SPL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 17 years (plus extension rights) with eight third parties for Trains 1 through 6 of the SPL Project. Under these SPAs, the customers will purchase LNG from SPL 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 approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion for Trains 1 through 5. After giving effect to an SPA that Cheniere has committed to provide to SPL, by the end of 2020, the annual fixed fee portion to be paid by the third-party SPA customers would increase to at least $3.3 billion, which is expected to occur upon the date of first commercial delivery of Train 6.

The annual aggregate fixed fees for all of SPL’s other SPAs with third-parties is approximately $490 million, prior to giving effect to an SPA that Cheniere has committed to provide to SPL by the end of 2020.SPL.

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of December 31, 2019,2020, SPL had secured up to approximately 3,8504,950 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the SPL Project, under which Bechtel charges a lump sum for all work

performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 6 of the SPL Project is approximately $2.5 billion, including estimated costs for an optionalthe third marine berth.berth that is currently under construction. As of December 31, 2019,2020, we have incurred $1.1$1.9 billion under this contract.

 

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

The remaining approximately 2 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the years ended December 31, 2020, 2019 2018 and 2017,2018, SPL recorded $129 million, $104 million $30 million and $23$30 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Liquefaction Facilities

We are currently operating two Trains and onetwo marine berthberths at the CCL Project and are constructingcommissioning one additional Train and marine berth.that is expected to be substantially completed in the first quarter of 2021. 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 2019 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:

Separate from the CCH Group, we are also developing Corpus Christi Stage 3 through our subsidiary CCL Stage III, adjacent to the CCL Project. We received approval 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 December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations separately from long-term authorizations. Accordingly, the DOE amended each case,of CCL’s long-term authorizations to include short-term export authority, and vacated the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from seven to 10 years from the date the order was issued.short-term orders.

An application was filed in September 2019 to authorize additional exports from the CCL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 108 Bcf/yr of natural gas, for a total CCL Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the CCL Project of the volumes contemplated in the application. TheIn April 2020, the DOE issued an order authorizing CCL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing CCL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the CCL Project from the currently authorized level to approximately 875.16 Bcf/yr was also submitted to the FERC and is currently pending before DOE.pending.

CCL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 19 years (plus extension rights) with nine third parties for Trains 1 through 3 of the CCL Project. Under these SPAs, the customers will purchase LNG from CCL on a FOBfree 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 equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the CCL Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for the applicable Train, as specified in each SPA.

In aggregate, the minimum annual fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to approximately $1.4 billion upon the date of first commercial delivery for TrainTrains 1 and 2 and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the CCL Project.

The average annual aggregate contracted cash flow from fixed fees for all of CCL’s other SPAs with third-parties is approximately $790 million.

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline

CCL Stage III has also entered into long-term natural gas supply contracts with third parties, and anticipates continuing to enter into such agreements, in order to secure natural gas feedstock for Corpus Christi Stage 3. As of December 31, 2019,2020, CCL Stage III had secured up to approximately 2,361 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to approximately 15 years, which is subject to the achievement of certain project milestones and other conditions precedent.

A portion of the natural gas feedstock transactions for CCL and CCL Stage III are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.

CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 3 of the CCL Project under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause CCL to enter into a change order, or CCL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 3, which is currently under construction,undergoing commissioning, is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2019.2020. As of December 31, 2019,2020, we have incurred $2.0$2.4 billion under this contract.

FID for Corpus Christi Stage 3 will be subject to, among other things, entering into an EPC contract, obtaining additional commercial support for the project and securing the necessary financing arrangements.

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 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 be primarily sourced by LNG produced by the Liquefaction Projects but supplemented by volumes procured from other locations worldwide, as needed. As of December 31, 2019,2020, we have sold or have options to sell approximately 4,9354,995 TBtu of LNG to be delivered to customers between 20202021 and 2045, excluding volumes for agreements anticipatedincluding volume from an SPA Cheniere Marketing has committed to be assignedprovide to SPL in the future.SPL.  The cargoes

have been sold either on a FOB basis (delivered to the customer at the Sabine Pass LNG terminal or the Corpus Christi LNG terminal, as applicable) or a delivered at terminal (“DAT”) basis (delivered to the customer at their specified LNG receiving terminal). We have chartered LNG vessels to be utilized for cargoes sold on a DAT basis. In addition, we have entered into a long-term agreement to sell LNG cargoes on a DAT basis that is conditioned upon the buyer achieving certain milestones.

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

If and when SPL, CCL or our integrated marketing function need to replace any existing SPA or enter into new SPAs, they will compete on the basis of price per contracted volume of LNG with each other and other natural gas liquefaction projects throughout the world. Revenues associated with any incremental volumes, including those sold by our integrated marketing function discussed above, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to markets than us. We have proximity to our customers, with offices located in Houston, London, Singapore, Beijing and Tokyo.

SPLNG currently does not experience competition for its terminal capacity because the entire approximately 4 Bcf/d of regasification capacity that is available at the Sabine Pass LNG terminal has been fully contracted. If and when SPLNG has to replace any TUAs, it will compete with other then-existing LNG terminals for customers.

 

Our 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 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.

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

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

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

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 Denying Rehearing”). The party petitioned the relevant Court of Appeals to review the December 2014 Order and the Order Denying

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 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.

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.

In October 2019, PHMSA published final rules revising its regulations governing the safety of certain gas transmission pipelines (effective July 1, 2020) and established new enforcement procedures for the issuance of temporary emergency orders (effective December 2, 2019).

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

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 (“FWS”), 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, 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. The regulatory regime created by the Dodd-Frank Act is designed primarily to (1) regulate certain participants in the swaps markets, including entities falling within the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of 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 authority of the CFTC and the SEC regarding the derivativesthose markets. Most of the regulations are already in effect, while other rules and regulations, including the proposed marginnew rules on speculative position limits and commodity clearing requirements, remain to bethat were finalized or effectuated. Therefore,by the CFTC on October 15, 2020, are in the process of being phased in. The full impact of those 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 have adopted rules to require 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.

EMIR is an EU regulation (with text that is relevant across the European Economic Area (“EEA”)) designed to increase the transparency and stability of the EEA derivatives markets, including by: (1) imposing requirements on market participants trading derivatives, including relating to reporting, clearing and risk mitigation; and (2) imposing rules and standards that apply to central counterparties (i.e. clearing houses) and trade repositories. The precise impact of these rules will depend on a number of factors, including the regulatory status of the counterparty that is trading derivative instruments, as well as the volume and types of instruments it is trading. We currently are categorized under EMIR as a non-financial counterparty below the clearing threshold, which is a type of market participant subject to a lower regulatory burden. However, were we to engage in activities that resulted in a change to our status, we could be subject to more onerous regulations (including clearing and margining) which could significantly increase the cost of our derivatives trading activity, and materially alter the terms of the derivatives contracts we enter into.

We are eligible to trade on our own account in commodity derivatives as a result of the “ancillary activity” exemption under MiFID II. To avail ourselves of this exemption, amongst other things, we must be ableMAR was implemented to demonstrate, on the basis of a methodology set out in certain delegated MiFID II text, that our activities in commodity derivatives are ancillary to the main business of our group. Provided we meet the requirements, we must notify the UK regulator that we are availing ourselves of this exemption oncreate an annual basis. If, in the future, we are no longer able to meet the requirements of the “ancillary activity” exemption, and no other exemption is available to us, we would be required to become authorized as an investment firm under MiFID II. This may result in us being subject to the regulatory capital requirements under the EU’s Capital Requirements Directive IV.

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 which is currently scheduledending as of January 1, 2021. A trade deal (the “Deal”) was agreed and ratified by both sides, avoiding a “no deal” Brexit. One area notably absent from the Deal was financial services. The UK and EU will work towards agreeing a memorandum of understanding (the “MoU”) on access to end on December 31, 2020, as well as other factorsfinancial services by March 2021, although such an MoU would be less far-reaching than a legal text like an 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, the possible reclassification of products traded on UK exchanges for EU purposes and products traded on EU exchanges for UK purposes and possible impacts on our treatment relatedrules) remains to various regulatory statuses (e.g., clearing threshold classifications and other safe harbors and exemptions).  During this transition period,be resolved. It should be noted that the UK will also have the right to declare whether EU financial services rules are “equivalent” to its own rules, and each sides' equivalence decision will be made unilaterally, and could be withdrawn unilaterally as well. In contrast, the EU has taken a more limited approach. This includes, in the context of EMIR, granting a finite equivalence decision for the UK's legal regime for central counterparties (“CCPs”) established in the UK until June 30, 2022. Furthermore, the EU has recognized the CCPs ICE Clear Europe Limited, LCH Limited and LME Clear Limited as third country CCPs, with the effect that they may continue to offer their services in the EU.

  

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.

From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory action to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 

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 into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ, and in Texas, by the TCEQ).

 

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.

In August 2019, the U.S. Fish and Wildlife Service (the “FWS”)FWS announced a series of changes to the rules implementing the ESA, including revisions to the regulations governing interagency cooperation, listing species and delisting critical habitat, and prohibitions related to threatened wildlife and plants.plants, and in August and September 2020, the FWS proposed additional changes to its regulations for designating critical habitat. The revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions.

In addition, in December 2017, the Department of Interior’s (“DOI’s”) Solicitor’s Office issued an official opinion that the MBTA’s broad prohibition on “taking” migratory birds applies only to affirmative actions and does prohibit incidental harm. In April 2018, the FWS issued guidance consistent with the DOI’s opinion and on January 30, 2020,2021, the FWS issued a proposedfinal rule defining the scope of the MBTA to cover only actions intentionally directed at migratory birds, their nests or their eggs.

WeIt 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 facilities, will be materially and adversely affected by these recentsuch regulatory actions.

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 and economic growth in developing countries. 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, hundreds of billions of dollars are being invested across Europe and Asia in natural gas projects under construction, and if we included planned commitments, the total would exceed $1 trillion. Some examples include India’s commitment to invest over $60 billion to drive its gas-based economy, Europe’s commitment of well over $100 billion in gas-fired power, import terminals and pipelines, and China’s hundreds of billions all along the natural gas value chain. We highlight regasification capacity, which will not only expand existing import capacities in rapidly growing markets like China and India, but also add new import markets all over the globe, raising the total to approximately 60 by 2030 from 43 today and just 15 markets as recently as 2005.

As a result of these dynamics, global demand for natural gas is projected by the International Energy Agency to grow by approximately 2721 trillion cubic feet (“Tcf”) between 20182019 and 2030 and 3942 Tcf between 20182019 and 2035.2040. LNG’s share is seen growing from about 11%12% in 20182019 to about 16% of the global gas market in 2030 and 18%19% in 2035.2040.  Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 79%56%, from approximately 316347 mtpa, or 15.216.6 Tcf, in 2018,2019, to approximately 566541 mtpa, or 27.226.0 Tcf, in 2030 and to 678723 mtpa or 32.634.7 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 469476 mtpa in 2030, declining to 430381 mtpa in 2035.2040. This will result in a market need for

construction of an additional approximately 9765 mtpa of LNG production by 2030 and about 248343 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 and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Projects and Corpus Christi Stage 3 are competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

We have limited exposure to the decline in oil prices as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes.  We have contracted approximately 85% of the total production capacity from the Liquefaction Projects on a term basis, with approximately 18 years of average remaining life as of December 31, 2020, which includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, as well as volumes contracted under IPM gas supply agreements. As of January 31, 2020,2021, U.S. natural gas prices indicate that LNG exported from the U.S. continues to be competitively priced, supporting the opportunity for U.S. LNG to fill uncontracted future demand through the execution of long-term and medium-term contracting of LNG from our terminals.

Subsidiaries

 

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

 

WeAs of January 31, 2021, we had 1,5301,519 full-time employees with approximately 1,439 located in the U.S. and 80 located outside of the U.S (primarily in the UK).

Through our recruitment efforts, we seek top diverse talent who will continue to drive our strong performance. We have a competitive offering that provides us with a solid pipeline of candidates. 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. In addition, we actively recruit at Januarycolleges and conduct information sessions at select universities including Historically Black Colleges and Universities (HBCUs) and Hispanic-Serving Institutions (HSIs).

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 CEO, 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.  2020, we achieved zero employee recordable injuries, and our total recordable incident rate (employees and contractors combined) was 0.17.

Available Information

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.

Risks Relating to Our Business in General

 

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,

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 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, 201914 and 15, 2020. On January 20, 2021, President Biden issued an executive order directing the EPA’s June 19, 2019 adoption ofEPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the Affordable Clean EnergySeptember 2020 rule, for power generation. However, Congress or a future Administration may reverse these decisions. Otherwhich could result in more stringent GHG emissions rulemaking. In addition, other federal and state initiatives may be considered in the future to address GHG emissions through, for example, United States treaty commitments, direct regulation, market-based regulations such as a carbon emissions tax or cap-and-trade programs or clean energy standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations. We are supportive of regulations reducing GHG emissions over time.

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

Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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 construct and operate our facilities and pipelines and to provide our customers with the highest quality service. Our affiliates who hire personnel on our behalf 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 skilled workers or other general inflationary pressures, or 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.

We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers,

Substantially all of our anticipated revenue in 20202021 will be dependent upon our two facilities, the Sabine Pass LNG terminal located in southern Louisiana and the Corpus Christi LNG terminal in Texas. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG terminal or the Corpus Christi LNG terminal, including the related pipelines, or in the LNG industry, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. We test goodwill for impairment annually during the fourth quarter, or more frequently as circumstances dictate. Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced estimates of future cash flows for our business or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our goodwill or long-lived assets, we may be required to record a charge to earnings in our Consolidated Financial Statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.

In June 2019, our Board authorized a three-year, $1 billion share repurchase program and as of December 31, 2019,2020, up to $751$596 million remains available for repurchase. Our share repurchase program does not obligate us to acquire any particular amount of common stock. Our share repurchase program may be modified, suspended or terminated at any time, which may result in a decrease in the trading price of our common stock.

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.

 

None.

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. These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service. We continue to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation will have a material adverse impact on our financial results or operations.

Not applicable.