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, 2021
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.
(Exact name of registrant as specified in its charter)
| Delaware | 20-5913059 | ||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||
700 Milam Street, Suite 1900
Houston, Texas 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 | Trading Symbol | Name of each exchange on which registered | ||||||
| Common Units Representing Limited Partner Interests | CQP | 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 | ☒ | Accelerated filer | ☐ | ||||||||||||||
| Non-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 $10.8 billion as of June 30, 2020.
As of February 18, 2022, the registrant had 484,027,123 common units outstanding.
Documents incorporated by reference: None
CHENIERE ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
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DEFINITIONS
As used in this annual report, the terms listed below have the following meanings:
Common Industry and Other Terms
| Bcf | billion cubic feet | |||||||
| Bcf/d | billion cubic feet per day | |||||||
| Bcf/yr | billion cubic feet per year | |||||||
| Bcfe | billion cubic feet equivalent | |||||||
| DOE | U.S. Department of Energy | |||||||
| EPC | engineering, procurement and construction | |||||||
| FERC | Federal Energy Regulatory Commission | |||||||
| FTA countries | countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas | |||||||
| GAAP | generally accepted accounting principles in the United States | |||||||
| Henry Hub | the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin | |||||||
| LIBOR | London Interbank Offered Rate | |||||||
| LNG | liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state | |||||||
| MMBtu | million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit | |||||||
| mtpa | million tonnes per annum | |||||||
| non-FTA countries | countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted | |||||||
| SEC | U.S. Securities and Exchange Commission | |||||||
| SPA | LNG sale and purchase agreement | |||||||
| TBtu | trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit | |||||||
| Train | an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG | |||||||
| TUA | terminal use agreement | |||||||
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Abbreviated Legal Entity Structure
The following diagram depicts our abbreviated legal entity structure as of December 31, 2021, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:
Unless the context requires otherwise, references to “CQP,” “the Partnership,” “we,” “us” and “our” refer to Cheniere Energy Partners, L.P. and its consolidated subsidiaries, including SPLNG, SPL and CTPL.
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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 regarding our future sources of liquidity and cash requirements;
•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 COVID-19 pandemic and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing creditworthiness 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
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “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
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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements 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.
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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
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.
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 natural gas liquefaction and export facility at Sabine Pass, Louisiana (the “Sabine Pass LNG terminal”), one of the largest LNG production facilities in the world, is located in Cameron Parish, Louisiana, and has natural gas liquefaction facilities consisting of six operational Trains, with Train 6 which achieved substantial completion on February 4, 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG terminal also has operational regasification facilities that include 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 (the “Creole Trail Pipeline”).
Our customer arrangements provide us with significant, stable and long-term cash flows. As further discussed below, we contract our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, We have contracted approximately 75% of the total production capacity from the Liquefaction Project through long-term SPAs, with approximately 16 years of weighted average remaining life as of December 31, 2021, 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. For further discussion of the contracted future cash flows under our revenue arrangements, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.
We remain focused on operational excellence and customer satisfaction. Increasing demand for 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 a significant land position at the Sabine Pass LNG terminal, which provides 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”).
Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. Cheniere published its 2020 Corporate Responsibility (“CR”) report, which details our strategy and progress on ESG issues, as well as our efforts on integrating climate considerations into our business strategy and taking a leadership position on increased environmental transparency, including conducting a climate scenario analysis and our plan to provide LNG customers with Cargo Emission Tags. In August 2021, Cheniere also announced a peer-reviewed LNG life cycle assessment study which allows for improved greenhouse gas emissions assessment, which was published in the American Chemical Society Sustainable Chemistry & Engineering Journal. Cheniere’s CR report is
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available at cheniere.com/IMPACT. Information on our website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K.
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 third party long-term SPA customers as of December 31, 2021;
•maximizing the production of LNG to serve our customers and generating steady and stable revenues and operating cash flows;
•optimizing the Liquefaction Project by leveraging existing infrastructure;
•maintaining a prudent and cost-effective capital structure; and
•strategically identifying actionable environmental solutions.
Our Business
Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.
Liquefaction Facilities
The Liquefaction Project is one of the largest LNG production facilities in the world. We operate six Trains, including Train 6 which achieved substantial completion on February 4, 2022, and two marine berths, and are constructing a third marine berth. The SPL Project has a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the EPC of Train 6. The following table summarizes the project completion and construction status of Train 6 of the Liquefaction Project as of December 31, 2021:
| Train 6 | |||||||||||
| Overall project completion percentage | 99.5% | ||||||||||
| Completion percentage of: | |||||||||||
| Engineering | 100.0% | ||||||||||
| Procurement | 100.0% | ||||||||||
| Subcontract work | 99.6% | ||||||||||
| Construction | 98.8% | ||||||||||
| Date of substantial completion | February 4, 2022 | ||||||||||
The following summarizes the volumes of natural gas for which we have received approvals from FERC to site, construct and operate the Liquefaction Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal through December 31, 2050:
| FERC Approved Volume | DOE Approved Volume | ||||||||||||||||||||||
| (in Bcf/yr) | (in mtpa) | (in Bcf/yr) | (in mtpa) | ||||||||||||||||||||
| FTA countries | 1,661.94 | 33 | 1,661.94 | 33 | |||||||||||||||||||
| Non-FTA countries | 1,661.94 | 33 | 1,509.3 (1) | 30 | |||||||||||||||||||
(1)The authorization for an additional 152.64 Bcf/yr (approximately 3 mtpa) of natural gas is currently pending.
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Natural Gas Supply, Transportation and Storage
SPL has secured natural gas feedstock for the Sabine Pass LNG terminal through long-term natural gas supply agreements. Additionally, to ensure that SPL is able to transport natural gas feedstock to the Sabine Pass LNG terminal and manage inventory levels, it has entered into transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third-parties.
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. SPLNG has entered into two long-term, third party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the approximately 2 Bcf/d of aggregate capacity they have reserved at the Sabine Pass LNG terminal. The remaining approximately 2 Bcf/d of capacity has been reserved under a TUA by SPL.
Customers
Information regarding our customer contracts can be found in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.
The following table shows customers with revenues of 10% or greater of total revenues from external customers:
| Percentage of Total Revenues from External Customers | |||||||||||||||||
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
BG Gulf Coast LNG, LLC | 24% | 24% | 27% | ||||||||||||||
GAIL (India) Limited | 17% | 18% | 20% | ||||||||||||||
Korea Gas Corporation | 17% | 17% | 19% | ||||||||||||||
Naturgy LNG GOM, Limited | 16% | 15% | 18% | ||||||||||||||
TotalEnergies Gas & Power North America, Inc. | 11% | 11% | * | ||||||||||||||
* Less than 10%
All of the above customers contribute to our LNG revenues through SPA contracts.
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 rigorous 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.
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;
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•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. On February 18, 2022, FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for FERC’s decision-making process, which would now include, among other things, reasonably foreseeable greenhouse gas emissions that may be attributable to the project and the project’s impact on environmental justice communities. These FERC changes are the first revision in more than 20 years to FERC’s policy for the certification of new interstate natural gas pipeline projects under Section 7 of the NGA. The updated Policy Statement has more limited applicability to LNG projects regulated under Section 3 of the Natural Gas Act. While the impact on our future projects and expansions is not known at this time, we do not expect it to have a material adverse effect on our operations.
We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate granted by the FERC with the issuance of our Certificate of Public Convenience and Necessity 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 its final Order Granting Section 3 Authority (“Order”) in April 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, in May 2012, 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 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. FERC issued written approval to commence site preparation work for the third berth in June 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, is required prior to making any modifications
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to the Creole Trail Pipeline as it is a regulated, interstate natural gas pipeline. In February 2013, the FERC approved CTPL’s application for authorization to construct, own, operate and maintain certain new facilities in order to enable bi-directional natural gas flow on the Creole Trail Pipeline system to allow for the delivery of up to 1,530,000 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 construction was completed in 2015. In September 2013, as part of the Application for Trains 5 and 6, 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 DOE issued Orders granting authorization to export LNG to FTA countries in April 2020. The DOE authorization for export to non-FTA countries is still pending. In October 2021, the FERC issued its Orders Amending Authorization under Section 3 of the NGA.
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.
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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 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.
PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $225,000 per day per violation, with a maximum administrative civil penalty of approximately $2.25 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, 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 EPA administers the Clean Air Act (“CAA”), 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. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, including the speculative position limit rules which became effective on March 15, 2021 and have a phased-in compliance date that began on January 1, 2022. Given the recent enactment of the speculative position limit rules, as well as the impact of other rules and regulations under the Dodd-Frank Act, the impact of such rules and regulations on our business continues to be uncertain.
As required by the Dodd-Frank Act, the CFTC and federal banking regulators also adopted rules requiring 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 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 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.
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Clean Air Act
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 include reporting 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 November 15, 2021, the EPA proposed new regulations to reduce methane emissions from both new and existing sources within the Crude Oil and Natural Gas source category. The proposed regulations if finalized, would result in more stringent requirements for new sources, expand the types of new sources covered, and for the first time, establish emissions guidelines for existing sources in the Crude Oil and Natural Gas source category. 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, the imposition of taxes or fees related to GHG emissions 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). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.
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.
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Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act, the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened 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.
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
Market Factors
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 natural gas, economic growth in developing countries and other related factors such as the effects of the COVID-19 pandemic. In addition, Cheniere’s ability to obtain additional funding to 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, significant amounts of money are being invested across Europe and Asia in natural gas projects under construction, and more continues to be earmarked to planned projects globally. Some examples include India’s commitment to invest over $60 billion to usher a gas-based economy, around $100 billion earmarked for Europe’s gas infrastructure buildout, 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 number of markets to approximately 60 by 2030 from 43 in 2020 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 20 trillion cubic feet (“Tcf”) between 2020 and 2030 and 33 Tcf between 2020 and 2040. LNG’s share is seen growing from about 11% in 2020 to about 12% of the global gas market in 2030 and 14% in 2040. Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 57%, from 366.6 mtpa, or 17.6 Tcf, in 2020, to 576.5 mtpa, or 27.7 Tcf, in 2030 and to 734.5 mtpa or 35.3 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 517 mtpa in 2030, declining to 456 mtpa in 2040. This could result in a market need for construction of an additional approximately 60 mtpa of LNG production by 2030 and about 279 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 Projects 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 oil price movements 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 through long-term SPAs, with approximately 16 years of weighted average remaining life as of December 31, 2021, 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.
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Competition
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, including our affiliate Corpus Christi Liquefaction, LLC (“CCL”), which operates three Trains at a natural gas liquefaction facility near Corpus Christi, Texas. Revenues associated with any incremental volumes of the Liquefaction Project, including those under the Cheniere Marketing SPA, 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 LNG markets than us.
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.
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, 2022, Cheniere and its subsidiaries had 1,550 full-time employees, including 513 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.
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.
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ITEM 1A. RISK FACTORS
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
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, 2021, we had $0.9 billion of cash and cash equivalents, $0.1 billion of restricted cash and cash equivalents, a total of $1.6 billion of available commitments under our credit facilities and $17.3 billion of total debt outstanding on a consolidated basis (before unamortized premium, discount and debt issuance costs). SPL and CQP operate with independent capital structures as further detailed in Note 11—Debt of our Notes to Consolidated Financial Statements. We incur, and will incur, significant interest expense relating to the assets at the Sabine Pass LNG terminal. Our ability to 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.
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, 2021, we had SPAs with terms of 10 or more years with a total of eight different third party customers. In addition, SPLNG had TUAs with two third party customers.
While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.
Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs upon the occurrence of certain
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events of force majeure. Under each of SPLNG’s long-term TUAs, such termination events include, but are not limited to: if the Sabine Pass LNG terminal (1) experiences a force majeure delay for longer than 18 months; (2) fails to redeliver a specified amount of natural gas in accordance with the customer’s redelivery nominations; or (3) fails to accept and unload a specified number of the customer’s proposed LNG cargoes.
Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.
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 subsidiaries’ 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 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.
Our subsidiaries’ inability to pay distributions to us or to incur additional indebtedness as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit our ability to pay or increase distributions to our unitholders, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Restrictions in agreements governing our subsidiaries’ indebtedness may prevent our subsidiaries from engaging in certain beneficial transactions, which could materially and adversely affect us.
In addition to restrictions on the ability of us and SPL to make distributions or incur additional indebtedness, the agreements governing their indebtedness also contain various other covenants that may prevent them from engaging in beneficial transactions, including limitations on their ability to:
•make certain investments;
•purchase, redeem or retire equity interests;
•issue preferred stock;
•sell or transfer assets;
•incur liens;
•enter into transactions with affiliates;
•consolidate, merge, sell or lease all or substantially all of its assets; and
•enter into sale and leaseback transactions.
Any restrictions on the ability to engage in beneficial transactions could materially and adversely affect us.
Risks Relating to Our Operations and Industry
Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the completion of our 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, Hurricanes Laura and Delta in 2020 and Winter Storm Uri in 2021 caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our facilities. 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
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December 31, 2021, eight 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 our other facilities 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.
Disruptions to the third party supply of natural gas to our pipeline and facilities 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 our 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, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted. Any significant disruption to our natural gas supply could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, 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.
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:
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
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•insufficient LNG tanker capacity;
•weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand. For example, LNG procurement in Japan rose dramatically in 2011 and several years thereafter following a tsunami that caused extensive destruction to its nuclear power infrastructure;
•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 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.
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.
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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.
We face competition based upon the international market price for LNG.
Our 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. 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 our Liquefaction Project are diverse and include, among others:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to our Liquefaction 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.
A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Project, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our pipeline, liquefaction and shipping operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third-parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Project. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should multiple of the third party pipelines which supply our Liquefaction Project suffer similar concurrent attacks, the Liquefaction Project may not be able to obtain sufficient
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natural gas to operate at full capacity, or at all. A cyber attack involving our business or operational control systems or related infrastructure, or that of third party pipelines with which we do business, could negatively impact our operations, result in data security breaches, impede the processing of transactions, or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
Outbreaks of infectious diseases, such as the outbreak of COVID-19, at our facilities could adversely affect our operations.
Our facilities at the Sabine Pass LNG terminal are critical infrastructure and have continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including the Delta and Omicron variants, has had no adverse impact on our on-going operations during this time, the risk of future variants is unknown. While we believe we can continue to mitigate any significant adverse impact to our employees and operations at our critical facilities related to the virus in its current form, the outbreak of a more potent variant in the future at one or more of our facilities could adversely affect our operations.
Risks Relating to Regulations
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 development and 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, our LNG terminal, including the Liquefaction Project, and other facilities, as well as 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.
To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the Liquefaction Project, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline. To date, the DOE has also issued orders under Section 4 of the NGA authorizing SPL to export domestically produced LNG. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipeline on land owned by third parties. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with such conditions, or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns, could impede the operation and construction of our infrastructure. 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. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our Creole Trail Pipeline and its FERC gas tariff are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.
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 our Creole Trail Pipeline must be just and reasonable, and we are 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, our Creole Trail Pipeline could be subject to substantial penalties and fines.
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In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we 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.
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.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of GHG emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting 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 November 15, 2021, the EPA proposed new regulations to reduce methane emissions from both new and existing sources within the Crude Oil and Natural Gas source category. The proposed regulations, if finalized, would result in more stringent requirements for new sources, expand the types of new sources covered, and for the first time, establish emissions guidelines for existing sources in the Crude Oil and Natural Gas source category. 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.
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Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.
The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
•perform ongoing assessments of pipeline safety and compliance;
•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventative and mitigating actions.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines, which for certain violations can aggregate up to as high as $2.3 million.
Risks Relating to Our Relationship with Our General Partner
We are entirely dependent on our general partner, 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, 2022, Cheniere and its subsidiaries had 1,550 full-time employees, including 513 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 our 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, remoteness of our site locations, or other general inflationary pressures, changes in applicable laws and regulations or labor disputes 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.
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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:
•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 refer to the risk factor “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, in some circumstances, is entitled to be indemnified by us;
•our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and
•our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
We also have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, SPL has also executed agreements with Cheniere Marketing to sell: (1) 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 and (2) up to 306 cargoes to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub. 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 three Trains 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 interconnection, natural gas balancing and storage agreements with one or more Cheniere-affiliated natural gas pipelines, services agreements, as well as other agreements and arrangements that cannot now be anticipated. In those circumstances
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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.
Risks Relating to an Investment in Us and Our Common Units
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:
•permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;
•provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner, as long as it acted in good faith, meaning that it believed the decision was in the best interests of our partnership;
•generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us;
•provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was criminal; and
•provides that in resolving conflicts of interest, it will be presumed that in making its decision the conflicts committee or the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units trade.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders 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.
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
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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.
Additionally, 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.
Any change of our general partner or the replacement of the board of directors or officers of our partnership, which can occur without the consent of our unitholders, can impact our future operations and have an adverse impact on the trading price of our stock.
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. Any change in our general partner or the replacement of the board of directors or officers of our partnership can impact our future operations and have an adverse impact on the trading price of our stock.
Our partnership agreement prohibits a unitholder (other than our general partner and its affiliates) who acquires 15% or more of our limited partner units without the approval of our general partner from engaging in a business combination with us for three years unless certain approvals are obtained. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.
Our partnership agreement effectively adopts Section 203 of the General Corporation Law of the State of Delaware (“DGCL”). Section 203 of the DGCL as it applies to us prevents an interested unitholder defined as a person (other than our general partner and its affiliates) who owns 15% or more of our outstanding limited partner units from engaging in business combinations with us for three years following the time such person becomes an interested unitholder unless certain approvals are obtained. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our partnership agreement could have an anti-takeover effect with respect to transactions not approved in advance by our general partner, including discouraging takeover attempts that might result in a premium over the market price for our common units.
Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for contractual obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware law, and we conduct business in other states. As a limited partner in a partnership organized under Delaware law, holders of our common units could be held liable for our obligations to the same extent as a general partner if a court determined that the right 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
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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.
Affiliates of our general partner or affiliates of Blackstone Inc. (“Blackstone”) or Brookfield Asset Management Inc. (“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, 2021, 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, and our not being subject to a material amount of entity-level taxation by individual states. If we were treated as a corporation for federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate 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.
At the state level, 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 such taxes on us in jurisdictions in which we operate, or to which we may expand our operations, 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 taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the initial quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. 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
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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 Internal Revenue Service (“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 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.
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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.
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, withholding may be required on the amount realized unless the disposing unitholder certifies that it is not a foreign person. 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 unitholder. 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. In Notice 2021-51, the IRS announced that it intends to amend the Treasury regulations to defer the applicability date for withholding on a transfer of an interest in a publicly traded partnership to January 1, 2023. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
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
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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.
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. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to SPL alleging violations of federal pipeline safety regulations relating to the 2018 SPL tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200. On October 12, 2021, SPL responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. PHMSA notified SPL in a letter dated November 9, 2021 that the case was considered “closed.” SPL continues 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 or resolution of the NOPV will have a material adverse impact on our financial results or operations.
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ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
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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 18, 2022, we had 484.0 million common units outstanding held by 10 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”)
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:
| Total Quarterly Distribution Target Amount | Marginal Percentage Interest Distributions | |||||||||||||||||||
| Common and Subordinated Unitholders | General Partner | |||||||||||||||||||
| Initial quarterly distribution | $0.425 | 98% | 2% | |||||||||||||||||
| First Target Distribution | Above $0.425 up to $0.489 | 98% | 2% | |||||||||||||||||
| Second Target Distribution | Above $0.489 up to $0.531 | 85% | 15% | |||||||||||||||||
| Third Target Distribution | Above $0.531 up to $0.638 | 75% | 25% | |||||||||||||||||
| Thereafter | Above $0.638 | 50% | 50% | |||||||||||||||||
ITEM 6. [Reserved]
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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. Discussion of 2019 items and variance drivers between the year ended December 31, 2020 as compared to December 31, 2019 are not included herein, and can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2020.
Our discussion and analysis includes the following subjects:
Overview
We are a limited partnership formed by Cheniere to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We operate a natural gas liquefaction and export facility at Sabine Pass, Louisiana (the “Sabine Pass LNG terminal”) with six operational natural gas liquefaction Trains, regasification facilities and a pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate natural gas pipelines (collectively, the “Liquefaction Project”). For further discussion of our business, see Items 1. and 2. Business and Properties.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted approximately 75% of the total production capacity from the Liquefaction Project with approximately 16 years of weighted average remaining life as of December 31, 2021. Our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases and transportation and liquefaction fuel to produce LNG, thus limiting our exposure to fluctuations in U.S. natural gas prices. We believe that continued global demand for natural gas and LNG, as further described in Items 1. and 2. Business and Properties—Market Factors and Competition, will provide a foundation for additional growth in our business in the future.
Overview of Significant Events
Our significant events since January 1, 2021 and through the filing date of this Form 10-K include the following:
Strategic
•In February 2022, Cheniere Marketing entered into agreements to novate to SPL SPAs entered into with ENN LNG (Singapore) Pte Ltd. and a subsidiary of Glencore plc, aggregating approximately 21 million tonnes of LNG to be delivered between 2023 and 2035, in connection with a prior commitment by Cheniere to collateralize financing for Train 6 of the Liquefaction Project.
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Operational
•As of February 18, 2022, over 1,550 cumulative LNG cargoes totaling approximately 110 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
•On February 4, 2022, substantial completion of Train 6 of the Liquefaction Project was achieved.
Financial
•In February 2022, we announced the initiation of quarterly distributions to be comprised of a base amount plus a variable amount, which are expected to begin with the distribution related to the first quarter of 2022. It is anticipated that the quarterly distribution with respect to the first quarter of 2022 will be comprised of a base amount equal to $0.775 ($3.10 annualized), and a variable amount equal to the remaining available cash per unit, which will take into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of the business.
•We completed the following debt transactions:
◦In December 2021, SPL issued Senior Secured Notes due 2037 on a private placement basis for an aggregate principal amount of approximately $482 million (the “2037 SPL Private Placement Senior Secured Notes”). The 2037 SPL Private Placement Senior Secured Notes are fully amortizing, with a weighted average life of over 10 years and a weighted average interest rate of 3.07%.
◦In September 2021, we issued an aggregate principal amount of $1.2 billion of 3.25% Senior Notes due 2032 (the “2032 CQP Senior Notes”).
◦The proceeds, net of related fees, costs and expenses (“net proceeds”) of the 2032 CQP Senior Notes were used to redeem a portion of the outstanding $1.1 billion aggregate principal amount of the 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”). The remaining net proceeds of the 2032 CQP Senior Notes, along with the net proceeds of the 2037 SPL Private Placement Senior Secured Notes and cash on hand, were used to redeem the outstanding $1.0 billion aggregate principal amount of the 6.25% Senior Secured Notes due 2022 (the “2022 SPL Senior Notes”).
◦In March 2021, we issued an aggregate principal amount of approximately $1.5 billion of 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”). The net proceeds of the 2031 CQP Senior Notes, along with cash on hand, were used to redeem the 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”).
•In April 2021, S&P Global Ratings changed the outlook on our ratings to positive from negative, and in February 2022, upgraded our issuer credit rating from BB to BB+.
•In February 2021, Fitch Ratings (“Fitch”) changed the outlook of SPL’s senior secured notes rating to positive from stable and the outlook of our long-term issuer default rating and senior unsecured notes rating to positive from stable.
Market Environment
The LNG market in 2021 saw unprecedented price increases across all natural gas and LNG benchmarks. Colder than normal temperatures early in the year, concerns over low natural gas and LNG inventories, low additional LNG supply availability and forecasts of a cold 2021/2022 winter in Europe and Asia increased price volatility and supported a run-up in natural gas and LNG prices. These conditions were exacerbated by rising coal and carbon prices in Europe, persistent under-performance from some non-US LNG supply projects and reduced Russian pipe exports to Europe, precipitating the early stages of a price-based energy crisis in Europe.
High demand for LNG during the recovery from the initial stages of the COVID-19 pandemic resulted in intense competition for supplies between the Atlantic and Pacific basins. Global LNG demand grew by about approximately 5% from the comparable 2020 period, adding an additional 18 mtpa to the overall market. A robust economic recovery in China powered an 8% increase in Asia’s LNG demand of approximately 19.5 million tonnes from the comparable 2020 period. This led to competition for supplies between Asia, Europe and Latin America, exposing the supply constraints that the industry has had while emerging from the pandemic. In turn, this drove international natural gas and LNG prices higher and widened the price spreads between the U.S. and other parts of the world. As an example, the Dutch Title Transfer Facility (“TTF”) monthly
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settlement prices averaged $14.4/MMBtu in 2021, approximately 375% higher than the $3.0/MMBtu average in 2020, and the TTF monthly settlement prices averaged $28.9/MMBtu in the fourth quarter of 2021, approximately 512% higher than the $4.72/MMBtu average in the fourth quarter of 2020. Similarly, the 2021 average settlement price for the Japan Korea Marker (“JKM”) increased 292% year-over-year to an average of $15.0/MMBtu in 2021, and the fourth quarter of 2021 average settlement price for the JKM increased over 412% year-over-year to an average of $27.9/MMBtu. This extreme price increase triggered a strong supply response from the U.S., which played a significant role in balancing the global LNG market. The U.S. exported 70 million tonnes of LNG, a gain of approximately 49% from the comparable 2020 period, as the market continued to pull on supplies from our facilities and those of our competitors. Exports from our Liquefaction Project reached 25 million tonnes, representing over 35% of the gain in the U.S. total over the same period.
Results of Operations
The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Project (including both operational and commissioning volumes) during the years ended December 31, 2021 and 2020:
| (1) | The years ended December 31, 2021 and 2020 excludes eight TBtu and 17 TBtu, respectively, that were loaded at our affiliate’s facility. | |||||||||||||||||||
Net income
| Year Ended December 31, | ||||||||||||||||||||
| (in millions, except per share data) | 2021 | 2020 | Variance ($) | |||||||||||||||||
| Net income | $ | 1,630 | $ | 1,183 | $ | 447 | ||||||||||||||
| Basic and diluted net income per common unit | 3.00 | 2.32 | 0.68 | |||||||||||||||||
Net income increased by $447 million during the year ended December 31, 2021 from the comparable period in 2020, primarily as a result of increased margin on LNG delivered as a result of increases in both volume delivered and gross margin on LNG delivered per MMBtu, partially offset by non-recurrence of revenues recognized on LNG cargoes for which customers notified us that they would not take delivery.
We enter into derivative instruments to manage our exposure to commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions being economically hedged are accounted for under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative
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instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.
Revenues
| Year Ended December 31, | ||||||||||||||||||||
| (in millions, except volumes) | 2021 | 2020 | Variance ($) | |||||||||||||||||
| LNG revenues | $ | 7,639 | $ | 5,195 | $ | 2,444 | ||||||||||||||
| LNG revenues—affiliate | 1,472 | 662 | 810 | |||||||||||||||||
| LNG revenues—related party | 1 | — | 1 | |||||||||||||||||
| Regasification revenues | 269 | 269 | — | |||||||||||||||||
| Other revenues | 53 | 41 | 12 | |||||||||||||||||
| Total revenues | $ | 9,434 | $ | 6,167 | $ | 3,267 | ||||||||||||||
| LNG volumes recognized as revenues (in TBtu) (1) | 1,288 | 991 | 297 | |||||||||||||||||
(1)Excludes volume associated with cargoes for which customers notified us that they would not take delivery. The years ended December 31, 2021 and 2020 include eight TBtu and 17 TBtu, respectively, that were loaded at our affiliate’s facility.
Total revenues increased by approximately $3.3 billion during the year ended December 31, 2021, from the comparable period in 2020, primarily due to increased revenues per MMBtu as a result of variable fees that are received in addition to fixed fees when customers take delivery of scheduled cargoes as opposed to exercising their contractual right to not take delivery, as well as from increases in Henry Hub prices and higher volumes of LNG delivered between the periods due to the delivery of all available volume of LNG in 2021. 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.
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 year ended December 31, 2021, we realized offsets to LNG terminal costs of $105 million, corresponding to 12 TBtu that were related to the sale of commissioning cargoes from the Liquefaction Project. 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 certain 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 $173 million and $255 million during the years ended December 31, 2021 and 2020, respectively, related to these transactions.
We expect the volume of LNG produced and available for sale to increase in the future as Train 6 of the Liquefaction Project achieved substantial completion on February 4, 2022.
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Operating costs and expenses
| Year Ended December 31, | ||||||||||||||||||||
| (in millions) | 2021 | 2020 | Variance ($) | |||||||||||||||||
| Cost of sales | $ | 5,290 | $ | 2,505 | $ | 2,785 | ||||||||||||||
| Cost of sales—affiliate | 84 | 77 | 7 | |||||||||||||||||
| Cost of sales—related party | 17 | — | 17 | |||||||||||||||||
| Operating and maintenance expense | 635 | 629 | 6 | |||||||||||||||||
| Operating and maintenance expense—affiliate | 142 | 152 | (10) | |||||||||||||||||
| Operating and maintenance expense—related party | 46 | 13 | 33 | |||||||||||||||||
| Development expense | 1 | — | 1 | |||||||||||||||||
| Development expense—affiliate | 1 | — | 1 | |||||||||||||||||
| General and administrative expense | 9 | 14 | (5) | |||||||||||||||||
| General and administrative expense—affiliate | 85 | 96 | (11) | |||||||||||||||||
| Depreciation and amortization expense | 557 | 551 | 6 | |||||||||||||||||
| Impairment expense and loss on disposal of assets | 10 | 5 | 5 | |||||||||||||||||
| Total operating costs and expenses | $ | 6,877 | $ | 4,042 | $ | 2,835 | ||||||||||||||
Total operating costs and expenses increased during the year ended December 31, 2021 from the year ended December 31, 2020, primarily as a result of increased cost of sales. 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 increased during the year ended December 31, 2021 from the comparable period in 2020 primarily due to the increase in pricing of natural gas feedstock as a result of higher US natural gas prices and increased volume of LNG delivered, partially offset by a decrease in net costs associated with the sale of certain unutilized natural gas procured for the liquefaction process and the increased fair value of commodity derivatives to secure natural gas feedstock for the Liquefaction Project due to favorable shifts in long-term forward prices relative to our hedged position. Cost of sales also includes variable transportation and storage costs and other costs to convert natural gas into LNG.
Other expense
| Year Ended December 31, | ||||||||||||||||||||
| (in millions) | 2021 | 2020 | Variance ($) | |||||||||||||||||
| Interest expense, net of capitalized interest | $ | 831 | $ | 909 | $ | (78) | ||||||||||||||
| Loss on modification or extinguishment of debt | 101 | 43 | 58 | |||||||||||||||||
| Other income, net | (3) | (8) | 5 | |||||||||||||||||
| Other income—affiliate | (2) | (2) | — | |||||||||||||||||
| Total other expense | $ | 927 | $ | 942 | $ | (15) | ||||||||||||||
Interest expense, net of capitalized interest, decreased during the year ended December 31, 2021 from the comparable period in 2020 primarily due to lower interest costs as a result of refinancing higher cost debt and reduction of outstanding debt during the year, as well as an increase in the portion of total interest costs that is eligible for capitalization due to the continued construction of the remaining assets of the Liquefaction Project. During the years ended December 31, 2021 and 2020, we incurred $963 million and $1,005 million of total interest cost, respectively, of which we capitalized $132 million and $96 million, respectively.
Loss on modification or extinguishment of debt increased during the year ended December 31, 2021 from the comparable period in 2020. The loss on modification of debt recognized in each of the years included the incurrence of fees paid to lenders, third party fees and write off of unamortized debt issuance costs recognized upon the early redemption of our senior notes, as further discussed in Liquidity and Capital Resources—Sources and Uses of Cash—Financing Cash Flows.
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Liquidity and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings by us or our subsidiaries and equity offerings by us. The table below provides a summary of our available liquidity as of December 31, 2021 (in millions). Future material sources of liquidity are discussed below.
| December 31, 2021 | |||||
| Cash and cash equivalents | $ | 876 | |||
| Restricted cash and cash equivalents designated for the Liquefaction Project | 98 | ||||
| Available commitments under our credit facilities (1): | |||||
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”) | 805 | ||||
| CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”) | 750 | ||||
| Total available commitments under our credit facilities | 1,555 | ||||
| Total available liquidity | $ | 2,529 | |||
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2021. See Note 11—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.
Our liquidity position subsequent to December 31, 2021 is driven by future sources of liquidity and future cash requirements. Future sources of liquidity are expected to be composed of (1) cash receipts from executed contracts, under which we are contractually entitled to future consideration, and (2) additional sources of liquidity, from which we expect to receive cash although the cash is not underpinned by executed contracts. Future cash requirements are expected to be composed of (1) cash payments under executed contracts, under which we are contractually obligated to make payments, and (2) additional cash requirements, under which we expect to make payments although we are not contractually obligated to make the payments under executed contracts. Future sources of liquidity and future cash requirements are estimates based on management’s assumptions and currently known market conditions and other factors as of December 31, 2021.
Although material sources of liquidity and material cash requirements are presented below from a consolidated standpoint, we and our subsidiary SPL operate with independent capital structures. Certain restrictions under debt instruments executed by our subsidiaries limit its ability to distribute cash, including the following:
•SPL is required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. The majority of the cash held by SPL that is restricted to CQP relates to advance funding for operation and construction of the Liquefaction Project; and
•SPL is restricted by affirmative and negative covenants included in certain of its debt agreements in its ability to make certain payments, including distributions, unless specific requirements are satisfied.
Notwithstanding the restrictions noted above, we believe that sufficient flexibility exists to enable each independent capital structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL primarily fund the cash requirements of SPL, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by SPLNG, is available to enable CQP to meet its cash requirements.
Supplemental Guarantor Information
The $1.5 billion of 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”), the 2031 CQP Senior Notes and the 2032 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”).
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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 CQP (“Parent Issuer”), and the CQP Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis. Investments in and equity in the earnings of SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”), which are not currently members of the Obligor Group, have been excluded. Intercompany balances and 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.
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| Summarized Statement of Income (in millions) | Year Ended December 31, 2021 | |||||||
| Revenues | $ | 323 | ||||||
| Revenues from Non-Guarantors | 512 | |||||||
| Total revenues | 835 | |||||||
| Operating costs and expenses | 191 | |||||||
| Operating costs and expenses—affiliate | 178 | |||||||
| Total operating costs and expenses | 369 | |||||||
| Income from operations | 466 | |||||||
| Net income | 165 | |||||||
Future Sources and Uses of Liquidity
Future Sources of Liquidity under Executed Contracts
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs and TUAs which has not yet been recognized as revenue. This future consideration is in most cases not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2021. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed contracts as of December 31, 2021 (in billions):
| Estimated Revenues Under Executed Contracts by Period (1) | |||||||||||||||||||||||
| 2022 | 2023 - 2026 | Thereafter | Total | ||||||||||||||||||||
| LNG revenues (fixed fees) (2) | $ | 3.4 | $ | 13.8 | $ | 34.2 | $ | 51.4 | |||||||||||||||
| LNG revenues (variable fees) (2) (3) | 5.4 | 19.1 | 50.5 | 75.0 | |||||||||||||||||||
| Regasification revenues | 0.3 | 1.0 | 0.6 | 1.9 | |||||||||||||||||||
| Total | $ | 9.1 | $ | 33.9 | $ | 85.3 | $ | 128.3 | |||||||||||||||
(1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2021. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)LNG revenues (including $2.1 billion and $4.0 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2021. The pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. 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 to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt.
LNG Revenues
We have contracted approximately 75% of the total production capacity from the Liquefaction Project through long-term SPAs, with approximately 16 years of weighted average remaining life as of December 31, 2021. The majority of this contracted capacity is comprised of fixed-price, long-term SPAs that SPL has executed with third parties to sell LNG from
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Trains 1 through 6 of the Liquefaction Project. Under the SPAs, the customers purchase LNG on a free on board (“FOB”) basis 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 115% of Henry Hub. Certain 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. The variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases and variable transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. 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 of the Liquefaction Project. After giving effect to an SPA that Cheniere has committed to provide to SPL and upon the date of first commercial delivery of Train 6, the annual fixed fee portion to be paid by the third-party SPA customers is expected to increase to at least $3.3 billion. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A, A2 and A- by S&P Global Ratings, Moody’s Corporation and Fitch Ratings, respectively. A discussion of revenues under our SPAs can be found in Note 13—Revenues from Contracts with Customers of our Notes to Consolidated Financial Statements.
In addition to the third party SPAs discussed above, SPL has also executed agreements with Cheniere Marketing to sell: (1) 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 and (2) up to 306 cargoes to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub (included in the table above).
In August 2020, we 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 certain 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.
Regasification Revenues
SPLNG has entered into two long-term, third party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the approximately 2 Bcf/d of the regasification capacity they have reserved at the Sabine Pass LNG terminal. TotalEnergies Gas & Power North America, Inc. (“Total”) and Chevron U.S.A. Inc. (“Chevron”) are each 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.
SPLNG has also entered into a TUA with SPL to reserve the remaining capacity at the Sabine Pass LNG terminal. 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 SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG that started in 2019. 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. Payments made by SPL to Total under this partial TUA assignment agreement are included in other purchase obligations in the Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts table below. Full discussion of SPLNG’s revenues under the TUA agreements and the partial TUA assignment can be found in Note 13—Revenues from Contracts with Customers of our Notes to Consolidated Financial Statements.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2021, we had $1.6 billion in available commitments under our credit facilities, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature between 2024 and 2025.
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Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts
We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures under executed contracts as of December 31, 2021 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | |||||||||||||||||||||||
| 2022 | 2023 - 2026 | Thereafter | Total | ||||||||||||||||||||
| Purchase obligations (2): | |||||||||||||||||||||||
| Natural gas supply agreements (3) | $ | 5.0 | $ | 7.9 | $ | 3.2 | $ | 16.1 | |||||||||||||||
| Natural gas transportation and storage service agreements (4) | 0.2 | 0.9 | 1.7 | 2.8 | |||||||||||||||||||
| Capital expenditures (5) | 0.2 | — | — | 0.2 | |||||||||||||||||||
| Other purchase obligations (6) | 0.2 | 0.8 | 1.1 | 2.1 | |||||||||||||||||||
| Leases (7) | — | 0.1 | 0.1 | 0.2 | |||||||||||||||||||
| Total | $ | 5.6 | $ | 9.7 | $ | 6.1 | $ | 21.4 | |||||||||||||||
(1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2021. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)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. 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 currently expected to be exercised.
(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2021.
(4)Includes $0.3 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements.
(5)Capital expenditures primarily consist of costs incurred through our EPC contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction.
(6)Other purchase obligations primarily include 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. Includes $0.9 million of purchase obligations to affiliates under service agreements.
(7)Leases include payments under operating leases and forward-starting leases. Certain of our leases also contain variable payments, such as inflation, which are not included above unless the contract terms require the payment of a fixed amount that is unavoidable. Payments during renewal options that are exercisable at our sole discretion are included only to the extent that the option is currently believed to be reasonably certain to be exercised.
Natural Gas Supply, Transportation and Storage Service Agreements
We have secured natural gas feedstock for the Sabine Pass LNG terminal through long-term natural gas supply agreements. As of December 31, 2021, we have secured 86% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2022. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2022. Natural gas supply is generally secured on an indexed pricing basis, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied conditions precedent as of December 31, 2021, we have secured up to 5,102 TBtu of natural gas feedstock through agreements with remaining terms that range up to 10 years. A discussion of our natural gas supply agreements can be found in Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements.
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To ensure that we are able to transport natural gas feedstock to the Sabine Pass LNG terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from third party pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project.
Capital Expenditures
We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Project. The historical contracts have been executed with Bechtel, who has charged a lump sum for all work performed and generally bore project cost, schedule and performance risks unless certain specified events occurred, in which case Bechtel caused us to enter into a change order, or we agreed with Bechtel to a change order. The future capital expenditures included in the table above primarily consist of costs incurred under the Bechtel EPC contract for Train 6 of the Liquefaction Project. The total contract price of the EPC contract for Train 6, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction is approximately $2.5 billion.
Leases
We have entered into leases for the use of tug vessels and land sites. A discussion of our lease obligations can be found in Note 12—Leases of our Notes to Consolidated Financial Statements.
Additional Future Cash Requirements for Operations and Capital Expenditures
Corporate Activities
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, 2022, Cheniere and its subsidiaries had 1,550 full-time employees, including 513 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.
Financially Disciplined Growth
Our significant land position at the Sabine Pass LNG terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. We expect that any potential future expansion at the Sabine Pass LNG terminal would increase cash requirements to support expanded operations, although expansion could be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
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Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2021 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | |||||||||||||||||||||||
| 2022 | 2023 - 2026 | Thereafter | Total | ||||||||||||||||||||
| Debt (2) | $ | — | $ | 7.1 | $ | 10.2 | $ | 17.3 | |||||||||||||||
| Interest payments (2) | 0.8 | 2.6 | 1.4 | 4.8 | |||||||||||||||||||
| Total | $ | 0.8 | $ | 9.7 | $ | 11.6 | $ | 22.1 | |||||||||||||||
(1)The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2021. Debt and interest payments do not contemplate repurchases, repayments and retirements that we expect to make prior to contractual maturity. See further discussion in Note 11—Debt of our Notes to Consolidated Financial Statements.
Debt
As of December 31, 2021, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $17.3 billion and credit facilities with an aggregate outstanding balance of zero. As of December 31, 2021, we and SPL were in compliance with all covenants related to their respective debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 11—Debt of our Notes to Consolidated Financial Statements.
Interest
As of December 31, 2021, our senior notes had a weighted average interest rate of 4.86%. Borrowings under our credit facilities are indexed to LIBOR, which is expected to be phased out by 2023. 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 and counterparties to pursue amendments to our debt agreements that are currently indexed to LIBOR. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.20% to 0.49%. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.50% to 1.625%. We had $395 million of issued letters of credit under our credit facilities as of December 31, 2021.
Additional Future Cash Requirements for Financing
CQP Distribution
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.
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Sources and Uses of Cash
The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents for the years ended December 31, 2021 and 2020 (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.
| Year Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Net cash provided by operating activities | $ | 2,291 | $ | 1,751 | |||||||
| Net cash used in investing activities | (648) | (972) | |||||||||
| Net cash used in financing activities | (1,976) | (1,434) | |||||||||
| Net decrease in cash, cash equivalents and restricted cash and cash equivalents | $ | (333) | $ | (655) | |||||||
Operating Cash Flows
Our operating cash net inflows during the years ended December 31, 2021 and 2020 were $2,291 million and $1,751 million, respectively. The $540 million increase in operating cash inflows in 2021 compared to 2020 was primarily related to cash provided by working capital primarily from payment timing differences and timing of cash receipts from the sale of LNG cargoes.
Investing Cash Flows
Cash outflows for property, plant and equipment were primarily for the construction costs for Train 6 of the Liquefaction Project, which was nearing substantial completion in the fourth quarter of 2021. These costs are capitalized as construction-in-process until achievement of substantial completion.
Financing Cash Flows
During the year ended December 31, 2021, we had total debt issuances of $3,182 million, which were comprised of $2,700 million aggregate principal amount of senior notes and aggregate borrowings of $482 million under our credit facilities. The proceeds from these issuances and borrowings, together with cash on hand, were used to redeem $3,600 million aggregate principal amount of senior notes.
During the year ended December 31, 2020, we entered into the 2020 SPL Working Capital Facility to replace the previous working capital facility, as well as issued an aggregate principal amount of $2.0 billion of the 4.500% Senior Secured Notes due 2030 (the “2030 SPL Senior Notes”) that was used to redeem all of SPL’s 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”).
Debt Issuances and Related Financing Costs
The following table shows the issuances of debt during the years ended December 31, 2021 and 2020, including intra-quarter borrowings (in millions):
| Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| SPL: | ||||||||||||||
2030 SPL Senior Notes | $ | — | $ | 1,995 | ||||||||||
2037 SPL Private Placement Senior Secured Notes | 482 | — | ||||||||||||
| CQP: | ||||||||||||||
2031 CQP Senior Notes | 1,500 | — | ||||||||||||
2032 CQP Senior Notes | 1,200 | — | ||||||||||||
| Total issuances | $ | 3,182 | $ | 1,995 | ||||||||||
During the years ended December 31, 2021 and 2020, we incurred debt issuance costs and other financing costs of $39 million and $35 million, respectively, related to the debt issuances above and closing of credit facilities during the respective periods.
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Debt Redemptions and Repayments and Related Extinguishment Costs
The following table shows the redemptions and repayments of debt during the years ended December 31, 2021 and 2020, including intra-quarter repayments (in millions):
| Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| SPL: | ||||||||||||||
2021 SPL Senior Notes | $ | — | $ | (2,000) | ||||||||||
2022 SPL Senior Notes | (1,000) | — | ||||||||||||
| CQP: | ||||||||||||||
2025 CQP Senior Notes | (1,500) | — | ||||||||||||
2026 CQP Senior Notes | (1,100) | — | ||||||||||||
| Total redemption and repayments | $ | (3,600) | $ | (2,000) | ||||||||||
During the years ended December 31, 2021 and 2020, we incurred debt extinguishment costs of $76 million and $39 million, respectively, related to these redemptions and repayments, primarily for the payment of early redemption fees and write off of unamortized issuance costs.
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, 2021 and 2020:
| Total Distribution (in millions) | ||||||||||||||||||||||||||||||||||||||||||||
| Date Paid | Period Covered by Distribution | Distribution Per Common Unit | Distribution Per Subordinated Unit | Common Units | Subordinated Units | General Partner Units | Incentive Distribution Rights | |||||||||||||||||||||||||||||||||||||
| November 12, 2021 | July 1 - September 30, 2021 | $ | 0.680 | $ | — | $ | 329 | $ | — | $ | 8 | $ | 39 | |||||||||||||||||||||||||||||||
| August 13, 2021 | April 1 - June 30, 2021 | 0.665 | — | 322 | — | 7 | 32 | |||||||||||||||||||||||||||||||||||||
| May 14, 2021 | January 1 - March 31, 2021 | 0.660 | — | 320 | — | 7 | 30 | |||||||||||||||||||||||||||||||||||||
| February 12, 2021 | October 1 - December 31, 2020 | 0.655 | — | 316 | — | 7 | 27 | |||||||||||||||||||||||||||||||||||||
| November 13, 2020 | July 1 - September 30, 2020 | $ | 0.65 | $ | — | $ | 315 | $ | — | $ | 7 | $ | 25 | |||||||||||||||||||||||||||||||
| August 14, 2020 | April 1 - June 30, 2020 | 0.645 | 0.645 | 225 | 88 | 7 | 22 | |||||||||||||||||||||||||||||||||||||
| May 15, 2020 | January 1 - March 31, 2020 | 0.64 | 0.64 | 223 | 86 | 7 | 20 | |||||||||||||||||||||||||||||||||||||
| February 14, 2020 | October 1 - December 31, 2019 | 0.63 | 0.63 | 220 | 85 | 6 | 18 | |||||||||||||||||||||||||||||||||||||
On January 28, 2022, we declared a $0.700 distribution per common unit and the related distribution to our general partner and incentive distribution right holders that was paid on February 14, 2022 to unitholders of record as of February 7, 2022 for the period from October 1, 2021 to December 31, 2021.
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.
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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 through earnings 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 as discussed below.
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 derivative contracts, consisting primarily of natural gas supply contracts for the operation of our liquified natural gas facilities is often 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 and volatility.
The valuation of certain physical commodity derivatives requires the use of significant unobservable inputs and judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below is the change in unrealized valuation gain (loss) of instruments valued through the use of internal models which incorporate significant unobservable inputs, inclusive of certain LNG term deals, for the years ended December 31, 2021 and 2020 (in millions). The changes shown are limited to instruments held at the end of each respective period.
| Year Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Change in unrealized gain (loss) relating to instruments still held at end of period | $ | 74 | $ | (43) | |||||||
The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as it relates to commodity prices given the level of volatility in the current year. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.
Recent Accounting Standards
For a summary 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):
| December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||
| Fair Value | Change in Fair Value | Fair Value | Change in Fair Value | ||||||||||||||||||||
| Liquefaction Supply Derivatives | $ | 27 | $ | 1 | $ | (21) | $ | 4 | |||||||||||||||
See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE ENERGY PARTNERS, L.P.
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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, 2021, 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, 2021, 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 | By: | /s/ Zach Davis | |||||||||||
| Jack A. Fusco | Zach Davis | |||||||||||||
| President and Chief Executive Officer (Principal Executive Officer) | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | |||||||||||||
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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, 2021 and 2020, the related consolidated statements of income, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, 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, 2021, 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, 2022 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.
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 $38 million, as of December 31, 2021. 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 using internal models that incorporate significant unobservable inputs.
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.
48
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 related to the valuation of the level 3 physical liquefaction supply derivatives. This included controls related to the assumptions for significant unobservable inputs. For a sample of level 3 liquefaction supply derivatives, we involved valuation professionals with specialized skills and knowledge who assisted in:
•evaluating the future prices of energy units for observable periods by comparing to market data, including quoted or published forward prices
•developing independent fair value estimates and comparing the independently developed estimates to the Company’s fair value estimates.
In addition, we evaluated the Partnership’s assumptions for future prices of energy units for unobservable periods and liquidity by comparing them 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, 2022
49
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, 2021, 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, 2021, 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, 2021 and 2020, the related consolidated statements of income, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes and financial statement schedule I (collectively, the consolidated financial statements), and our report dated February 23, 2022 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 company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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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, 2022
51
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per unit data)
| Year Ended December 31, | |||||||||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||||||||
| Revenues | |||||||||||||||||||||||
| LNG revenues | $ | 7,639 | $ | 5,195 | $ | 5,211 | |||||||||||||||||
| LNG revenues—affiliate | 1,472 | 662 | 1,312 | ||||||||||||||||||||
| LNG revenues—related party | 1 | — | — | ||||||||||||||||||||
| Regasification revenues | 269 | 269 | 266 | ||||||||||||||||||||
| Other revenues | 53 | 41 | 49 | ||||||||||||||||||||
| Total revenues | 9,434 | 6,167 | 6,838 | ||||||||||||||||||||
| Operating costs and expenses | |||||||||||||||||||||||
| Cost of sales (excluding items shown separately below) | 5,290 | 2,505 | 3,374 | ||||||||||||||||||||
| Cost of sales—affiliate | 84 | 77 | 7 | ||||||||||||||||||||
| Cost of sales—related party | 17 | — | — | ||||||||||||||||||||
| Operating and maintenance expense | 635 | 629 | 632 | ||||||||||||||||||||
| Operating and maintenance expense—affiliate | 142 | 152 | 138 | ||||||||||||||||||||
| Operating and maintenance expense—related party | 46 | 13 | — | ||||||||||||||||||||
| Development expense | 1 | — | — | ||||||||||||||||||||
| Development expense—affiliate | 1 | — | — | ||||||||||||||||||||
| General and administrative expense | 9 | 14 | 11 | ||||||||||||||||||||
| General and administrative expense—affiliate | 85 | 96 | 102 | ||||||||||||||||||||
| Depreciation and amortization expense | 557 | 551 | 527 | ||||||||||||||||||||
| Impairment expense and loss on disposal of assets | 10 | 5 | 7 | ||||||||||||||||||||
| Total operating costs and expenses | 6,877 | 4,042 | 4,798 | ||||||||||||||||||||
| Income from operations | 2,557 | 2,125 | 2,040 | ||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||
| Interest expense, net of capitalized interest | (831) | (909) | (885) | ||||||||||||||||||||
| Loss on modification or extinguishment of debt | (101) | (43) | (13) | ||||||||||||||||||||
| Other income, net | 3 | 8 | 31 | ||||||||||||||||||||
| Other income—affiliate | 2 | 2 | 2 | ||||||||||||||||||||
| Total other expense | (927) | (942) | (865) | ||||||||||||||||||||
| Net income | $ | 1,630 | $ | 1,183 | $ | 1,175 | |||||||||||||||||
| Basic and diluted net income per common unit | $ | 3.00 | $ | 2.32 | $ | 2.25 | |||||||||||||||||
| Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation | 484.0 | 399.3 | 348.6 | ||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
52
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)
The accompanying notes are an integral part of these consolidated financial statements.
53
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
(in millions)
| Common Unitholders’ Interest | Subordinated Unitholder’s Interest | General Partner’s Interest | Total Partners’ Equity | ||||||||||||||||||||||||||||||||||||||
| Units | Amount | Units | Amount | Units | Amount | ||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 348.6 | $ | 1,806 | 135.4 | $ | (990) | 9.9 | $ | (16) | $ | 800 | ||||||||||||||||||||||||||||||
| Net income | — | 829 | — | 322 | — | 24 | 1,175 | ||||||||||||||||||||||||||||||||||
| Distributions | |||||||||||||||||||||||||||||||||||||||||
Common units, $2.57/unit | — | (843) | — | — | — | — | (843) | ||||||||||||||||||||||||||||||||||
Subordinated units, $2.57/unit | — | — | — | (328) | — | — | (328) | ||||||||||||||||||||||||||||||||||
| General partner units | — | — | — | — | — | (89) | (89) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 348.6 | 1,792 | 135.4 | (996) | 9.9 | (81) | 715 | ||||||||||||||||||||||||||||||||||
| Net income | — | 930 | — | 229 | — | 24 | 1,183 | ||||||||||||||||||||||||||||||||||
| Conversion of subordinated units into common units | 135.4 | (1,026) | (135.4) | 1,026 | — | — | — | ||||||||||||||||||||||||||||||||||
| Distributions | |||||||||||||||||||||||||||||||||||||||||
Common units, $2.57/unit | — | (982) | — | — | — | — | (982) | ||||||||||||||||||||||||||||||||||
Subordinated units, $2.57/unit | — | — | — | (259) | — | — | (259) | ||||||||||||||||||||||||||||||||||
| General partner units | — | — | — | — | — | (118) | (118) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 484.0 | 714 | — | — | 9.9 | (175) | 539 | ||||||||||||||||||||||||||||||||||
| Net income | — | 1,597 | — | — | — | 33 | 1,630 | ||||||||||||||||||||||||||||||||||
| Distributions | |||||||||||||||||||||||||||||||||||||||||
Common units, $2.660/unit | — | (1,287) | — | — | — | — | (1,287) | ||||||||||||||||||||||||||||||||||
| General partner units | — | — | — | — | — | (164) | (164) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 484.0 | $ | 1,024 | — | $ | — | 9.9 | $ | (306) | $ | 718 | ||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
54
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
| Net income | $ | 1,630 | $ | 1,183 | $ | 1,175 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization expense | 557 | 551 | 527 | ||||||||||||||
| Amortization of debt issuance costs, premium and discount | 29 | 32 | 34 | ||||||||||||||
| Loss on modification or extinguishment of debt | 101 | 43 | 13 | ||||||||||||||
| Total losses (gains) on derivatives, net | (29) | 49 | (72) | ||||||||||||||
| Total gains on derivatives, net—related party | (2) | — | — | ||||||||||||||
| Net cash provided by (used for) settlement of derivative instruments | (17) | (4) | 5 | ||||||||||||||
| Impairment expense and loss on disposal of assets | 10 | 5 | 7 | ||||||||||||||
| Other | 17 | 14 | 11 | ||||||||||||||
| Other—affiliate | — | (2) | (2) | ||||||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||||
| Accounts and other receivables, net of current expected credit losses | (204) | (21) | 16 | ||||||||||||||
| Accounts receivable—affiliate | (32) | (80) | 9 | ||||||||||||||
| Accounts receivable—related party | (1) | — | — | ||||||||||||||
| Advances to affiliate | 2 | 8 | (41) | ||||||||||||||
| Inventory | (68) | 8 | (16) | ||||||||||||||
| Accounts payable and accrued liabilities | 321 | — | (126) | ||||||||||||||
| Accrued liabilities—related party | (1) | 4 | — | ||||||||||||||
| Due to affiliates | 1 | 9 | 6 | ||||||||||||||
| Deferred revenue | 18 | (18) | 39 | ||||||||||||||
| Other, net | (41) | (28) | (36) | ||||||||||||||
| Other, net—affiliate | — | (2) | (2) | ||||||||||||||
| Net cash provided by operating activities | 2,291 | 1,751 | 1,547 | ||||||||||||||
| Cash flows from investing activities | |||||||||||||||||
| Property, plant and equipment | (648) | (972) | (1,331) | ||||||||||||||
| Other | — | — | (1) | ||||||||||||||
| Net cash used in investing activities | (648) | (972) | (1,332) | ||||||||||||||
| Cash flows from financing activities | |||||||||||||||||
| Proceeds from issuances of debt | 3,182 | 1,995 | 2,230 | ||||||||||||||
| Redemptions and repayments of debt | (3,600) | (2,000) | (730) | ||||||||||||||
| Debt issuance and other financing costs | (39) | (35) | (35) | ||||||||||||||
| Debt extinguishment costs | (76) | (39) | (4) | ||||||||||||||
| Distributions to owners | (1,451) | (1,359) | (1,260) | ||||||||||||||