We shipped our first LNG cargo in February 2016 and we shipped our 1,000th cargo in January 2020.as of February 18, 2022, over 2,000 cumulative LNG cargoes totaling approximately 140 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects. Cheniere’s LNG has been shipped to over 3037 countries and regions around the world.

The SPL Project is one of the largest LNG production facilities in the world. Through Cheniere Partners,CQP we are currently operating fiveoperate six Trains, including Train 6 which achieved substantial completion on February 4, 2022, and two marine berths at the SPL Project, and are constructing one additional Train. We have received authorization froma third marine berth. The SPL Project has a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completionEPC of the first five TrainsTrain 6 of the SPL Project and commenced commercial operating activities for each Train at various times starting in May 2016.Project. The following table summarizes the project completion and construction status of Train 6 of the SPL Project as of December 31, 2019:

The following summarizes the volumes of natural gas for which we have received approvals from FERC to site, construct and operate the SPL Project and the orders we have been issued byreceived from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:terminal through December 31, 2050:

SPL has secured natural gas (approximately 10 mtpa).

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. ApproximatelySPLNG has entered into two long-term, third party TUAs for an aggregate of 2 Bcf/d, of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the regasification capacity they have reserved at the Sabine Pass LNG terminal. Each of Total and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually, prior to inflation adjustments, for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

We are currently operating twooperate three Trains and onetwo marine berthberths at the CCL Project and are constructing one additional Train and marine berth. We have received authorization from the FERC to site, construct and operate Trains 1 through 3 of the CCL Project. We completed construction of Trains 1 and 2 of the CCL Project and commenced commercial operating activities in February 2019of Trains 1, 2 and August 2019, respectively. The following table summarizes the project completion and construction status of Train 3 of the CCL Project including the related infrastructure, as of December 31, 2019:

The following summarizes the volumes of natural gas for which we have received approvalapprovals from FERC in November 2019 to site, construct and operate seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG.

In November 2019, the FERC authorized CCP to construct and operate the pipeline for Corpus Christi Stage 3. The pipeline will be designed to transport 1.5 Bcf/d of natural gas feedstock required by Corpus Christi Stage 3 from the existing regional natural gas pipeline grid.

We market and sell LNG produced by the Liquefaction Projects that is not required for other customers through Cheniere Marketing, our integrated marketing function. We have, and continue to develop, a portfolio of long-, medium- and short-term SPAs to transport and unload commercial LNG cargoes to locations worldwide. These volumes are expected to

The following table shows customers with revenues of 10% or greater of total revenues from external customers:

* Less than 10%

Our LNG terminals and pipelines are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.

The design, construction, operation, maintenance and expansion of our liquefaction facilities, the import or export of LNG and the purchase and transportation of natural gas in interstate commerce through our pipelines (including our Creole Trail Pipeline and Corpus Christi Pipeline) are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA.Natural Gas Act of 1938, as amended (the “NGA”). Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.

Under the NGA, our pipelines are not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including its own marketing affiliate. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified FERC’s policy in this area expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area. On February 18, 2022,

We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC with the issuance of our Certificate of Public Convenience and Necessity to our marketing affiliates. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.

In order to site, construct and operate our LNG terminals, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct, amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law.

The FERC issued its final ordersOrder Granting Section 3 Authority (“Order”) in April and July 2012 approving our application for an order under Section 3 of the NGA authorizing the siting, construction and operation of Trains 1 through 4 of the SPL 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 SPL Project, and in August 2013, the FERC issued an orderOrder approving the modifications. In October 2013, we applied to further amend the FERC approval, requesting authorization to increase the total permitted LNG production capacity of Trains 1 through 4 from the then authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity of Trains 1 through 4. In February 2014, the FERC issued an order approving the October 2013 application (the “February 2014 Order”). A party to the proceeding requested a rehearing of the February 2014 Order, and in September 2014, the FERC issued an order denying the rehearing request (the “FERC Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review the February 2014 Order and the FERC Order Denying Rehearing. The court denied the petition in June 2016. In September 2013, we filed an application with the FERC for authorization to add Trains 5 and 6 to the SPL Project, which was granted by the FERC in an orderOrder issued in April 2015 and an orderOrder denying rehearing issued in June 2015. These ordersOrders are not subject to appellate court review. In October of 2018, SPL applied to the FERC for authorization to add a third marine berth to the Sabine Pass LNG terminal facilities.facilities, which FERC approved in February of 2020. FERC issued written approval to commence site preparation work for the third berth in June 2020.

The Creole Trail Pipeline, which interconnects with the Sabine Pass LNG terminal, holds a certificate of public convenience and necessity from the FERC under Section 7 of the NGA. The FERC’s approval under Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, may beis required prior to making any modifications to the Creole Trail Pipeline as it is a regulated, interstate natural gas pipeline. In February 2013, the FERC approved CTPL’s application for authorization to construct, own, operate and maintain certain new facilities in order to enable bi-directional natural gas flow on the Creole Trail Pipeline system to allow for the delivery of up to 1,530,000 Dekatherms per day of feed gas to the Sabine Pass LNG terminal. In November 2013, CTPL received approval from the Louisiana Department of Environmental Quality (“LDEQ”) for the proposed modifications and with subsequent final FERC clearance, construction was completed in 2015. In September 2013, as part of the Application for Trains 5 and 6, we filed an application with the FERC for authorization to construct and operate an extension and expansion of Creole Trail Pipeline and related facilities in order to deliver additional domestic natural gas supplies to the Sabine Pass LNG terminal, which was granted by the FERC in an order issued in April 2015 and an order denying rehearing issued in June 2015. These orders are not subject to appellate court review.

In December 2014, the FERC issued an order granting CCL authorization under Section 3 of the NGA to site, construct and operate Trains 1 through 3 of the CCL Project and issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing construction and operation of the Corpus Christi Pipeline (the “December 2014 Order”). A party to the proceeding requested a rehearing of the December 2014 Order, and in May 2015, the FERC denied rehearing (the “Order

On September 27, 2019, CCL and SPL filed a request with the FERC pursuant to sectionSection 3 of the NGA, requesting authorization to increase the total LNG production capacity of each terminal from currently authorized levels to an amount which reflects more accurately the capacity of each facility based on enhancements during the engineering, design and construction process, as well as operational experience to date. The requested authorizations do not involve construction of new facilities. Corresponding applications for authorization to export the incremental volumes were also submitted to the DOE. The DOE issued Orders granting authorization to export LNG to FTA countries in April 2020. The DOE authorization for export to non-FTA countries is still pending. In October 2021, the FERC issued its Orders Amending Authorization under Section 3 of the NGA.

The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. The general principles of the FERC Standards of Conduct are: (1) independent functioning, which requires transmission function employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue preference due to the improper disclosure of non-public transmission function information. We have established the required policies, procedures and training to comply with the FERC’s Standards of Conduct.

All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

Several other material governmental and regulatory approvals and permits will be required throughout the life of our LNG terminals and our pipelines. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of our facilities. For example, throughout the life of our LNG terminals and our pipelines, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations have not materially affected our construction or operations.

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.

Our LNG terminals as well as the Creole Trail Pipeline and the Corpus Christi Pipeline are subject to regulation by PHMSA. PHMSA is authorized by the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation, maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.

PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $218,000$225,000 per day per violation, with a maximum administrative civil penalty of approximately $2$2.25 million for any related series of violations.

Construction and operation of the Sabine Pass LNG terminal and the CCL Project require 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 Services,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, the LDEQ, the Texas Commission on Environmental Quality (“TCEQ”) and the Railroad Commission of Texas (“RRC”).

The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10) (the “Section 10/404 Permit”). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the TCEQ and LDEQ to issue the Title V Operating Permit (the “Title V Permit”) and the Prevention of Significant Deterioration Permit (the “PSD Permit”). These two permits are issued by the LDEQ for the Sabine Pass LNG terminal and CTPL and by the TCEQ for the CCL Project.

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 that market.those markets. The regulatory regime created byCFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, is designed primarily to (1) regulate certain participants inincluding the swaps markets, including entities falling withinspeculative 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 categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of standardized swaps of certain classes as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authorityrecent enactment of the CFTC andspeculative position limit rules, as well as the SEC regarding the derivatives markets. Mostimpact of the regulations are already in effect, while other rules and regulations includingunder the proposed margin rules, position limits and commodity clearing requirements, remain to be finalized or effectuated. Therefore,Dodd-Frank Act, the impact of thosesuch rules and regulations on our business continues to be uncertain.

As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators havealso adopted rules to requirerequiring Swap Dealers and Major Swap Participants,(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 expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

In particular, under the UK Onshored Rules, firms engaging in investment services and activities under UK MiFID II must be authorized unless an exemption applies, and we qualify for an exemption and therefore do not need to entities trading on, or in a manner that impacts EU markets. MAR contains a number of “insider dealing” and “market manipulation” (including “attempted manipulation”) based offences. Under MAR, any person professionally arranging or executing transactions in financial instruments is required to establish and maintain effective arrangements, systems and procedures to detect and report suspicious orders and transactions.be authorized under UK MiFID II.

In addition to the variousUK Onshored Rules, we are also subject to a separate, UK-specific regime that is not based on prior EU/EEA rules described above, other UK-specific laws, such aslegislation. This is primarily set out in the UK’s Financial Services and Markets Act of 2002000 (“FSMA”) and Financial Services and Markets Act 2000 (Regulated Activities) Order 2001 (“RAO”), also applywhich, among other things, governs the regulation of financial services and markets in the UK, and contains a definitive list of the specified kinds of activities and products that are regulated. Under these UK-specific rules, a firm engaging in regulated activities must be authorized unless an exclusion applies. We qualify under applicable exclusions and therefore are not required to our trading activities.be authorized under the UK FSMA/RAO regime.

Any violation of the foregoing laws and regulations could result in investigations, and possible finefines and penalties, and in some scenarios, criminal offenses.offenses, as well as reputational damage.

The UK withdrew from the EU (“Brexit”) on January 31, 2020, and the withdrawal may have an impact on the applicability of the current EU Regulations and Directives that govern our various trading activities. The precise impacts will depend on the negotiations that will occur duringwith the transition period ending as of January 1, 2021. A trade deal (the “Deal”) was agreed and ratified by both the UK and the EU, avoiding a “no deal” Brexit.

One area notably absent from the Deal was financial services. The UK and EU are working towards formally agreeing a memorandum of understanding (the “MoU”) on access to financial services, the text of which is currently scheduledwas agreed in principle in March 2021. This was expected to end on December 31, 2020,be formally ratified and published in 2021, but so far this has not occurred. In any event, an MoU would be less far-reaching than a legal text such as well as other factorsan international treaty.

The issue of whether the UK's financial system will be granted “equivalence” by the EU (the scenario that may or may not be addressed during the negotiations.  We anticipate that impacts could include a possible requirement to registerwould result in the least disruption and would treat compliance with UK rules as being equivalent to compliance with the corresponding EU for certain activities,rules) has not been resolved, and at present seems unlikely to be agreed. The UK also has the possible reclassification of products traded onright to declare whether EU

Additionally, there is no guarantee that any equivalence decision, if granted, will be comprehensive across all financial services. In the meantime, UK exchanges for EU purposes and products traded on EU exchanges for UK purposes and possible impacts on our treatment related to various regulatory statuses (e.g., clearing threshold classifications and other safe harbors and exemptions).  During this transition period,firms must comply with the UK will continue to be subject to EU Regulations and Rules, with the objective being to provide as smooth a transition as possible for businesses.  Until additional clarity surrounding Brexit is obtained, other impacts pertaining to our trading activities could occur.Onshored Rules.

Our LNG terminals are 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.

Our LNG terminals are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by any such requirements.

In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of greenhouse gas (“GHG”) emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules havewere largely been stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and additional proposed amendments to new source performance standards for the oil and gas industry on September 24, 2019,14 and 15, 2020. On November 15, 2021, the EPA’s June 19, 2019 adoptionEPA 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 Affordable Clean Energy rulefirst time, establish emissions guidelines for power generation.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.

The siting and construction of our LNG terminals 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.

Our LNG terminals are 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

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.

Various federal and state statutes, such as the Endangered Species Act, (the “ESA”), the Migratory Bird Treaty Act, (“MBTA”), the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If one of our LNG terminals or pipelines adversely affects 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 Wildlife Service (the “FWS”) announced a series of changes to the rules implementing the ESA, including revisions to the regulations governing interagency cooperation, listing specieswetlands and delisting critical habitat, and prohibitions related to threatened wildlife and plants. The revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions.

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, and economic growth in developing countries.countries and other related factors such as the effects of the COVID-19 pandemic. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our 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. GlobalPlayers 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 2720 trillion cubic feet (“Tcf”) between 20182020 and 2030 and 3933 Tcf between 20182020 and 2035.2040. LNG’s share is seen growing from about 11% in 20182020 to about 16%12% of the global gas market in 2030 and 18%14% in 2035.2040. Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 79%57%, from approximately 316366.6 mtpa, or 15.217.6 Tcf, in 2018,2020, to approximately 566576.5 mtpa, or 27.227.7 Tcf, in 2030 and to 678734.5 mtpa or 32.635.3 Tcf in 2035.2040. WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 469517 mtpa in 2030, declining to 430456 mtpa in 2035.2040. This willcould result in a market need for construction of an additional approximately 9760 mtpa of LNG production by 2030 and about 248279 mtpa by 2035.2040. 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

We have limited exposure to the decline in oil pricesprice 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 85%95% of the total production capacity from the Liquefaction Projects, including those contracts executed to support Corpus Christi Stage 3. Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. Excluding contracts with terms less than 10 years, our SPAs and IPM agreements had approximately 17 years of weighted average remaining life as of December 31, 2021.

Despite the long term nature of our SPAs, when SPL, CCL or our integrated marketing function need to replace or amend any existing SPA or enter into new SPAs, they will compete with each other and other natural gas liquefaction projects throughout the world on a termthe basis which includes volumesof price per 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 deliveriesvolume of LNG cargoes, as well asat that time. Revenues associated with any incremental volumes, contracted under IPM gas supply agreements. Asincluding those sold by our integrated marketing function, will also be subject to market-based price competition. Many of January 31, 2020, U.S. natural gas prices indicatethe companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to LNG markets than us.

SPLNG currently does not experience competition for its terminal capacity because the entire approximately 4 Bcf/d of regasification capacity that is available at the Sabine Pass LNG exported from the U.S. continuesterminal has been fully contracted. If and when SPLNG has to be competitively priced, supporting the opportunityreplace any TUAs, it will compete with other then-existing LNG terminals for U.S. LNG to fill uncontracted future demand through the execution of long-term and medium-term contracting of LNG from our terminals.customers.

Our assets are generally held by our subsidiaries. We conduct most of our business through these subsidiaries, including the development, construction and operation of our LNG terminal business and the development and operation of our LNG and natural gas marketing business.

 

WeAs of January 31, 2022, we had 1,5301,550 full-time employees with 1,456 located in the U.S. and 94 located outside of the U.S. (primarily in the UK).

Through our recruitment efforts, we seek diverse talent to drive our corporate strategies and goals. We actively recruit at Januarycolleges and conduct information sessions at select universities, including Historically Black Colleges and Universities (“HBCUs”) and Hispanic-Serving Institutions. Internally and externally, we post openings to attract individuals with a range of backgrounds, skills and experience, offering employee bonuses for referring highly qualified candidates.

The safety of our employees, contractors and communities is one of our core values. Our Cheniere Integrated Management System defines our required safety programs and details safety and health related procedures. Safety efforts are led by our Executive Safety Committee, which includes the Chief Executive Officer, senior leaders from across the company, and representatives from each of our operating assets. We focus our efforts on continuously improving our performance. For the year ended December 31, 2020.  2021, we had one employee recordable injury and seven contractor recordable injuries. Our total recordable incident rate (employees and contractors combined) was 0.10, placing us in the top quartile of industry benchmarks based on Bureau of Labor safety statistics.

Our common stock has been publicly traded since March 24, 2003 and is traded on the NYSE American under the symbol “LNG.” Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our annual report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy, Inc., Investor Relations Department, 700 Milam Street Suite 1900, Houston, Texas 77002 or call (713) 375-5000. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers.

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.

Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2019, SPL2021, we had SPAs with eight third-party customers, CCL had SPAsterms of 10 or more years with nine third-party customers and our integrated marketing function had a limited numbertotal of SPAs with third-party24 different third party customers. In addition, SPLNG had TUAs with two third-partythird party customers. We

While substantially all of our long-term third party customer arrangements are dependent on each customer’s continued willingness and ability to perform its obligations under its SPAexecuted with a creditworthy parent company or TUA. Wesecured by a parent company guarantee or other form of collateral, we are nonetheless exposed to the credit risk of any guarantor of these customers’ obligations under their respective agreements 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 must seek recoursefail 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. Under each of SPLNG’s long-term TUAs, such termination events include, but are not limited to: if the Sabine Pass LNG terminal (1) experiences a guaranty. If any customerforce majeure delay for longer than 18 months; (2) fails to perform its obligations under its SPAredeliver a specified amount of natural gas in accordance with the customer’s redelivery nominations; or TUA,(3) fails to accept and unload a specified number of the customer’s proposed LNG cargoes.

Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the agreement.affected.

CCH is generally restricted from making distributions under agreements governing its indebtedness until, among other requirements, the completion of the construction of Trains 1 through 3 of the CCL Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.

Our subsidiaries’ inability to pay distributions to Cheniere PartnersCQP or us or to incur additional indebtedness as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit Cheniere Partners’CQP’s ability to pay or increase distributions to us and its other unitholders or inhibit our access to cash flows from the CCL Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Any restrictions on the ability to engage in beneficial transactions could materially and adversely affect us.

In addition, the United States securities markets have experienced significant price and volume fluctuations. These fluctuations have often been unrelated to the operating performance of companies in these markets. Market fluctuations and broad market, economic and industry factors may negatively affect the price of our common stock, regardless of our operating performance. If we were to be the object of securities class litigation as a result of volatility in our common stock price or for other reasons, it could result in substantial diversion of our management’s attention and resources, which could negatively affect our financial results.

We expect to continue to pay quarterly dividends to our stockholders; however, our Board may reduce our usedividend or cease declaring dividends at any time, including if it determines that our net cash provided by operating activities, after deducting capital expenditures and investments, are not sufficient to pay our desired levels of swapsdividends to hedge our risks, suchstockholders or to pay dividends to our stockholders at all.

Additionally as commodity price risks that we encounter inof December 31, 2021, $998 million of repurchase authority remained of the $1 billion share repurchase program our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.

Any downward revision in increased costs and risksthe amount of dividends we pay to stockholders or the business similar to the impacts stated above with respect to the Dodd-Frank Act. The increased costs may alsonumber of shares we purchase under our share repurchase program could have an adverse impacteffect on the market price of our common stock.

We have historically pursued a number of alternatives in order to finance the construction of our Trains, including potential issuances and regulationssales of additional equity or equity-related securities by our subsidiaries. Such sales, in one or more transactions, could resultdilute our proportionate indirect interests in investigations,our assets, business operations and possible fines and penalties, and in some scenarios, criminal offenses.

Hurricanes Katrina and Rita in 2005, Hurricane Ike in 2008, and Hurricane Harvey in 2017, Hurricanes Laura and Delta in 2020 and Winter Storm Uri in 2021 caused interruptions or temporary suspension in construction ofor operations at our liquefaction projectsfacilities or caused minor damage to our liquefaction projects.facilities. 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, the Corpus Christi LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Liquefaction Projects, Corpus Christi Stage 3 or our other facilities

We will require significant additional funding to be able to commence construction of Corpus Christi Stage 3, and any additional expansion projects, which we may not be able to recover our investmentobtain at a cost that results in our projects. Additionally, government disruptions, such as a U.S. government shutdown,positive economics, or at all. The inability to achieve acceptable funding may delay or halt our ability to obtain and maintain necessary approvals and permits. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We depend upon third-partythird party pipelines and other facilities that provide gas delivery options to our liquefaction facilities and pipelines. 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 meet our SPA obligations andreceive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be restricted, thereby reducingadversely 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.

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.

Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of our LNG terminals and our pipelines the rates, termsare, and conditions of service and abandonment of facilities. Under the NGA, the rates charged by our interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines couldwill be, subject to substantial penaltiesthe inherent risks associated with these types of operations, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and fines.

We do not, own the land on which our pipelines are situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.

Although some agreements may adversely affect our operating results, liquidity and access to financing.

Furthermore, we may have disagreements with customers to sell LNG produced in excessour contractors about different elements of the aggregate annual contract quantitiescommittedconstruction process, which could lead to SPL’sthe assertion of rights and CCL’s third-party SPAs.

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,flow, liquidity and prospects.

Operations of the Liquefaction Projects 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

Although SPL has entered into arrangements to utilize up to approximately three-quarters of the regasification capacity at the Sabine Pass LNG terminal in connection with operations of the SPL Project, operations at the Sabine Pass LNG terminal are dependent, in part, upon the ability of our TUA customers to import LNG supplies into the United States, which is primarily dependent upon LNG being a competitive source of energy in North America. In North America, due mainly to a historically abundant supply of natural gas and discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the regasification services component of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to North America at a lower cost than the cost to produce some domestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas have recently been and may continue to be discovered in North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG.

Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction or regasification facilities in the United States.

As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or to the

The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our trading, marketing, pipeline, liquefaction and shipping operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Facilities. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should a multiple of the third party pipelines which supply our Liquefaction Facilities suffer similar concurrent attacks, the Liquefaction Facilities may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A terroristcyber attack cyber incidentinvolving our business or military incident involving an LNG facility, ouroperational control systems or related infrastructure, or an LNG vessel maythat of third party pipelines with which we do business, could negatively impact our operations, result in delaysdata 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.

We are dependent upon the available labor pool of constructionskilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of new LNG facilities, includingskilled 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 for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, 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.

The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Projects, Corpus Christi Stage 3 and other facilities, as well as increased costs,the import and dependingexport of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.

To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the SPL Project, the three Trains and related facilities of the CCL Project and the seven midscale Trains and related facilities for Corpus Christi Stage 3, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline, the Corpus Christi Pipeline and the pipeline for Corpus Christi Stage 3. To date, the DOE has also issued orders under Section 4 of the NGA authorizing SPL, CCL and Corpus Christi Stage 3 to export domestically produced LNG. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipelines on their ultimate magnitude,land owned by third parties. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with such conditions, or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns, could impede the operation and construction of our infrastructure. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and uninsured risks, one or morethe Natural Gas Policy Act of which may create significant liabilities1978 (the “NGPA”). The FERC regulates the purchase and losses for us.

In addition, our operationsas a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the facilities and vesselsNGPA to impose penalties for current violations of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.up to $1.3 million per day for each violation.

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

    

    

Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals 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.

We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to constructmaintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operate our facilitiesoperating expenditures. Should we fail to comply with applicable statutes and pipelinesthe Office of Pipeline Safety’s rules and to provide our customers with the highest quality service. Our affiliates who hire personnel on our behalf are alsorelated regulations and orders, we could be subject to the Fair Labor Standards Act,significant penalties and fines, which governs such mattersfor certain violations can aggregate up to as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressureshigh as $2.3 million.

None.

ITEM 3. LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

Certain of our subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG terminal and the commissioning of the SPL Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of our subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of our subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.

In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal.terminal (the “2018 SPL tank incident”). These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service. We continueIn July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to SPL alleging violations of federal pipeline safety regulations relating to the 2018 SPL tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200. On October 12, 2021, SPL responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. PHMSA notified SPL in a letter dated November 9, 2021 that the case was considered “closed.” SPL continues to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak,SPL tank incident, 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.

Not applicable.