EDGAR 10-K Filing

Company CIK: 1499200
Filing Year: 2022
Filename: 1499200_10-K_2022_0001499200-22-000003.json

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ITEM 1. BUSINESS
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
We are a Delaware limited liability company formed by Cheniere Energy Partners, L.P. (“CQP”). 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, has 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 is located in Cameron Parish, Louisiana, adjacent to the existing regasification facilities owned and operated by Sabine Pass LNG, L.P. (“SPLNG”).
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. Further development of the Sabine Pass LNG terminal 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 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 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. We have 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
SPLNG has received authorization from the FERC for the construction of the third marine berth.
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.
Natural Gas Supply, Transportation and Storage
We have secured natural gas feedstock for the Sabine Pass LNG terminal through long-term natural gas supply agreements. Additionally, to ensure that we are 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.
Terminal Use Agreements
We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. Additionally, we have entered into a partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“Total”), another TUA customer, to provide us with additional berthing and storage capacity at the Sabine Pass LNG terminal. Refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources for additional discussion of our TUA agreements.
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
25% 25% 29%
GAIL (India) Limited
18% 19% 21%
Korea Gas Corporation
17% 18% 21%
Naturgy LNG GOM, Limited
16% 16% 19%
Total
10% * *
* Less than 10%
All of the above customers contribute to our LNG revenues through SPA contracts.
Governmental Regulation
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. 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 Liquefaction Project 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 sale for resale of natural gas in interstate commerce and to the construction, operation, maintenance and expansion of liquefaction facilities.
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, we 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.
On September 27, 2019, we 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.
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.
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 the Liquefaction Project. 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 the Liquefaction Project. For example, throughout the life of our liquefaction facility, 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 facility. 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.
Other Governmental Permits, Approvals and Authorizations
Construction and operation of the Liquefaction Project 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 Louisiana Department of Environmental Quality (“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 Liquefaction Project.
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 Liquefaction Project 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.
Clean Air Act
The Liquefaction Project 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 the Liquefaction Project, 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 Liquefaction Project 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 Liquefaction Project 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.
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 Liquefaction Project may 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 our Liquefaction Project, 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 import 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 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, 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.
Competition
When we need to replace any existing SPA or enter into new SPAs, we 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.
Employees
We have no employees. We have contracts with subsidiaries of Cheniere and CQP for operations, maintenance and management services. As of January 31, 2022, Cheniere and its subsidiaries had 1,550 full-time employees, including 513 employees who directly supported the Liquefaction Project. See Note 12-Related Party Transactions of our Notes to Financial Statements for a discussion of the services agreements pursuant to which general and administrative services are provided to us.
Available Information
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. 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
ITEM 1A. RISK FACTORS
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;
•Risks Relating to Our Operations and Industry; and
•Risks Relating to Regulations.
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 no cash and cash equivalents, $98 million of restricted cash and cash equivalents, $805 million of available commitments under the our $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”) and $13.1 billion of total debt outstanding (before unamortized premium, discount and debt issuance costs). We incur, and will incur, significant interest expense relating to the assets at the Liquefaction Project. 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 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.
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 events of force majeure.
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.
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 Liquefaction Project or caused minor damage to our Liquefaction Project. In August 2020, we entered into an arrangement with our 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 our affiliate’s terminal. During the year ended 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 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. 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 Liquefaction Project is, and will be, subject to the inherent risks associated with this type of operation, 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;
•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 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 exported LNG to be a competitive source of energy for 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.
Political instability in foreign countries that import 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 LNG from the United States. Furthermore, some foreign suppliers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or from our competitors’ liquefaction 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 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 from the Liquefaction Project on a commercial basis. Any significant impediment to the ability to deliver LNG from the United States generally, 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 LNG industry is 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 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 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 Liquefaction Project 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.
We are entirely dependent on Cheniere and CQP, 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 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 Liquefaction Project. We have contracted with subsidiaries of Cheniere and CQP to provide the personnel necessary for the operation, maintenance and management of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. 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 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 Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.
Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do 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 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.
We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, we have a TUA with SPLNG under which SPLNG derives economic benefits, we have entered into a transportation agreement with CTPL to transport natural gas to the Liquefaction Project and we have also executed agreements with Cheniere Marketing to sell: (1) at Cheniere Marketing’s option, any LNG produced by us 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 with respect to any future expansion of the Liquefaction Project.
We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements with one or more Cheniere-affiliated entities as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.
We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.
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 the Liquefaction Project 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 the Liquefaction Project and the export of LNG are highly regulated activities. Approvals of the FERC and DOE under Section 3 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 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. To date, the DOE has also issued orders under Section 4 of the NGA authorizing us to export domestically produced LNG.
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.
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 terminal, including the 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 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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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
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 Cheniere’s 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 Cheniere’s 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 Cheniere’s 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 us 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, we 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 us returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to us alleging violations of federal pipeline safety regulations relating to the 2018 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, we 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 us in a letter dated November 9, 2021 that the case was considered “closed.” We continue to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation 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
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 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
•Overview of Significant Events
•Market Environment
•Results of Operations
•Liquidity and Capital Resources
•Summary of Critical Accounting Estimates
•Recent Accounting Standards
Overview
We are a limited liability company formed by CQP 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 (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 us 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.
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 October 2021, we redeemed $318 million of our $1.1 billion outstanding 6.25% Senior Secured Notes due 2022 (the “2022 Senior Notes”) using $318 million of capital contributions from CQP.
•In December 2021, we issued Senior Secured Notes due 2037 on a private placement basis for an aggregate principal amount of approximately $482 million (the “2037 Private Placement Senior Secured Notes”). The 2037 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%. The proceeds of the 2037 Private Placement Senior Secured Notes, net of related fees, costs and expenses, along with cash on hand were used to redeem the remaining portion of the 2022 Senior Notes.
•In February 2021, Fitch Ratings (“Fitch”) changed the outlook of our senior secured 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 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
Our net income was $1.5 billion for the year ended December 31, 2021, compared to $943 million in the year ended December 31, 2020. This $518 million increase in net income was primarily a result of increased margin on LNG delivered as a result of increases in both volume delivered and gross margin on LNG delivered per MMBtu, decreased losses from commodity derivatives to secure natural gas feedstock for the Liquefaction Project and decreased interest expense, net, partially offset by non-recurrence of revenues recognized on LNG cargoes for which customers notified us that they would not take delivery.
We enter into derivative instruments to manage our exposure to commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Financial Statements. In some cases, the underlying transactions being economically hedged are accounted for under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.
Revenues
Year Ended December 31,
(in millions, except volumes) 2021 2020 Variance ($)
LNG revenues $ 7,639 $ 5,195 $ 2,444
LNG revenues-affiliate 1,472 662 810
LNG revenues-related party 1 - 1
Total revenues $ 9,112 $ 5,857 $ 3,255
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 year ended December 31, 2020 primarily due to increased revenues per MMBtu as a result of variable fees that are received in addition to fixed fees when the 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 $255 million during the years ended December 31, 2021 and 2020, respectively, related to these transactions.
We expect the volume of LNG produced and available for sale to increase in the future as Train 6 of the Liquefaction Project achieved substantial completion on February 4, 2022.
Operating costs and expenses
Year Ended December 31,
(in millions) 2021 2020 Variance ($)
Cost of sales $ 5,289 $ 2,504 $ 2,785
Cost of sales-affiliate 128 110 18
Cost of sales-related party 17 - 17
Operating and maintenance expense 548 547 1
Operating and maintenance expense-affiliate 457 466 (9)
Operating and maintenance expense-related party 46 13 33
General and administrative expense 4 9 (5)
General and administrative expense-affiliate 61 71 (10)
Depreciation and amortization expense 468 465 3
Impairment expense and loss on disposal of assets 6 1 5
Total operating costs and expenses $ 7,024 $ 4,186 $ 2,838
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. These
increases were 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 $ 622 $ 685 $ (63)
Loss on modification or extinguishment of debt 5 43 (38)
Total other expense $ 627 $ 728 $ (101)
Interest expense, net of capitalized interest, decreased during the year ended December 31, 2021 from the comparable period in 2020 primarily as a result of 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, and to a lesser extent due to the reduction of outstanding debt during the year. During the years ended December 31, 2021 and 2020, we incurred $754 million and $779 million of total interest cost, respectively, of which we capitalized $132 million and $94 million, respectively.
Loss on modification or extinguishment of debt decreased during the year ended December 31, 2021 from the comparable period in 2020. The loss on modification or extinguishment 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.
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 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. 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
Restricted cash and cash equivalents designated for the Liquefaction Project $ 98
Available commitments under our $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”) (1)
Total available liquidity $ 903
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under the 2020 Working Capital Facility as of December 31, 2021. See Note 10-Debt of our Notes to Financial Statements for additional information on the 2020 Working Capital Facility 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 revenues, 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.
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 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 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
Total $ 8.8 $ 32.9 $ 84.7 $ 126.4
(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 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 we have executed with third parties to sell LNG from 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 us 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, respectively. A discussion of revenues under our SPAs can be found in Note 11-Revenues from Contracts with Customers of our Notes to Financial Statements.
In addition to the third party SPAs discussed above, we have also executed agreements with Cheniere Marketing to sell: (1) at Cheniere Marketing’s option, any LNG produced by us 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.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2021, we had $805 million in available commitments under the 2020 Working Capital Facility, subject to compliance with the applicable covenants, to potentially meet liquidity needs. The 2020 Working Capital Facility matures in 2025.
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) 0.3 1.2 2.5 4.0
Capital expenditures (5) 0.2 - - 0.2
Other purchase obligations (6) 0.5 1.8 3.5 5.8
Total $ 6.0 $ 10.9 $ 9.2 $ 26.1
(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 $1.2 billion of purchase obligations to affiliates and $0.3 billion of purchase obligations to related parties under transportation and storage services 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 include $3.8 billion of purchase obligations to affiliates under the TUA and $0.8 billion of purchase obligations to affiliates under services agreements, as well as payments under our partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“Total”), as discussed in Note 11-Revenues from Contracts with Customers of our Notes to Financial Statements.
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 7-Derivative Instruments of our Notes to Financial Statements.
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 CTPL, a wholly owned subsidiary of CQP, and 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 engineering, procurement and construction (“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 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.
Terminal Use Agreements
We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for unloading, loading, storage and regasification of LNG. Full discussion of our TUA agreement can be found in Note 12-Related Party Transactions of our Notes to Financial Statements.
Additionally, we have entered into a partial TUA assignment agreement with Total, another TUA customer, whereby upon substantial completion of Train 5 of the Liquefaction Project, we gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity. Full discussion of our partial TUA assignment with Total can be found in Note 11-Revenues from Contracts with Customers of our Notes to Financial Statements.
Additional Future Cash Requirements for Operations and Capital Expenditures
Corporate Activities
We have contracts with subsidiaries of Cheniere and CQP for operations, maintenance and management services. Cheniere and its subsidiaries’ full-time employee headcount was 1,550, including 513 employees who directly supported the Liquefaction Project operations, as of January 31, 2022. Full discussion of our operations, maintenance and management agreements can be found in Note 12-Related Party Transactions of our Notes to Financial Statements.
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.
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 $ 6.0 $ 13.1
Interest payments (2) 0.7 1.9 0.7 3.3
Total $ 0.7 $ 9.0 $ 6.7 $ 16.4
(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 10-Debt of our Notes to Financial Statements.
Debt
As of December 31, 2021, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $13.1 billion and the 2020 Working Capital Facility with an outstanding balance of zero. As of December 31, 2021, we were in compliance with all covenants related to our debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10-Debt of our Notes to Financial Statements.
Interest
As of December 31, 2021, our senior notes had a weighted average interest rate of 5.15%. Borrowings under the 2020 Working Capital Facility 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 the 2020 Working Capital Facility are subject to commitment fees of 0.20%. Issued letters of credit under the 2020 Working Capital Facility are subject to letter of credit fees of 1.50%. There were $395 million issued letters of credit under the 2020 Working Capital Facility as of December 31, 2021.
Sources and Uses of Cash
The following table summarizes the sources and uses of our 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 $ 1,937 $ 1,424
Net cash used in investing activities (612) (916)
Net cash used in financing activities (1,324) (592)
Net increase (decrease) in restricted cash and cash equivalents $ 1 $ (84)
Operating Cash Flows
Our operating cash net inflows during the years ended December 31, 2021 and 2020 were $1,937 million and $1,424 million, respectively. The $513 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 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 issued approximately $482 million of the 2037 Private Placement Senior Secured Notes. The proceeds of the 2037 Private Placement Senior Secured Notes, along with capital contributions and cash on hand were used to redeem all of the outstanding 2022 Senior Notes.
During the year ended December 31, 2020, we entered into our $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 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 Senior Notes”), which along with cash on hand was used to redeem all of the outstanding 5.625% Senior Secured Notes due 2021 (the “2021 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
2030 Senior Notes
$ - $ 1,995
2037 SPL Private Placement Senior Secured Notes
482 -
Total issuances $ 482 $ 1,995
We incurred $5 million and $35 million of debt issuance and other financing costs during the years ended December 31, 2021 and 2020, respectively, related to the debt transactions described above.
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
2021 Senior Notes
$ - $ (2,000)
2022 Senior Notes
(1,000) -
Total redemption and repayments $ (1,000) $ (2,000)
We incurred $3 million and $39 million of debt extinguishment costs during the years ended December 31, 2021 and 2020, respectively, related to the debt transactions described above.
Capital Contributions and Distributions
During the years ended December 31, 2021 and 2020, we received $821 million and $488 million, respectively of capital contributions from CQP and we made distributions of $1,619 million and $1,001 million, respectively, to CQP.
Summary of Critical Accounting Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.
Fair Value of Derivative Instruments
All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes in the fair value of our derivative positions 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.
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 2-Summary of Significant Accounting Policies of our Notes to Financial Statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 7-Derivative Instruments of our Notes to Financial Statements for additional details about our derivative instruments.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
SABINE PASS LIQUEFACTION, LLC
Management’s Report to the Member of Sabine Pass Liquefaction, LLC
Report of Independent Registered Public Accounting Firm
Statements of Income
Balance Sheets
Statements of Member’s Equity
Statements of Cash Flows
Notes to Financial Statements
Note 1-Organization and Nature of Operations
Note 2-Summary of Significant Accounting Policies
Note 3-Restricted Cash and Cash Equivalents
Note 4-Accounts and Other Receivables, Net of Current Expected Credit Losses
Note 5-Inventory
Note 6-Property, Plant and Equipment, Net of Accumulated Depreciation
Note 7-Derivative Instruments
Note 8-Other Non-current Assets, Net
Note 9-Accrued Liabilities
Note 10-Debt
Note 11-Revenues from Contracts with Customers
Note 12-Related Party Transactions
Note 13-Commitments and Contingencies
Note 14-Customer Concentration
Note 15-Supplemental Cash Flow Information
MANAGEMENT’S REPORT TO THE MEMBER OF SABINE PASS LIQUEFACTION, LLC
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 Sabine Pass Liquefaction, LLC (“Sabine Pass Liquefaction”). 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”). Sabine Pass Liquefaction’s 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 Sabine Pass Liquefaction 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.
This annual report does not include an attestation report of Sabine Pass Liquefaction’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Sabine Pass Liquefaction’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Management’s Certifications
The certifications of Sabine Pass Liquefaction’s Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Sabine Pass Liquefaction’s Form 10-K.
By: /s/ Jack A. Fusco By: /s/ Zach Davis
Jack A. Fusco Zach Davis
Chief Executive Officer
(Principal Executive Officer) Manager and Chief Financial Officer
(Principal Financial Officer)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Member of Sabine Pass Liquefaction, LLC and
Board of Directors of Cheniere Energy Partners GP, LLC
Sabine Pass Liquefaction, LLC:
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Sabine Pass Liquefaction, LLC (the Company) as of December 31, 2021 and 2020, the related statements of income, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company 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.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company 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 financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the 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 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 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 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 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 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 2 and 7 to the financial statements, the Company 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.
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 Company’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 Company’s auditor since 2014.
Houston, Texas
February 23, 2022
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF INCOME
(in millions)
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 - -
Total revenues 9,112 5,857 6,523
Operating costs and expenses
Cost of sales (excluding items shown separately below) 5,289 2,504 3,373
Cost of sales-affiliate 128 110 47
Cost of sales-related party 17 - -
Operating and maintenance expense 548 547 547
Operating and maintenance expense-affiliate 457 466 450
Operating and maintenance expense-related party 46 13 -
General and administrative expense 4 9 6
General and administrative expense-affiliate 61 71 79
Depreciation and amortization expense 468 465 447
Impairment expense and loss on disposal of assets 6 1 6
Total operating costs and expenses 7,024 4,186 4,955
Income from operations 2,088 1,671 1,568
Other income (expense)
Interest expense, net of capitalized interest (622) (685) (705)
Loss on modification or extinguishment of debt (5) (43) -
Other income, net - - 10
Total other expense (627) (728) (695)
Net income $ 1,461 $ 943 $ 873
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
BALANCE SHEETS
(in millions)
December 31,
2021 2020
ASSETS
Current assets
Restricted cash and cash equivalents $ 98 $ 97
Accounts and other receivables, net of current expected credit losses 571 309
Accounts receivable-affiliate 232 185
Accounts receivable-related party 1 -
Advances to affiliate 127 122
Inventory 159 93
Current derivative assets 21 14
Other current assets 60 41
Other current assets-affiliate 21 21
Total current assets 1,290 882
Property, plant and equipment, net of accumulated depreciation 14,433 14,255
Debt issuance costs, net of accumulated amortization 7 10
Derivative assets 33 11
Other non-current assets, net 171 165
Total assets $ 15,934 $ 15,323
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable $ 18 $ 8
Accrued liabilities 1,012 591
Accrued liabilities-related party 4 4
Due to affiliates 73 59
Deferred revenue 132 114
Current derivative liabilities 16 11
Total current liabilities 1,255 787
Long-term debt, net of premium, discount and debt issuance costs 13,023 13,520
Derivative liabilities 11 35
Other non-current liabilities 7 8
Other non-current liabilities-affiliate 17 15
Commitments and contingencies (see Note 13)
Member’s equity 1,621 958
Total liabilities and member’s equity $ 15,934 $ 15,323
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF MEMBER’S EQUITY
(in millions)
Sabine Pass LNG-LP, LLC Total Member’s Equity
Balance at December 31, 2018 $ 466 $ 466
Capital contributions 1,046 1,046
Distributions (1,851) (1,851)
Net income 873 873
Balance at December 31, 2019 534 534
Capital contributions 488 488
Distributions (1,007) (1,007)
Net income 943 943
Balance at December 31, 2020 958 958
Capital contributions 821 821
Distributions (1,619) (1,619)
Net income 1,461 1,461
Balance at December 31, 2021 $ 1,621 $ 1,621
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF CASH FLOWS
(in millions)
Year Ended December 31,
2021 2020 2019
Cash flows from operating activities
Net income $ 1,461 $ 943 $ 873
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 468 465 447
Amortization of debt issuance costs, premium and discount 22 24 27
Loss on modification of debt 5 43 -
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 6 1 6
Changes in operating assets and liabilities:
Accounts and other receivables, net of current expected credit losses (203) (17) 19
Accounts receivable-affiliate (32) (80) 9
Accounts receivable-related party (1) - -
Advances to affiliate (5) 5 (34)
Inventory (66) 9 (16)
Accounts payable and accrued liabilities 326 2 (138)
Accrued liabilities-related party (1) 4 -
Due to affiliates (1) 9 8
Deferred revenue 18 (18) 40
Deferred revenue-affiliate - (10) (13)
Other, net (14) (1) -
Other, net-affiliate 2 - -
Net cash provided by operating activities 1,937 1,424 1,161
Cash flows from investing activities
Property, plant and equipment (612) (916) (1,282)
Other - - (1)
Net cash used in investing activities (612) (916) (1,283)
Cash flows from financing activities
Proceeds from issuances of debt 482 1,995 -
Redemptions and repayments of debt (1,000) (2,000) -
Debt issuance and other financing costs (5) (35) -
Debt extinguishment costs (3) (39) -
Capital contributions 821 488 1,046
Distributions (1,619) (1,001) (1,499)
Net cash used in financing activities (1,324) (592) (453)
Net increase (decrease) in restricted cash and cash equivalents 1 (84) (575)
Restricted cash and cash equivalents-beginning of period 97 181 756
Restricted cash and cash equivalents-end of period $ 98 $ 97 $ 181
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1-ORGANIZATION AND NATURE OF OPERATIONS
We are a Delaware limited liability company formed by CQP. We are a Houston-based company with one member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of CQP. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of CQP, a publicly traded limited partnership (NYSE MKT: CQP). CQP is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses. Cheniere also owns 100% of the general partner interest in CQP through ownership in Cheniere Energy Partners GP, LLC.
The Sabine Pass LNG terminal currently has six operational natural gas liquefaction Trains, with Train 6 achieving 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 is located in Cameron Parish, Louisiana, adjacent to the existing regasification facilities owned by SPLNG.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Financial Statements have been prepared in accordance with GAAP. When necessary, reclassifications that are not material to our Financial Statements are made to prior period financial information to conform to the current year presentation.
Use of Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment and asset retirement obligations (“AROs”) as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7-Derivative Instruments.
The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10-Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
Revenue Recognition
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 11-Revenues from Contracts with Customers for further discussion of our revenue streams and accounting policies related to revenue recognition.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents
Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets.
Accounts and Other Receivables
Accounts and other receivables are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Statements of Income. As of both December 31, 2021 and 2020, we had current expected credit losses on our accounts and other receivables of $5 million.
Inventory
LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or capitalized to property, plant and equipment when issued, primarily using the weighted average method.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.
Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets.
We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.
We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives. Refer to Note 6-Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.
We recorded $5 million of impairments related to property, plant and equipment during the year ended December 31, 2021. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2020 and 2019.
Interest Capitalization
We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis.
Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2021, 2020 and 2019. See Note 7-Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.
We have entered into fixed price long-term SPAs generally with terms of 20 years with eight third parties and have entered into agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.
See Note 14-Customer Concentration for additional details about our customer concentration.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.
Debt
Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in loss on modification or extinguishment of debt on our Statements of Income.
We classify debt on our Balance Sheets based on contractual maturity, with the following exceptions:
•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.
•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.
Income Taxes
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss included in the federal income tax return of CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements. At December 31, 2021, the tax basis of our assets and liabilities was $7.2 billion less than the reported amounts of our assets and liabilities. See Note 12-Related Party Transactions for details about income taxes under our tax sharing agreement.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
Business Segment
Our liquefaction operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of SPL in total when evaluating financial performance and for purposes of allocating resources.
Recent Accounting Standards
In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.
NOTE 3-RESTRICTED CASH AND CASH EQUIVALENTS
Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. As of December 31, 2021 and 2020, we had $98 million and $97 million of restricted cash and cash equivalents, respectively.
Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.
NOTE 4-ACCOUNTS AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES
As of December 31, 2021 and 2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions):
December 31,
2021 2020
Trade receivable $ 546 $ 300
Other accounts receivable 25 9
Total accounts and other receivables, net of current expected credit losses $ 571 $ 309
NOTE 5-INVENTORY
As of December 31, 2021 and 2020, inventory consisted of the following (in millions):
December 31,
2021 2020
Materials $ 71 $ 68
LNG 44 8
Natural gas 43 17
Other 1 -
Total inventory $ 159 $ 93
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
NOTE 6-PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION
As of December 31, 2021 and 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):
December 31,
2021 2020
LNG terminal
LNG terminal $ 13,751 $ 13,711
LNG terminal construction-in-process 2,699 2,100
Accumulated depreciation (2,021) (1,561)
Total LNG terminal, net of accumulated depreciation 14,429 14,250
Fixed assets
Fixed assets 19 19
Accumulated depreciation (15) (14)
Total fixed assets, net of accumulated depreciation 4 5
Property, plant and equipment, net of accumulated depreciation $ 14,433 $ 14,255
The following table shows depreciation expense and offsets to LNG terminal costs during the years ended December 31, 2021, 2020 and 2019 (in millions):
Year Ended December 31,
2021 2020 2019
Depreciation expense $ 463 $ 460 $ 442
Offsets to LNG terminal costs (1) 105 - 48
(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.
LNG Terminal Costs
LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and 50 years, as follows:
Components Useful life (years)
Water pipelines 30
Liquefaction processing equipment 6-50
Other 10-30
Fixed Assets
Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
NOTE 7-DERIVATIVE INSTRUMENTS
We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”).
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Statements of Operations to the extent not utilized for the commissioning process, in which case it is capitalized.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2021 and 2020 (in millions):
Fair Value Measurements as of
December 31, 2021 December 31, 2020
Quoted Prices in Active Markets
(Level 1) Significant Other Observable Inputs
(Level 2) Significant Unobservable Inputs
(Level 3) Total Quoted Prices in Active Markets
(Level 1) Significant Other Observable Inputs
(Level 2) Significant Unobservable Inputs
(Level 3) Total
Liquefaction Supply Derivatives asset (liability) $ 2 $ (13) $ 38 $ 27 $ 1 $ (1) $ (21) $ (21)
We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.
The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value.
We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.
The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2021:
Net Fair Value Asset
(in millions) Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives $38 Market approach incorporating present value techniques Henry Hub basis spread $(1.368) - $0.250 / $0.012
(1)Unobservable inputs were weighted by the relative fair value of the instruments.
Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.
The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2021, 2020 and 2019 (in millions):
Year Ended December 31,
2021 2020 2019
Balance, beginning of period $ (21) $ 24 $ (25)
Realized and mark-to-market gains (losses):
Included in cost of sales 74 (43) 6
Purchases and settlements:
Purchases (10) 5 -
Settlements (5) (7) 42
Transfers out of Level 3, net (1) - - 1
Balance, end of period $ 38 $ (21) $ 24
Change in unrealized gain (loss) relating to instruments still held at end of period $ 74 $ (43) $ 6
(1)Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
Liquefaction Supply Derivatives
We have entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.
The notional natural gas position of our Liquefaction Supply Derivatives was approximately 5,194 TBtu and 4,970 TBtu as of December 31, 2021 and 2020, respectively.
Fair Value and Location of Derivative Assets and Liabilities on the Balance Sheets
The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions):
Fair Value Measurements as of (1)
Balance Sheets Location December 31, 2021 December 31, 2020
Current derivative assets $ 21 $ 14
Derivative assets 33 11
Total derivative assets 54 25
Current derivative liabilities (16) (11)
Derivative liabilities (11) (35)
Total derivative liabilities (27) (46)
Derivative asset (liability), net $ 27 $ (21)
(1)Does not include collateral posted with counterparties by us of $7 million and $4 million, which are included in other current assets in our Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract that we had with a related party, which had a fair value of zero as of December 31, 2020. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12-Related Party Transactions.
The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions):
Gain (Loss) Recognized in Statements of Operations
Statements of Operations Location (1) Year Ended December 31,
2021 2020 2019
LNG revenues $ (1) $ - $ 1
Cost of sales 30 (49) 71
Cost of sales-related party (2) 2 - -
(1)Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(2)Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12-Related Party Transactions.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
Balance Sheets Presentation
Our derivative instruments are presented on a net basis on our Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):
Liquefaction Supply Derivatives
As of December 31, 2021
Gross assets $ 79
Offsetting amounts (25)
Net assets $ 54
Gross liabilities $ (33)
Offsetting amounts 6
Net liabilities $ (27)
As of December 31, 2020
Gross assets $ 69
Offsetting amounts (44)
Net assets $ 25
Gross liabilities $ (48)
Offsetting amounts 2
Net liabilities $ (46)
NOTE 8-OTHER NON-CURRENT ASSETS, NET
As of December 31, 2021 and 2020, other non-current assets, net consisted of the following (in millions):
December 31,
2021 2020
Advances made to municipalities for water system enhancements $ 81 $ 84
Advances and other asset conveyances to third parties to support LNG terminal 37 33
Operating lease assets 23 23
Advances made under EPC and non-EPC contracts 5 9
Information technology service prepayments 4 5
Other 21 11
Total other non-current assets, net $ 171 $ 165
NOTE 9-ACCRUED LIABILITIES
As of December 31, 2021 and 2020, accrued liabilities consisted of the following (in millions):
December 31,
2021 2020
Accrued natural gas purchases $ 786 $ 374
Interest costs and related debt fees 133 150
Liquefaction Project costs 89 64
Other accrued liabilities 4 3
Total accrued liabilities $ 1,012 $ 591
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
NOTE 10-DEBT
As of December 31, 2021 and 2020, our debt consisted of the following (in millions):
December 31,
2021 2020
Senior Secured Notes:
6.25% due 2022
$ - $ 1,000
5.625% due 2023
1,500 1,500
5.75% due 2024
2,000 2,000
5.625% due 2025
2,000 2,000
5.875% due 2026
1,500 1,500
5.00% due 2027
1,500 1,500
4.200% due 2028
1,350 1,350
4.500% due 2030
2,000 2,000
4.27% weighted average rate due 2037
1,282 800
Total Senior Secured Notes 13,132 13,650
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”)
- -
Total debt 13,132 13,650
Unamortized premium, discount and debt issuance costs, net (109) (130)
Total debt, net of premium, discount and debt issuance costs $ 13,023 $ 13,520
Senior Secured Notes
The Senior Secured Notes are our senior secured obligations, ranking equally in right of payment with our other existing and future senior debt and secured by the same collateral and senior in right of payment to any of its future subordinated debt. Subject to permitted liens, the Senior Secured Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in us and substantially all of our assets. We may, at any time, redeem all or part of the Senior Secured Notes at specified prices set forth in the respective indentures governing the Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. The series of Senior Secured Notes due in 2037 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2021 (in millions):
Years Ending December 31, Principal Payments
2022 $ -
2023 1,500
2024 2,000
2025 2,037
2026 1,579
Thereafter 6,016
Total $ 13,132
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
2020 Working Capital Facility
Below is a summary of our 2020 Working Capital Facility as of December 31, 2021 (in millions):
2020 Working Capital Facility (1)
Original facility size $ 1,200
Less:
Outstanding balance -
Letters of credit issued 395
Available commitment $ 805
Priority ranking Senior secured
Interest rate on available balance LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%
Weighted average interest rate of outstanding balance n/a
Commitment fees on undrawn balance 0.20%
Maturity date March 19, 2025
(1)Our obligations under the 2020 Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu basis by a first priority lien with the Senior Secured Notes.
Restrictive Debt Covenants
The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit our ability to make certain investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, deposits are made into any required debt service reserve accounts and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.
As of December 31, 2021, we were in compliance with all covenants related to our debt agreements.
Interest Expense
Total interest expense, net of capitalized interest consisted of the following (in millions):
Year Ended December 31,
2021 2020 2019
Total interest cost $ 754 $ 779 $ 790
Capitalized interest (132) (94) (85)
Total interest expense, net of capitalized interest $ 622 $ 685 $ 705
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
Fair Value Disclosures
The following table shows the carrying amount and estimated fair value of our debt (in millions):
December 31, 2021 December 31, 2020
Carrying
Amount Estimated
Fair Value Carrying
Amount Estimated
Fair Value
Senior notes - Level 2 (1) $ 11,850 $ 13,128 $ 12,850 $ 14,834
Senior notes - Level 3 (2) 1,282 1,466 800 1,036
Working capital facility - Level 3 (3) - - - -
(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
NOTE 11-REVENUES FROM CONTRACTS WITH CUSTOMERS
The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2021, 2020 and 2019 (in millions):
Year Ended December 31,
2021 2020 2019
LNG revenues (1) $ 7,640 $ 5,195 $ 5,210
LNG revenues-affiliate 1,472 662 1,312
LNG revenues-related party 1 - -
Total revenues from customers 9,113 5,857 6,522
Net derivative gain (loss) (2) (1) - 1
Total revenues $ 9,112 $ 5,857 $ 6,523
(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2021 and 2019. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.
(2)See Note 7-Derivative Instruments for additional information about our derivatives.
LNG Revenues
We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues-affiliate. See Note 12-Related Party Transactions for additional information regarding these agreements.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price.
Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.
Contract Assets and Liabilities
The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Balance Sheets (in millions):
December 31,
2021 2020
Contract assets, net of current expected credit losses $ 1 $ -
Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the year ended December 31, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.
The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Balance Sheets (in millions):
Year Ended December 31, 2021
Deferred revenue, beginning of period $ 114
Cash received but not yet recognized in revenue 132
Revenue recognized from prior period deferral (114)
Deferred revenue, end of period $ 132
The following table reflects the changes in our contract liabilities, which we classify as other non-current liabilities-affiliate on our Balance Sheets (in millions):
Year Ended December 31, 2021
Deferred revenue-affiliate, beginning of period $ -
Cash received but not yet recognized in revenue 2
Deferred revenue-affiliate, end of period $ 2
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
Transaction Price Allocated to Future Performance Obligations
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2021 and 2020:
December 31, 2021 December 31, 2020
Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1)
LNG revenues $ 49.3 9 $ 52.1 9
LNG revenues-affiliate 2.1 3 0.1 1
Total revenues $ 51.4 $ 52.2
(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 61% and 42% of our LNG revenues from contracts included in the table above during the years ended December 31, 2021 and 2020, respectively, were related to variable consideration received from customers. Approximately 96% and 100% of our LNG revenues-affiliate from contracts included in the table above during the years ended December 31, 2021 and 2020, respectively, were related to variable consideration received from customers.
We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
NOTE 12-RELATED PARTY TRANSACTIONS
Below is a summary of our related party transactions as reported on our Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions):
Year Ended December 31,
2021 2020 2019
LNG revenues-affiliate
Cheniere Marketing Agreements $ 1,453 $ 632 $ 1,309
Contracts for Sale and Purchase of Natural Gas and LNG 19 30 3
Total LNG revenues-affiliate 1,472 662 1,312
LNG revenues-related party
Natural Gas Transportation and Storage Agreements 1 - -
Cost of sales-affiliate
Cheniere Marketing Agreements 34 61 -
Cargo loading fees under TUA 43 33 40
Contracts for Sale and Purchase of Natural Gas and LNG 51 16 7
Total cost of sales-affiliate 128 110 47
Cost of sales-related party
Natural Gas Transportation and Storage Agreements 1 - -
Natural Gas Supply Agreements (1) 16 - -
Total cost of sales-related party 17 - -
Operating and maintenance expense-affiliate
TUA 266 265 261
Natural Gas Transportation Agreement 81 82 81
Services Agreements 109 118 107
LNG Site Sublease Agreement 1 1 1
Total operating and maintenance expense-affiliate 457 466 450
Operating and maintenance expense-related party
Natural Gas Transportation and Storage Agreements 46 13 -
General and administrative expense-affiliate
Services Agreements 61 71 79
(1)Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed below.
As of December 31, 2021 and 2020, we had $232 million and $185 million, respectively, of accounts receivable-affiliate under the agreements described below.
LNG Terminal-Related Agreements
Terminal Use Agreements
We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
CQP has guaranteed our obligations under our TUA. Cargo loading fees incurred under the TUA are recorded as cost of sales-affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process.
Cheniere Marketing Agreements
Cheniere Marketing SPA
Cheniere Marketing has an SPA (“Base SPA”) with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.
In May 2019, we and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by us to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo.
Cheniere Marketing Master SPA
We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement.
Cheniere Marketing Letter Agreements
Cheniere Marketing has letter agreements with us to purchase up to 306 cargoes to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub.
In December 2020, we and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes that were delivered in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu.
In December 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes that were delivered in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.
In May 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu that were delivered between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu.
Facility Swap Agreement
In August 2020, 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 operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Natural Gas Transportation and Storage Agreements
To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of CQP, and third party pipeline companies. These agreements with CTPL have a primary term that continues until 20 years from May 2016 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to two consecutive terms of 10 years. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise. As of both December 31, 2021 and 2020, we recorded due to affiliates of $8 million and $6 million, respectively, related to this agreement.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
We are also party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by the investment management company that indirectly acquired a portion of CQP’s limited partner interests in September 2020. In addition to the amounts recorded on our Statements of Operations in the table above, we recorded accrued liabilities-related party of $4 million as of both December 31, 2021 and 2020 with this related party.
Services Agreements
As of December 31, 2021 and 2020, we had $127 million and $122 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense-affiliate.
Cheniere Investments Information Technology Services Agreement
Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.
Liquefaction O&M Agreement
We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of CQP, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on our behalf, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train.
Liquefaction MSA
We have a management services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.
Natural Gas Supply Agreement
We were a party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party was partially owned by Blackstone, who also partially owns CQP’s limited partner interests. However, this entity was acquired by a non-related party on December 31, 2021; therefore, as of such date, this agreement ceased to be considered a related party agreement.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
LNG Site Sublease Agreement
We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple periods of 10 years with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements.
Cooperation Agreement
We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We conveyed $6 million in assets to SPLNG under this agreement during the year ended December 31, 2020. We did not convey any assets to SPLNG under this agreement during the year ended December 31, 2021.
Contracts for Sale and Purchase of Natural Gas and LNG
We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales-affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under these agreements is recorded as LNG revenues-affiliate.
State Tax Sharing Agreement
We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere and Cheniere has not demanded any such payments from us under the agreement. The agreement is effective for tax returns due on or after August 2012.
NOTE 13-COMMITMENTS AND CONTINGENCIES
We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain unconditional purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2021, are not recognized as liabilities but require disclosures in our Financial Statements.
LNG Terminal Commitments and Contingencies
EPC Contract
We have a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the EPC of Train 6 of the Liquefaction Project. The total contract price of the EPC contract for Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction is approximately $2.5 billion, reflecting amounts incurred under change orders through December 31, 2021. As of December 31, 2021, we had approximately $0.2 billion remaining under this contract.
Natural Gas Supply, Transportation and Storage Service Agreements
We have physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 10 years.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
Additionally, we have natural gas transportation and storage service agreements for the Liquefaction Project. The initial term of the natural gas transportation agreements range up to 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The initial terms of our natural gas storage service agreements range up to 10 years.
As of December 31, 2021, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in billions):
Years Ending December 31, Payments Due (1)
2022 $ 5.3
2023 3.7
2024 2.6
2025 1.7
2026 1.1
Thereafter 5.7
Total $ 20.1
(1)Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2021. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.
LNG TUAs
We have a TUA with SPLNG pursuant to which we have reserved approximately 2 Bcf/d of regasification capacity. See Note 12-Related Party Transactions for additional information regarding this TUA.
Additionally, we have a partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 5, we gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.
Services Agreements
We have certain services agreements with affiliates. See Note 12-Related Party Transactions for information regarding such agreements.
Environmental and Regulatory Matters
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.
Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In the opinion of management, as of December 31, 2021, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS-CONTINUED
NOTE 14-CUSTOMER CONCENTRATION
The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivable, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivable, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:
Percentage of Total Revenues from External Customers Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers
Year Ended December 31, December 31,
2021 2020 2019 2021 2020
Customer A 25% 25% 29% 29% 32%
Customer B 18% 19% 21% 17% 22%
Customer C 17% 18% 21% * *
Customer D 16% 16% 19% 14% 21%
Customer E 10% * * 13% *
Customer F * * * 12% *
* Less than 10%
The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.
Revenues from External Customers
Year Ended December 31,
2021 2020 2019
United States $ 2,550 $ 1,975 $ 1,854
India 1,342 970 1,113
South Korea 1,336 924 1,071
Ireland 1,237 842 989
United Kingdom 966 456 184
Other countries 208 28 -
Total $ 7,639 $ 5,195 $ 5,211
NOTE 15-SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in millions):
Year Ended December 31,
2021 2020 2019
Cash paid during the period for interest, net of amounts capitalized $ 615 $ 692 $ 678
Non-cash distributions to affiliates for conveyance of assets - 6 351
Right-of-use assets obtained in exchange for new operating lease liabilities - 3 -
The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $322 million, $207 million and $276 million as of December 31, 2021, 2020 and 2019, respectively.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 31, 2021, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included in our Financial Statements and is incorporated herein by reference.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE
Omitted pursuant to Instruction I of Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to Instruction I of Form 10-K.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS
Omitted pursuant to Instruction I of Form 10-K.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE
Omitted pursuant to Instruction I of Form 10-K.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2021 and 2020 (in millions):
Fiscal 2021 Fiscal 2020
Audit Fees $ 2 $ 2
Audit Fees-Audit fees for 2021 and 2020 include fees associated with the audit of our annual Financial Statements, reviews of our interim Financial Statements and services performed in connection with registration statements and debt offerings, including comfort letters and consents.
Audit-Related Fees-There were no audit-related fees in 2021 and 2020.
Tax Fees-There were no tax fees in 2021 and 2020.
Other Fees-There were no other fees in 2021 and 2020.
Auditor Pre-Approval Policy and Procedures
We are not a public company and we are not listed on any stock exchange. As a result, we are not required to, and do not, have an independent audit committee, a financial expert or a majority of independent directors. The audit committee of the general partner of CQP has approved all audit and non-audit services to be provided by the independent accountants and the fees for such services during the fiscal years ended December 31, 2021 and 2020.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)Financial Statements and Exhibits
(1)Financial Statements-Sabine Pass Liquefaction, LLC:
Management’s Report to the Member of Sabine Pass Liquefaction, LLC
Report of Independent Registered Public Accounting Firm
Statements of Income
Balance Sheets
Statements of Member’s Equity
Statements of Cash Flows
Notes to Financial Statements
(2)Financial Statement Schedules:
All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.
(3)Exhibits:
Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:
•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
•may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;
•may apply standards of materiality that differ from those of a reasonable investor; and
•were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
3.1 Certificate of Formation of the Company
SPL S-4 3.1 11/15/2013
3.2 First Amended and Restated Limited Liability Company Agreement of the Company
SPL S-4 3.2 11/15/2013
4.1 Indenture, dated as of February 1, 2013, by and among the Company, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee
CQP 8-K 4.1 2/4/2013
4.2 First Supplemental Indenture, dated as of April 16, 2013, between the Company and The Bank of New York Mellon, as Trustee
CQP 8-K 4.1.1 4/16/2013
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
4.3 Second Supplemental Indenture, dated as of April 16, 2013, between the Company and The Bank of New York Mellon, as Trustee
CQP 8-K 4.1.2 4/16/2013
4.4 Form of 5.625% Senior Secured Note due 2023 (Included as Exhibit A-1 to Exhibit 4.3 above)
CQP 8-K 4.1.2 4/16/2013
4.5 Third Supplemental Indenture, dated as of November 25, 2013, between the Company and The Bank of New York Mellon, as Trustee
CQP 8-K 4.1 11/25/2013
4.6 Fourth Supplemental Indenture, dated as of May 20, 2014, between the Company and The Bank of New York Mellon, as Trustee
CQP 8-K 4.1 5/22/2014
4.7 Form of 5.750% Senior Secured Note due 2024 (Included as Exhibit A-1 to Exhibit 4.7 above)
CQP 8-K 4.1 5/22/2014
4.8 Fifth Supplemental Indenture, dated as of May 20, 2014, between the Company and The Bank of New York Mellon, as Trustee
CQP 8-K 4.2 5/22/2014
4.9 Form of 5.625% Senior Secured Note due 2023 (Included as Exhibit A-1 to Exhibit 4.9 above)
CQP 8-K 4.2 5/22/2014
4.10 Sixth Supplemental Indenture, dated as of March 3, 2015, between the Company and The Bank of New York Mellon, as Trustee
CQP 8-K 4.1 3/3/2015
4.11 Form of 5.625% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.11 above)
CQP 8-K 4.1 3/3/2015
4.12 Seventh Supplemental Indenture, dated as of June 14, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture
CQP 8-K 4.1 6/14/2016
4.13 Form of 5.875% Senior Secured Note due 2026 (Included as Exhibit A-1 to Exhibit 4.13 above)
CQP 8-K 4.1 6/14/2016
4.14 Eighth Supplemental Indenture, dated as of September 19, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture
CQP 8-K 4.1 9/23/2016
4.15 Ninth Supplemental Indenture, dated as of September 23, 2016, between the Company and The Bank of New York Mellon, as Trustee under the Indenture
CQP 8-K 4.2 9/23/2016
4.16 Form of 5.00% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.16 above)
CQP 8-K 4.2 9/23/2016
4.17 Tenth Supplemental Indenture, dated as of March 6, 2017, between the Company and The Bank of New York Mellon, as Trustee under the Indenture
CQP 8-K 4.1 3/6/2017
4.18 Form of 4.200% Senior Secured Note due 2028 (Included as Exhibit A-1 to Exhibit 4.18 above)
CQP 8-K 4.1 3/6/2017
4.19 Eleventh Supplemental Indenture, dated as of May 8, 2020, between the Company and The Bank of New York Mellon, as Trustee under the Indenture
SPL 8-K 4.1 5/8/2020
4.20 Form of 4.500% Senior Secured Note due 2030 (Included as Exhibit A-1 to Exhibit 4.20 above)
SPL 8-K 4.1 5/8/2020
4.21 Indenture, dated as of February 24, 2017, between the Company, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as Trustee under the Indenture
CQP 8-K 4.1 2/27/2017
4.22 Form of 5.00% Senior Secured Note due 2037 (Included as Exhibit A-1 to Exhibit 4.22 above)
CQP 8-K 4.1 2/27/2017
4.23* Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee
4.24* Form of 2.95% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.23 above)
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
4.25* Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee
4.26* Form of 3.17% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.25 above)
4.27* First Supplemental Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee
4.28* Form of 3.19% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.27 above)
4.29* Second Supplemental Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee
4.30* Form of 3.08% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.29 above)
4.31* Third Supplemental Indenture, dated as of December 15, 2021, between the Company and The Bank of New York Mellon, as Trustee
4.32* Form of 3.10% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.31 above)
10.1 LNG Sale and Purchase Agreement (FOB), dated November 21, 2011, between the Company (Seller) and Gas Natural Aprovisionamientos SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)
CQP 8-K 10.1 11/21/2011
10.2 Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated April 3, 2013, between the Company (Seller) and Gas Natural Aprovisionamientos SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)
CQP 10-Q 10.1 5/3/2013
10.3 Amendment of LNG Sale and Purchase Agreement (FOB), dated January 12, 2017, between the Company (Seller) and Gas Natural Fenosa LNG GOM, Limited (assignee of Gas Natural Aprovisionamientos SDG S.A.) (Buyer)
SPL
(SEC File No. 333-215882)
S-4 10.3 2/3/2017
10.4 LNG Sale and Purchase Agreement (FOB), dated December 11, 2011, between the Company (Seller) and GAIL (India) Limited (Buyer)
CQP 8-K 10.1 12/12/2011
10.5 Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between the Company (Seller) and GAIL (India) Limited (Buyer)
CQP 10-K 10.18 2/22/2013
10.6 Amended and Restated LNG Sale and Purchase Agreement (FOB), dated January 25, 2012, between the Company (Seller) and BG Gulf Coast LNG, LLC (Buyer)
CQP 8-K 10.1 1/26/2012
10.7 LNG Sale and Purchase Agreement (FOB), dated January 30, 2012, between the Company (Seller) and Korea Gas Corporation (Buyer)
CQP 8-K 10.1 1/30/2012
10.8 Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between the Company (Seller) and Korea Gas Corporation (Buyer)
CQP 10-K 10.19 2/22/2013
10.9 Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company (Seller) and Cheniere Marketing, LLC (Buyer)
SPL 8-K 10.1 8/11/2014
10.10 Letter agreement, dated December 8, 2016, amending the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)
SPL 10-K 10.14 2/24/2017
10.11 Amendment No. 1 of Amended and Restated LNG Sale and Purchase Agreement, dated May 3, 2019, by and between the Company and Cheniere Marketing International LLP
SPL 10-Q 10.1 5/9/2019
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.12 Letter Agreement, dated December 9, 2020, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC).
SPL 8-K 10.1 12/9/2020
10.13 Letter Agreement, dated August 4, 2021, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)
SPL 10-Q 10.2 8/5/2021
10.14 Letter Agreement, dated August 4, 2021, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)
SPL 10-Q 10.3 8/5/2021
10.15 Letter agreement, dated November 3, 2021, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)
SPL 10-Q 10.3 11/4/2021
10.16 Letter Agreement, dated November 24, 2021, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between the Company and Cheniere Marketing International LLP (as assignee of Cheniere Marketing, LLC)
SPL 8-K 10.1 11/26/2021
10.17 Management Services Agreement, dated May 14, 2012, by and between Cheniere Terminals and the Company
CQP 8-K 10.6 5/15/2012
10.18 Amendment to Management Services Agreement, dated September 28, 2015, between Cheniere Terminals and the Company
SPL 10-Q/A 10.8 11/9/2015
10.19 Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated May 14, 2012, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and the Company
CQP 8-K 10.5 5/15/2012
10.20 Assignment and Assumption Agreement (Sabine Pass Liquefaction O&M Agreement), dated as of November 20, 2013, by and between Cheniere Energy Partners GP, LLC and Cheniere Investments
Cheniere Holdings S-1/A 10.76 12/2/2013
10.21 Amendment to Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated September 28, 2015, by and among Cheniere LNG O&M Services, LLC, Cheniere Investments and the Company
SPL 10-Q/A 10.7 11/9/2015
10.22 Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.)
SPL 8-K 10.1 11/9/2018
10.23 Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: the Change Order CO-00001 Modifications to Insurance Language Change Order, dated June 3, 2019
SPL 10-Q 10.3 8/8/2019
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.24 Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00002 Fuel Provisional Sum Closure, dated July 8, 2019, (ii) the Change Order CO-00003 Currency Provisional Sum Closure, dated July 8, 2019, (iii) the Change Order CO-00004 Foreign Trade Zone, dated July 2, 2019, (iv) the Change Order CO-00005 NGPL Gate Access Security Coordination Provisional Sum, dated July 17, 2019, (v) the Change Order CO-00006 Alternate to Adams Valves, dated August 14, 2019, (vi) the Change Order CO-00007 E-1503 to HRU Permanent Drain Piping, dated August 14, 2019, (vii) the Change Order CO-00008 Differing Subsurface Soil Conditions - Train 6 ISBL, dated August 27, 2019, (viii) the Change Order CO-00009 LNG Berth 3, dated September 25, 2019 and (iv) the Change Order CO-00010 Cold Box Redesign and Addition of Inspection Boxes on Methane Cold Box, dated September 16, 2019
SPL 10-Q 10.1 11/1/2019
10.25 Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00011 Insurance Provisional Sum Interim Adjustment, dated October 1, 2019 and (ii) the Change Order CO-00012 Replacement of Timber Piles with Pre-Stressed Concrete Piles, dated October 30, 2019
SPL 10-K 10.23 2/24/2020
10.26 Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00013 Cost to Comply with SPL FTZ (FTZ entries, bonded transports and receipts for AG Pipe Spools Only), dated February 10, 2020, (ii) the Change Order CO-00014 Permanent Access Road to Third Berth, dated February 10, 2020, (iii) the Change Order CO-00015 Modifications to Schedule Bonus Language, dated February 10, 2020, (iv) the Change Order CO-00016 LNG Berth 3 LNTP No 3, dated January 31, 2020 and (v) the Change Order CO-00017 Construction Doc Fender Guards and LP Fuel Gas Overpressure Interlock, dated March 18, 2020
SPL 10-Q 10.4 4/30/2020
10.27 Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00018 Electrical Studies for GTG Grid Modification, dated April 2, 2020, (ii) the Change Order CO-00019 Third Berth - Change in 5kV Electrical Tie-In, dated April 30, 2020, (iii) the Change Order CO-00020 LNG Berth 3 LNTP No. 4, dated May 4, 2020, (iv) the Change Order CO-00021 Train 6 P1601 A/B/ Flange Changes, dated May 27, 2020 and (v) the Change Order CO-00022 Train 6 H2S Skid Modifications to Level Transmitters & GTG Pressure Range Change on PT-573 A/B, dated June 4, 2020
SPL 10-Q 10.2 8/6/2020
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.28 Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00023 Third Berth Vapor Fence Provisional Sum Scope Removal and Closeout, dated June 22, 2020, (ii) the Change Order CO-00024 Train 6 Thermowell Upgrades, dated June 22, 2020, (iii) the Change Order CO-00025 Third Berth Bubble Curtain, dated June 22, 2020, (iv) the Change Order CO-00026 Third Berth Fuel Provisional Sum Closure Change Order, dated July 14, 2020, (v) the Change Order CO-00027 Third Berth Currency Provisional Sum Closure Change Order, dated July 20, 2020, (vi) the Change Order CO-00028 Train 6 Hot Oil WHRU PSV Bypass, dated August 11, 2020 and (vii) the Change Order CO-00029 Change in Law IMO 2020 Regulatory Change - Low Sulphur Emissions on Marine Vessels, dated August 25, 2020
SPL 10-Q 10.1 11/6/2020
10.29 Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00030 Third Berth Soil Preparation Provisional Sum Interim Adjustment Change Order, dated September 16, 2020, (ii) the Change Order CO-00031 Provisional Sum Consolidation (PAB, Taxes & Insurance), dated October 2, 2020, (iii) the Change Order CO-00032 COVID-19 Impacts, dated October 2, 2020, (iv) the Change Order CO-00033 Third Berth - Jetty Building (00A-4041) - Clean Agent System, dated November 2, 2020 and (v) the Change Order CO-00034 Vanessa Spare Valves, dated November 18, 2020
SPL 10-K 10.26 2/24/2021
10.30 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00035 Impacts from Hurricanes Laura and Delta, dated December 22, 2020, (ii) the Change Order CO-00036 Third Berth - Add N2 Connection on Liquid & Hybrid SVT Loading Arm Apex, dated December 22, 2020, (iii) the Change Order CO-00037 Third Berth Design Vessels Update, dated December 22, 2020, (iv) the Change Order CO-00038 Train 6 PV-16002 & FV-15104 Valve Trim Upgrades, dated January 21, 2021, (v) the Change Order CO-00039 Third Berth Design Update to Supply Bunkering Fuel, dated February 11, 2021, (vi) the Change Order CO-00040 LNG Benchmark 7 Elevation Change, dated February 11, 2021, (vii) the Change Order CO-00041 Costs to Comply with SPL FTZ (Excluding Pipe Spools), dated February 12, 2021 and (viii) the Change Order CO-00042 COVID-19 Impacts 1Q2021, dated March 12, 2021
SPL 10-Q 10.1 5/4/2021
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.31 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00043 Third Berth SVT Loading Arm Spares, dated April 9, 2021, (ii) the Change Order CO-00044 Third Berth U/G Directional Drilling & Cathodic Protection Provisional Sum Closures, dated April 9, 2021, (iii) the Change Order CO-00045 Winter Storm Impacts, dated April 9, 2021, (iv) the Change Order CO-00046 NGPL Security Provisional Sum Interim Adjustment, dated June 15, 2021, (v) the Change Order CO-00047 80 Acres Bridge, dated June 15, 2021 and (vi) the Change Order CO-00048 AGRU Additions for Lean Solvent Overpressure, dated June 15, 2021
SPL 10-Q 10.1 8/5/2021
10.32 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00049 COVID-19 Impacts 2Q2021, dated July 6, 2021, (ii) CO-00050 Third Berth Bunkering Ship Modifications - Pre-Investment for Foundations, dated July 6, 2021, (iii) CO-00051 Thermal Oxidizer Controls Change, dated September 8, 2021, (iv) CO-00052 Third Berth Spare Beacon and Additional Cable Tray, dated September 8, 2021 and (v) CO-00053 Train 6 Gearbox Assembly Replacement for Unit 1411, dated September 24, 2021
SPL 10-Q 10.1 11/4/2021
10.33* Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00054 80 Acres Bridge Credit, dated November 30, 2021, (ii) CO-00055 Change in Law LPDES Permit - Water Treatment Filter Washing, dated December15, 2021, (iii) CO-00056 Impacts from Hurricane Ida, dated December 15, 2021 and (iv) CO-00057 Impacts from Hurricane Nicholas, dated December 15, 2021
10.34 Second Amended and Restated LNG Terminal Use Agreement, dated as of July 31, 2012, between the Company and SPLNG
SPLNG 8-K 10.1 8/6/2012
10.35 Letter Agreement, dated May 28, 2013, by and between the Company and SPLNG
SPLNG 10-Q 10.1 8/2/2013
10.36 Third Amended and Restated Common Terms Agreement, among the Company, as borrower, the Secured Debt Holder Group Representatives party thereto, the Secured Hedge Representatives party thereto, the Secured Gas Hedge Representatives party thereto and Société Générale, as the Common Security Trustee and the Intercreditor Agent
SPL 8-K 10.2 3/23/2020
10.37 First Amendment to Third Amended and Restated Common Terms Agreement, dated as of July 26, 2021, among the Company, as borrower, the Secured Debt Holder Group Representatives party thereto, the Secured Hedge Representatives party thereto, the Secured Gas Hedge Representatives party thereto and Société Générale, as the Common Security Trustee and the Intercreditor Agent
SPL 10-Q 10.2 11/4/2021
10.38 Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, among the Company, as borrower, certain subsidiaries of the Company, The Bank of Nova Scotia, as Senior Facility Agent, Société Générale, as the Common Security Trustee, the issuing banks and lenders from time to time party thereto and other participants
SPL 8-K 10.1 3/23/2020
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.39 Third Amended and Restated Accounts Agreement, among the Company, certain subsidiaries of the Company, Société Générale, as the Common Security Trustee, and Citibank, N.A. as the Accounts Bank
SPL 8-K 10.3 3/23/2020
10.40 Tax Sharing Agreement, dated as of August 9, 2012, by and between Cheniere and the Company
SPL S-4 10.30 11/15/2013
31.1* Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2* Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1** Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2** Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Labels Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
104* Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
(1) Exhibits are incorporated by reference to reports of Cheniere (SEC File No. 001-16383), CQP (SEC File No. 001-33366), Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (SEC File No. 333-191298), SPL (SEC File No. 333-192373) and SPLNG (SEC File No. 333-138916), as applicable, unless otherwise indicated.
* Filed herewith.
** Furnished herewith.