A substantial amount of Cheniere Partners’ operating, investing and financing activities are conducted by its affiliates.
The Condensed Financial Statements should be read in conjunction with Cheniere Partners’ Consolidated Financial Statements.
Recent Accounting Standards
In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)
2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.
This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to
existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional
expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have
not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified
contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until
December 31, 2022, at which time the optional expedients are no longer available.
NOTE 2—DEBT
As of December 31, 2020 and 2019, our debt consisted of the following (in millions):
Long-term debt:
4.500% to 5.625% senior notes due between 2025 and 2029 and credit facilities (“2019
CQP Credit Facilities”)
Unamortized debt issuance costs
Total long-term debt, net
$
$
4,100
(40)
4,060
$
$
4,100
(45)
4,055
December 31,
2020
2019
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31,
2020 (in millions):
Years Ending December 31,
2021
2022
2023
2024
2025
Thereafter
Total
Principal Payments
—
—
—
—
1,500
2,600
4,100,
$
$
124
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY PARTNERS, L.P.
NOTES TO CONDENSED FINANCIAL STATEMENTS—CONTINUED
NOTE 3—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in millions):
Cash paid during the period for interest, net of amounts capitalized
Non-cash capital distributions (1)
(1)
Amounts represent equity income of affiliates.
Year Ended December 31,
2020
2019
2018
$
$
213
1,413
$
151
1,360
115
1,416
125
ITEM 16.
FORM 10-K SUMMARY
None.
126
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.
By: Cheniere Energy Partners GP, LLC,
its general partner
By:
Date:
/s/ Jack A. Fusco
Jack A. Fusco
President and Chief Executive Officer
(Principal Executive Officer)
February 23, 2021
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/ Jack A. Fusco
Jack A. Fusco
/s/ Zach Davis
Zach Davis
/s/ Leonard E. Travis
Leonard E. Travis
/s/ James R. Ball
James R. Ball
/s/ Eric Bensuade
Eric Bensuade
/s/ Wallace C. Henderson
Wallace C. Henderson
/s/ Lon McCain
Lon McCain
/s/ Mark Murski
Mark Murski
/s/ Vincent Pagano Jr.
Vincent Pagano Jr.
g
/s/ Scott Peak
Scott Peak
/s/ Oliver G. Richard, III
Oliver G. Richard, III
/s/ Aaron Stephenson
Aaron Stephenson
p
President and Chief Executive Officer, Chairman of the Board
(Principal Executive Officer)
February 23, 2021
Senior Vice President and Chief Financial Officer, Director
(Principal Financial Officer)
February 23, 2021
February 23, 2021
February 23, 2021
February 23, 2021
February 23, 2021
February 23, 2021
February 23, 2021
February 23, 2021
February 23, 2021
February 23, 2021
February 23, 2021
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
127
APPENDIX
Adjusted EBITDA
The following table reconciles our Adjusted EBITDA to U.S. GAAP results for 2020 (in millions):
Net income
Interest expense, net of capitalized interest
Loss on modification or extinguishment of debt
Other income, net
Other income—affiliate
Income from operations
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense
Loss from changes in fair value of commodity derivatives, net
Impairment expense and loss on disposal of assets
Incremental costs associated with COVID-19 response
Adjusted EBITDA
2020
1,183
909
43
(8)
(2)
2,125
551
45
5
36
2,762
$
$
$
Board of Directors
Jack A. Fusco
Chairman of the Board and
President and Chief Executive Officer
James R. Ball
Independent Director
Eric Bensaude
Director
Zach Davis
Director and Senior Vice President and
Chief Financial Officer
Senior Management
Jack A. Fusco
President and Chief Executive Officer
Anatol Feygin
Executive Vice President and
Chief Commercial Officer
Sean N. Markowitz
Executive Vice President, Chief Legal Officer
and Corporate Secretary
Wallace C. Henderson
Director
Lon McCain
Independent Director
Mark Murski
Director
Vincent Pagano, Jr.
Independent Director
Scott Peak
Director
Oliver G. Richard, III
Independent Director
Aaron Stephenson
Director and Senior Vice President, Operations
Zach Davis
Senior Vice President and
Chief Financial Officer
Christopher Smith
Senior Vice President, Policy, Government,
and Public Affairs
David Craft
Senior Vice President, Engineering
and Construction
Scott Culberson
Senior Vice President, Gas Supply
Aaron Stephenson
Senior Vice President, Operations
Len Travis
Senior Vice President and Chief Accounting Officer
Hilary Ware
Chief Human Resources Officer
Corey Grindal
Executive Vice President, Worldwide Trading
Michael Dove
Senior Vice President, Shared Services
Officers
Randy Bhatia
Vice President, Investor Relations
Eben Burnham-Snyder
Vice President, Public Affairs
Khary Cauthen
Vice President, Federal Government Affairs
Rina Chang
Vice President, Environmental
Lisa Cohen
Vice President and Treasurer
Robin Dane
Chief Risk Officer
Contacts & Advisors
Tony Eaton
Vice President, Project Development
and Execution
William L. Knittle
Vice President, Supply Chain Management
Scott Mills
Vice President, Mid Office
Tom Myers
Vice President, Health and Safety
Julie Nelson
Vice President, State Government Affairs
Deanna L. Newcomb
Chief Compliance and Ethics Officer,
Vice President, Internal Audit
Florian Pintgen
Vice President, Commercial Operations
Mitch Price
Vice President and Chief Security Risk Officer
Brandon Smith
Vice President and Chief Information Officer
Tim Wyatt
Vice President, Business Development and Strategy
Sean Bunk
Assistant Corporate Secretary
Omer Chadha
Director, Tax
Corporate Office
Cheniere Energy Partners, LP
700 Milam, Suite 1900, Houston, TX 77002
Tel: (713) 375-5000 | Fax: (713) 375-6000
Transfer Agent
Computershare Trust Company, N.A.
P.O. Box 43078, Providence, RI 02940-3078
Tel: (800) 962-4284 | Fax: (303) 262-0600
Stock Exchange Listing
NYSE American: CQP
Independent Accountants
KPMG LLP, Houston, TX
Investor Relations
Tel: (713) 375-5100
Email: investor@cheniere.com
Website
www.cheniere.com
CHENIERE ENERGY PARTNERS, L.P. ANNUAL REPORT
Cheniere Energy Partners, L.P. provides clean, secure, and affordable LNG to the world.
We conduct our business safely and responsibly, delivering a reliable, competitive,
and integrated source of LNG to our customers.
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www.cheniere.com