PART I
General
We are a Delaware limited liability company formed by Cheniere Energy Partners, L.P. (“Cheniere Partners”) in June 2010.. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.
LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.
We are currently operating five natural gas liquefaction Trains and are constructing one additional Train that is expected to be substantially completed in the second half of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal, one of the largest LNG production facilities in the world. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast, adjacent to the existing regasification facilities owned and operated by Sabine Pass LNG, L.P. (“SPLNG”).
We remain focused on operational excellence and customer satisfaction. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG terminal, which provides opportunity for further liquefaction capacity expansion. Further development of the Sabine Pass LNG terminal will require, among other things, acceptable commercial and financing arrangements before we can make a final investment decision (“FID”).
Our Business Strategy
Our primary business strategy is to develop, construct and operate assets supported by long-term, fixed fee contracts. We plan to implement our strategy by:
•safely, efficiently and reliably operating and maintaining our Trains; • |
procuring natural gas to our facility;
•commencing commercial delivery for our long-term SPA customers, of which we have initiated for sixseven of eight long-term SPA customers as of December 31, 2019;2020;
•safely, on-time and on-budget completing construction and commencing operation of Train 6 of the Liquefaction Project; and
•maximizing the production of LNG to serve our long-term customers and generating steady and stable revenues and operating cash flows; and
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Liquefaction Facilities
The Liquefaction Project is one of the largest LNG production facilities in the world. We are currently operating five Trains and two marine berths at the Liquefaction Project, and are constructing one additional Train.Train that is expected to be substantially completed in the second half of 2022, and a third marine berth. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. Additionally, SPLNG has received authorization from the FERC for the construction of the third marine berth. We have achieved substantial completion of the first five Trains of the Liquefaction Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the Liquefaction Project as of December 31, 2019:
2020:
| Train 6 | |||||||||||
| Overall project completion percentage | |||||||||||
| Completion percentage of: | |||||||||||
| Engineering | |||||||||||
| Procurement | |||||||||||
| Subcontract work | |||||||||||
| Construction | |||||||||||
| Date of expected substantial completion | |||||||||||
The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:
•Trains 1 through 4—FTA countries for a 30-year term, which commenced in May 2016, and non-FTA countries for a 20-year term, which commenced in June 2016,through December 31, 2050, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).
•Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term, both of which commenced inthrough December 2018,31, 2050, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).
•Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, which partially commenced in June 2019 and the remainder commenced in September 2019,through December 31, 2050, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
In each case,December 2020, the terms of theseDOE announced a new policy in which it would no longer issue short-term export authorizations began onseparately from long-term authorizations. Accordingly, the earlier of the date of first export thereunder or the date specified in the particular order. In addition, we received an order providing for a three-year makeup period with respect toDOE amended each of our long-term authorizations to include short-term export authority, and vacated the non-FTA orders for LNG volumes we were authorized but unable to export during any portion of the initial 20-year export period of such order.short-term orders.
An application was filed in September 2019 seeking authorization to authorizemake additional exports from the Liquefaction Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 153 Bcf/yr of natural gas, for a total Liquefaction Project export capacity of approximately 1,662 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of the volumes contemplated in the application. TheIn April 2020, the DOE issued an order authorizing us 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 us to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the Liquefaction Project from the currently authorized level to approximately 1,662 Bcf/yr was also submitted to the FERC and is currently pending before DOE.pending.
Customers
We have entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 17 years (plus extension rights)with eight third parties for Trains 1 through 6 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 75% of the total production capacity from these Trains.Trains, potentially increasing up to approximately 85% after giving effect to an SPA that Cheniere has committed to provide to us. Under these SPAs, the customers will purchase LNG from us 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.
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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 fees under our 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 us, 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.
In addition, Cheniere Marketing has agreements with us to purchase: (1) at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers and (2) up to 4330 cargoes scheduled for delivery in 20202021 at a price of 115% of Henry Hub plus $1.67$0.728 per MMBtu.
The annual contracted cash flows from fixed fees of each buyer of LNG under our third-party SPAs that constitute more than 10% of the aggregate fixed fees under all our SPAs are:
•approximately $720 million from BG Gulf Coast LNG, LLC (“BG”), which is guaranteed by BG Energy Holdings Limited;
•approximately $550 million from Korea Gas Corporation (“KOGAS”);
•approximately $550 million from GAIL;
•approximately $450 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM, Limited) (“Naturgy”), which is guaranteed by Naturgy Energy Group, S.A. (formerly known as Gas Natural SDG S.A.); and
•approximately $310 million from Total Gas & Power North America, Inc. (“Total”), which is guaranteed by Total S.A.
The annual aggregate fixed fees for all of our other SPAs with third-parties is approximately $490 million, prior to giving effect to an SPA that Cheniere has committed to provide to us by the end of 2020.us.
The following table shows customers with revenues of 10% or greater of total revenues from external customers:
| Percentage of Total Revenues from External Customers | ||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||
| BG | 25% | 29% | 30% | |||||||||||||||||||||||||||||
| GAIL | 19% | 21% | 20% | |||||||||||||||||||||||||||||
| KOGAS | 18% | 21% | 24% | |||||||||||||||||||||||||||||
| Naturgy | 16% | 19% | 23% | |||||||||||||||||||||||||||||
| Percentage of Total Revenues from External Customers | ||||||
| Year Ended December 31, | ||||||
| 2019 | 2018 | 2017 | ||||
| BG | 29% | 30% | 43% | |||
| Naturgy | 19% | 23% | 30% | |||
| KOGAS | 21% | 24% | 25% | |||
| GAIL | 21% | 20% | —% | |||
Natural Gas Transportation, Storage and Supply
To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. We have entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project. We have also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2019,2020, we 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.
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Construction
We have entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause us to enter into a change order, or we agree with Bechtel to a change order.
The total contract price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion, including estimated costs for 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.
Terminal Use Agreements
We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. Cheniere Partners has guaranteed our obligations under our TUA. During the years ended December 31, 2020, 2019 2018 and 2017,2018, we recorded operating and maintenance expense—affiliate of $265 million, $261 million $256 million and $190$256 million, respectively, for the TUA Fees and cost of sales—affiliate of $33 million, $40 million $32 million and $23$32 million, respectively, for cargo loading services incurred under the TUA.
Additionally, we have entered into a partial TUA assignment agreement with Total, another TUA customer, whereby upon substantial completion of Train 5 of the Liquefaction Project, we gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit us to more flexibly manage our LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the years ended December 31, 2020, 2019 2018 and 2017,2018, we recorded $129 million, $104 million $30 million and $23$30 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.
Governmental Regulation
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.
Federal Energy Regulatory Commission
The design, construction, operation, maintenance and expansion of the Liquefaction Project are highly regulated activities subject to the jurisdiction of the FERC pursuant to the Natural Gas Act of 1938, as amended (the “NGA”). Under the NGA, the FERC’s jurisdiction generally extends to the sale for resale of natural gas in interstate commerce and to the construction, operation, maintenance and expansion of liquefaction facilities.
The FERC issued final orders in April and July 2012 approving our application for an order under Section 3 of the NGA authorizing the siting, construction and operation of Trains 1 through 4 of the Liquefaction Project (and related facilities). Subsequently, the FERC issued written approval to commence site preparation work for Trains 1 through 4. In October 2012, we applied to amend the FERC approval to reflect certain modifications to the Liquefaction Project, and in August 2013, the FERC issued an order approving the modifications. In October 2013, we applied to further amend the FERC approval, requesting authorization to increase the total permitted LNG production capacity of Trains 1 through 4 from the then authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity of Trains 1 through 4. In February 2014, the FERC issued an order approving the October 2013 application (the “February 2014 Order”). A party to the proceeding requested a rehearing of the February 2014 Order, and in September 2014, the FERC issued an order denying the rehearing request (the “FERC Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review the February 2014 Order and the FERC Order Denying
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Rehearing. The court denied the petition in June 2016. In September 2013, we filed an application with the FERC for authorization to add Trains 5 and 6 to the Liquefaction Project, which was granted by the FERC in an order issued in April 2015 and an order denying rehearing issued in June 2015. These orders are not subject to appellate court review. In October of 2018, SPLwe applied to the FERC for authorization to add a third marine berth to the Liquefaction Project.Project, which FERC approved in February of 2020.
On September 27, 2019, SPLwe filed a request with the FERC pursuant to sectionSection 3 of the NGA, requesting authorization to increase the total LNG production capacity of eachthe terminal from currently authorized levels to an amount which reflects more accurately the capacity of eachthe 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.
All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other material governmental and regulatory approvals and permits will be required throughout the life of the Liquefaction Project. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of the Liquefaction Project. For example, throughout the life of our liquefaction facility, we are subject to regular reporting requirements to the FERC, the U.S. Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facility. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations have not materially affected our construction or operations.
DOE Export LicenseLicenses
The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal as discussed in Liquefaction Facilities. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.
Under Section 3 of the NGA applications for exports of natural gas to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas.Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest.
Other Governmental Permits, Approvals and Authorizations
Construction and operation of the Liquefaction Project requires additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including notably 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 and the Louisiana Department of Environmental Quality (“LDEQ”).
The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10) (the “Section 10/404 Permit”). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the LDEQ to issue the Title V Operating Permit (the “Title V Permit”) and the Prevention of Significant Deterioration Permit (the “PSD Permit”). These two permits are issued by the LDEQ for the Liquefaction Project.
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Commodity Futures Trading Commission (“CFTC”)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter (“OTC”) 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.
Environmental Regulation
The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations require significant expenditures for compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
Clean Air Act (“CAA”)
The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of the Liquefaction Project, will be materially and adversely affected by any such requirements.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of greenhouse gas (“GHG”) emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules 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 January 20, 2021, President Biden issued an executive order directing the EPA’s June 19, 2019 adoptionEPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent GHG emissions rulemaking. We are supportive of the Affordable Clean Energy rule for power generation.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
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result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Coastal Zone Management Act (“CZMA”)
The siting and construction of the Liquefaction Project within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.
Clean Water Act (“CWA”)
The Liquefaction Project is subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ).
Resource Conservation and Recovery Act (“RCRA”)
The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.
Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act (the “ESA”), the Migratory Bird Treaty Act (“MBTA”), the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If the Liquefaction Project may adversely affect a protected species or its habitat, we may be required to develop and follow a plan to avoid those impacts. In that case, siting, construction or operation may be delayed or restricted and cause us to incur increased costs.
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 regulation 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.
It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe that our operations, or the construction and operations of our Liquefaction Project, will be materially and adversely affected by these recentsuch regulatory actions.
Market Factors and Competition
If and when we need to replace any existing SPA or enter into new SPAs, we will compete on the basis of price per contracted volume of LNG with other natural gas liquefaction projects throughout the world. Cheniere is currently operating
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two Trains and is constructingcommissioning one additional Train at a natural gas liquefaction facility near Corpus Christi, Texas and Corpus Christi Liquefaction, LLC (“CCL”) has entered into fixed price SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 19 years (plus extension rights) with nine third parties for the sale of LNG from this natural gas liquefaction facility, and may continue to enter into commercial agreements with respect to this natural gas liquefaction facility that might otherwise have been entered into with respect to Train 6. Revenues associated with any incremental volumes of the Liquefaction Project, including those under the Cheniere Marketing SPA discussed above, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer
operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to markets than us. Our affiliates have proximity to our customers, with offices located in Houston, London, Singapore, Beijing and Tokyo.
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, Cheniere’s ability to obtain additional funding to execute its business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and Cheniere’s ability to access capital markets.
We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. 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 Project is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.
Our LNG business has limited exposure to the decline in oil prices as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes. We have contracted approximately 75% of the total production capacity from the Liquefaction Project on a term basis, with approximately 17 years of average remaining life as of December 31, 2020, which includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes. As of January 31, 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 terminal.
Employees
We have no employees. We have contracts with subsidiaries of Cheniere and Cheniere Partners for operations, maintenance and management services. As of January 31, 2020,2021, Cheniere and its subsidiaries had 1,5301,519 full-time employees, including 490 employees who directly supported the Liquefaction Project. See Note 12—Related Party Transactions of our Notes to Financial Statements for a discussion of the services agreements pursuant to which general and administrative services are provided to us.
Available Information
Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.
ITEM 1A. RISK FACTORS |
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements.We may encounter risks in addition to those described below.Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
•Risks Relating to Our Financial Matters; and
•Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business.
Risks Relating to Our Financial Matters
Our existing level of cash resources and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
As of December 31, 2019,2020, we had no cash and cash equivalents, $181$97 million of current restricted cash, $787 million of available commitments under the 2020 Working Capital Facility and $13.7 billion of total debt outstanding (before unamortized premium, discount and debt issuance costs), excluding $414$413 million of outstanding letters of credit. We incur, and will incur, significant interest expense relating to the assets at the Liquefaction Project, and we anticipate needing to incur additional debt to finance the construction of Train 6 of the Liquefaction Project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.
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Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations for any reason.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2019,2020, we had SPAs with eight third-party customers. We are dependent on each customer’s continued willingness and ability to perform its obligations under its SPA. We are exposed to the credit risk of any guarantor of these customers’ obligations under their respective SPAagreements in the event that we must seek recourse under a guaranty. IfAs a result of the disruptions caused by the COVID-19 pandemic and the volatility in the energy markets, we believe we are exposed to heightened credit and performance risk of our customers. Additionally, some customers have indicated to us that COVID-19 has impacted their operations and/or may impact their operations in the future. Some of our SPA customers’ primary countries of business have experienced a significant number of COVID-19 cases and/or have been subject to government imposed lockdown or quarantine measures. Although we believe that impacts of the COVID-19 pandemic on LNG regasification facilities, downstream markets and broader energy demand do not constitute valid force majeure claims under our FOB LNG SPAs, if any significant customer fails to perform its obligations under its SPA, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor, if any, for a breach of the SPA.agreement.
Each of our customer contracts is subject to termination under certain circumstances.
Each of our SPAs contains various termination rights allowing our customers to terminate their SPAs, including, without limitation: (1) upon the occurrence of certain events of force majeure; (2) if we fail to make available specified scheduled cargo quantities; and (3) delays in the commencement of commercial operations. We may not be able to replace these SPAs on desirable terms, or at all, if they are terminated.
Our use of hedging arrangements may adversely affect our future operating results or liquidity.
To reduce our exposure to fluctuations in thecommodity-related marketing and price volume and timing risk associated with the purchase of natural gas,risks, we useenter into derivative financial instruments, including futures, swaps and option contracts traded or cleared oncontracts. To the Intercontinental Exchange andextent we hedge our exposure to commodity price, we forego the New York Mercantile Exchange or over-the-counter options and swaps with other natural gas merchants and financial institutions.benefits we would otherwise experience if commodity prices were to change favorably to our hedged position. Hedging arrangements could also expose us to risk of financial loss in some circumstances, including when:
•expected supply is less than the amount hedged;hedged or is otherwise imperfect;
•the counterparty to the hedging contract defaults on its contractual obligations; or
•there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.
The regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.
The provisions of the Dodd-Frank Act and the rules adopted and to be adopted by the CFTC, the SEC and other federal regulators establishing federal regulation of the over-the-counter (“OTC”)OTC derivatives market and entities like us that participate in that market may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable
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to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminal and to secure natural gas feedstock for our Liquefaction Project.
As required by the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require certain market participants to collect and post initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users and certain registered swap dealers and major swap participants. Although we believe we will not be required to post margin with respect to any uncleared swaps we enter into in the future, were we required to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. Our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, contractually require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.
Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business
Cost overruns and delays in the completion of Train 6 or any future Trains, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The actual construction costs of theTrain 6 and any future Trains may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future EPC contracts resulting from the occurrence of certain specified events that may give Bechtelour EPC contractor the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We have already experienced increased costs due to change orders. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations.
The COVID-19 pandemic and the resulting actions taken by governmental and regulatory authorities to prevent the spread of COVID-19 may cause a slow-down in the construction of one or more Trains. Our EPC contractor has advised us of voluntary proactive measures it is taking to protect employees and to mitigate risks associated with COVID-19, however, it has not indicated that there will be any changes to the project cost or schedule and is still performing its obligations under its EPC contract. While the construction of Train 6 is continuing, if there were a major outbreak of COVID-19 at any construction site or the implementation of restrictions by the government that prevented construction for an extended period, we could experience significant delays in the construction of one or more Trains.
Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to theour existing EPC contracts with Bechtelcontract or any future EPC contract related to additional Trains, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the Liquefaction Project is fully constructed (which could cause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of the Liquefaction Project, damage to our Liquefaction Project and Sabine Pass LNG terminal and increased insurance costs, all of which could adversely affect us.
Hurricanes Katrina and Rita in 2005, Hurricane Ike in 2008, and Hurricane Harvey in 2017 and Hurricanes Laura and Delta in 2020 caused temporary suspension in construction or operation of our Liquefaction Project or caused minor damage to our Liquefaction Project. In August 2020, we entered into an arrangement with our affiliate to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers from the other facility in the event operational conditions impact operations at the Sabine Pass LNG terminal or at our affiliate’s terminal. During the year ended December 31, 2020, 17 TBtu was loaded at affiliate facilities pursuant to this agreement. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Liquefaction Project and related infrastructure and increase our insurance premiums. The U.S. Global Change Research
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Program has reported that the U.S.’s energy and transportation systems are expected to be increasingly disrupted by climate change and extreme weather events. An increase in frequency and severity of extreme weather events such as storms, floods, fires and rising sea levels could have an adverse effect on our operations.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of the Liquefaction Project and the export of LNG could impede operations and construction and could have a material adverse effect on us.
The design, construction and operation of the Liquefaction Project and the export of LNG are highly regulated activities. Approvals of the FERC and DOE under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and export LNG. Although the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities, the FERC orders require us to comply with certain ongoing conditions and obtain certain additional approvals in conjunction with ongoing construction and operations of the Liquefaction Project. We will be required to obtain similar approvals and permits with respect to any expansion or modification of the Liquefaction Project. We cannot control the outcome of the regulatory review and approval processes. Certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We do not know whether or when any such approvals or permits can be obtained, or whether any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, including as a result of untimely notices or filings, we may not be able to recover our investment in the Liquefaction Project. Additionally, government disruptions, such as a U.S. government shutdown, may delay or halt our ability to obtain and maintain necessary approvals and permits. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Delays in the completion of one or more Trains could lead to reduced revenues or termination of one or more of the SPAs by our customers.
Any delay in completion of a Train could cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. In particular, each of our SPAs provides that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are entirely dependent on Cheniere and Cheniere Partners, including employees of Cheniere and its subsidiaries, for key personnel, and a loss of key personnel could have a material adverse effect on our business.
As of January 31, 2020,2021, Cheniere and its subsidiaries had 1,5301,519 full-time employees, including 490 employees who directly supported the Liquefaction Project. We have contracted with subsidiaries of Cheniere and Cheniere Partners to provide the personnel necessary for the construction and operation of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate liquefaction facilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing, including the natural gas liquefaction facility it is developing and constructing near Corpus Christi, Texas, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere face competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.
Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a
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material adverse effect on our business. In addition, our future success will depend in part on our ability to engage, and Cheniere’s ability to attract and retain, additional qualified personnel.
A shortage in the labor pool of skilled workers or other general inflationary pressures, or changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and
benefits packages that are offered, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damages.
Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, we have a TUA with SPLNG under which SPLNG derives economic benefits, we have entered into a transportation agreement with CTPL to transport natural gas to the Liquefaction Project and Cheniere Marketing has entered into an SPA with us to purchase: (1) at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers and (2) up to 4330 cargoes scheduled for delivery in 20202021 at a price of 115% of Henry Hub plus $1.67$0.728 per MMBtu. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently operating two Trains and is constructing one additional Train at a natural gas liquefaction facility near Corpus Christi, Texas and CCL has entered into fixed price SPAs with third parties for the sale of LNG from this natural gas liquefaction facility, and may continue to enter into commercial arrangements with respect to this liquefaction facility that might otherwise have been entered into with respect to Train 6 or any future Trains.
We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future transportation, interconnection and gas balancing agreements with one or more Cheniere-affiliated natural gas pipelines as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.
We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.
We are dependent on Bechtel and other contractors for the successful completion of the Liquefaction Project.
Timely and cost-effective completion of the Liquefaction Project in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of Bechtel and our other contractors under their agreements. The ability of Bechtel and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
•design and engineer each Train to operate in accordance with specifications;
•engage and retain third-party subcontractors and procure equipment and supplies;
•respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
•attract, develop and retain skilled personnel, including engineers;
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•post required construction bonds and comply with the terms thereof;
•manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
•maintain their own financial condition, including adequate working capital.
Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Liquefaction Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of Bechtel and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.
Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Liquefaction Project or result in a contractor’s unwillingness to perform further work on the Liquefaction Project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are relying on estimates for the future capacity ratings and performance capabilities of the Liquefaction Project, and these estimates may prove to be inaccurate.
We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the Liquefaction Project. If any Train, when actually constructed, fails to have the capacity ratings and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
If third-party pipelines and other facilities interconnected to our facilities are or become unavailable to transport natural gas, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We depend upon third-party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to meet our SPA obligations and continue shipping natural gas from producing regions could be restricted, thereby reducing our revenues which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
The construction and operation of the Liquefaction Project is and will be subject to the inherent risks associated with this type of operation, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities
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or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully
insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions, including extreme weather events and temperature volatility resulting from climate change;
•reduced demand and lower prices for natural gas;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
•cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•political conditions in natural gas producing regions;
•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
•adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Project will beare 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
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outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign suppliers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or from our competitors’ liquefaction facilities in the United States.
In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.
As a result of these and other factors, LNG may not be a competitive source of energy internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or from the Liquefaction Project on a commercial basis. Any significant impediment to the ability to deliver LNG from the United States generally, or from the Liquefaction Project specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Various economic and political factors could negatively affect the development, construction and operation of the Liquefaction Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Commercial development of a liquefaction facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:
•increased construction costs;
•economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for liquefaction projects on commercially reasonable terms;
•decreases in the price of LNG, which might decrease the expected returns relating to investments in liquefaction projects;
•the inability of project owners or operators to obtain governmental approvals to construct or operate liquefaction facilities;
•political unrest or local community resistance to the siting of liquefaction facilities due to safety, environmental or security concerns; and
•any significant explosion, spill or similar incident involving a liquefaction facility or LNG vessel.
There may be impediments to the transport of LNG, such as shortages of LNG vessels worldwide or operational impacts on LNG shipping, including maritime transportation routes, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The construction and delivery of LNG vessels require significant capital and long construction lead times, andtimes. Additionally, the availability of theLNG vessels and transportation costs could be delayedimpacted to the detriment of our business and our customers because of:
•an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
•shortages of or delays in the receipt of necessary construction materials;
•political or economic disturbances in the countries where the vessels are being constructed;disturbances;
•changes in governmental regulations or maritime self-regulatory organizations;
•work stoppages or other labor disturbances at the shipyards;disturbances;
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•bankruptcy or other financial crisis of shipbuilders;shipbuilders or shipowners;
•quality or engineering problems;
•disruptions to maritime transportation routes; and
•weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; andfire.
We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements, which could have a material adverse effect on us.
We have contracted for firm capacity for our natural gas feedstock transportation requirements for the Liquefaction Project. If and when we need to replace one or more of our existing agreements with these interconnecting pipelines, we may not be able to do so on commercially reasonable terms or at all, which could impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We face competition based upon the international market price for LNG.
The Liquefaction Project is subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs with respect to Train 6 or any future Trains. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from the Liquefaction Project are diverse and include, among others:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to the Liquefaction Project;
•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
•increases in capacity and utilization of nuclear power and related facilities; and
•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
Terrorist attacks, cyber incidents or military campaigns may adversely impact our business.
A terrorist attack, cyber incident or military incident involving an LNG facility, our infrastructure or an LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including Train 6, which would increase our costs and decrease our cash flows. A terrorist incident or cyber incident may also result in temporary or permanent closure of existing LNG facilities, including the Sabine Pass LNG terminal, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of terrorism, cyber incidents or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources, and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of the Sabine Pass LNG terminal, including the PHMSA, to issue compliance orders, which may restrict or limit operations or increase compliance or
operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties or to capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of GHG emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules 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 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 terminal, or could increase compliance costs for our operations. We are supportive of regulations reducing GHG emissions over time.
Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Sabine Pass LNG terminal or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Substantially all of our anticipated revenue in 20202021 will be dependent upon one facility, the Liquefaction Project located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Liquefaction Project 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 may incur impairments to long-lived assets.
We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, reduced estimates of future cash flows for our business or disruptions to our business could lead to an impairment charge of our long-lived assets. Our
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valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our long-lived assets, we may be required to record a charge to earnings in our Financial Statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.
The COVID-19 global pandemic and volatility in the energy markets may materially and adversely affect our business, financial condition, operating results, cash flow, liquidity and prospects.
The COVID-19 global pandemic has resulted in significant disruption globally. Actions taken by various governmental authorities, individuals and companies around the world to prevent the spread of COVID-19 have restricted travel, business operations, and the overall level of individual movement and in-person interaction across the globe. Additionally, recent disputes over production levels between members of the Organization of Petroleum Exporting Countries and other oil producing countries have resulted in increased volatility in oil and natural gas prices.
The extent, duration and magnitude of the COVID-19 pandemic’s effects will depend on future developments, all of which are highly uncertain and difficult to predict, including the impact of the pandemic on global and regional economies, travel, and economic activity, as well as actions taken by governments, businesses and individuals in response to the pandemic or any future resurgence. These developments include the impact of the COVID-19 pandemic on unemployment rates, the demand for oil and natural gas, levels of consumer confidence and the post-pandemic pace of recovery.
Many uncertainties remain with respect to the COVID-19 pandemic, and we continue to monitor the rapidly evolving situation. The COVID-19 pandemic alone or coupled with continued volatility in the energy markets may materially and adversely affect our business, financial condition, operating results, cash flow, liquidity and prospects or have the effect of heightening many of the other risks described herein. The extent to which our business, contracts, financial condition, operating results, cash flow, liquidity and prospects are affected by the COVID-19 global pandemic or volatility in the energy markets will depend on various factors beyond our control and are highly uncertain, including the duration and scope of the outbreak, decreased demand for LNG and the resulting economic effects of the COVID-19 global pandemic.
Outbreaks of infectious diseases, such as the outbreak of COVID-19, at our facilities could adversely affect our operations.
Federal, state and local governments have enacted various measures to try to contain the outbreak of COVID-19, such as travel bans and restrictions, quarantines, shelter-in-place orders and business shutdowns. Our facilities at the Sabine Pass LNG terminal are critical infrastructure and have continued to operate during the outbreak, which means that Cheniere must keep its employees who operate our facilities safe and minimize unnecessary risk of exposure to the virus. In response, Cheniere has taken extra precautionary measures to protect the continued safety and welfare of its employees who continue to work at our facilities and have modified certain business and workforce practices, such as implementing work from home policies where appropriate, but there can be no assurances that these measures will prevent any outbreak. Furthermore, the measures taken to prevent an outbreak at our facilities have resulted in increased costs and it is unclear how long such increased costs will continue to be incurred. If a large number of Cheniere’s employees in those critical facilities were to contract COVID-19 at the same time, our operations could be adversely affected.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.LEGAL PROCEEDINGS
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.
LDEQ Matter
Certain of Cheniere’s subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG terminal and the commissioning of the Liquefaction Project, and relating to certain
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requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of Cheniere’s subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of Cheniere’s subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.
PHMSA Matter
In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to us in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal. These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, we and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to us returning the tanks to service. We continue to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation will have a material adverse impact on our financial results or operations.
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data set forth below are derived from our audited Financial Statements for the periods indicated (in millions). The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Financial Statements and the accompanying notes thereto included elsewhere in this report.
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||
| Statement of Income Data: | ||||||||||||||||||||||||||||||||
| Revenues (including transactions with affiliates) | $ | 5,857 | $ | 6,523 | $ | 6,126 | $ | 4,024 | $ | 833 | ||||||||||||||||||||||
| Income from operations | 1,671 | 1,568 | 1,520 | 781 | 50 | |||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (685) | (705) | (589) | (494) | (186) | |||||||||||||||||||||||||||
| Net income (loss) | 943 | 873 | 944 | 250 | (193) | |||||||||||||||||||||||||||
| December 31, | ||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||
| Balance Sheet Data: | ||||||||||||||||||||||||||||||||
| Property, plant and equipment, net | $ | 14,255 | $ | 13,861 | $ | 13,209 | $ | 12,920 | $ | 11,875 | ||||||||||||||||||||||
| Total assets | 15,323 | 14,952 | 14,967 | 14,206 | 12,883 | |||||||||||||||||||||||||||
| Current debt | — | — | — | — | 224 | |||||||||||||||||||||||||||
| Long-term debt, net | 13,520 | 13,524 | 13,500 | 13,477 | 11,649 | |||||||||||||||||||||||||||
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| Year Ended December 31, | ||||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||
| Statement of Income Data: | ||||||||||||||||||||
| Revenues (including transactions with affiliates) | $ | 6,523 | $ | 6,126 | $ | 4,024 | $ | 833 | $ | — | ||||||||||
| Income (loss) from operations | 1,568 | 1,520 | 781 | 50 | (92 | ) | ||||||||||||||
| Interest expense, net of capitalized interest | (705 | ) | (589 | ) | (494 | ) | (186 | ) | (36 | ) | ||||||||||
| Net income (loss) | 873 | 944 | 250 | (193 | ) | (266 | ) | |||||||||||||
| December 31, | ||||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||
| Balance Sheet Data: | ||||||||||||||||||||
| Property, plant and equipment, net | $ | 13,861 | $ | 13,209 | $ | 12,920 | $ | 11,875 | $ | 9,841 | ||||||||||
| Total assets | 14,952 | 14,967 | 14,206 | 12,883 | 10,433 | |||||||||||||||
| Current debt | — | — | — | 224 | 15 | |||||||||||||||
| Long-term debt, net | 13,524 | 13,500 | 13,477 | 11,649 | 9,206 | |||||||||||||||
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis includes the following subjects:
Overview of Business
We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to the world, while responsiblyconduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG in a safe and rewarding work environment.to our customers. We are currently operating five natural gas liquefaction Trains and are constructing one additional Train that is expected to be substantially completed in the second half of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal, one of the largest LNG production facilities in the world. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast, adjacent to the existing regasification facilities owned and operated by SPLNG.
Overview of Significant Events
Our significant events since January 1, 20192020 and through the filing date of this Form 10-K include the following:
Strategic
•In August 2020, we entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater. |
Operational
•As of February 21, 2020, over 90019, 2021, more than 1,175 cumulative LNG cargoes totaling over 6080 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
Financial
•In February 2021, we entered into a note purchase agreement for the sale of approximately $147 million aggregate principal amount of 2.95% Senior Secured Notes due 2037 (the “2.95% 2037 Senior Secured Notes”) on a private placement basis. The 2.95% 2037 Senior Secured Notes are expected to be issued in December 2021, and the net proceeds are expected to be used to refinance a portion of our outstanding Senior Secured Notes due 2022. The 2.95% 2037 Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years.
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•In May 2020, we issued an aggregate principal amount of $2.0 billion of 4.500% Senior Secured Notes due 2030 (the “2030 Senior Notes”). Net proceeds of the offering, along with available cash, were used to redeem all of our outstanding 5.625% Senior Secured Notes due 2021 (the “2021 Senior Notes”).
•In March 2020, we entered into a $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”), which refinanced our previous working capital facility, reduced the interest rate and extended the maturity date to March 2025.
•In February 2021, Fitch Ratings upgraded the outlook of our senior secured notes rating to positive from stable.
Impact of COVID-19 and Market Environment
The LNG business environment in 2020 was impacted by the coronavirus pandemic and its economic ramifications. Lockdown measures across the globe reduced economic activity and resulted in lower energy needs throughout most of the year. However, LNG demand proved relatively resilient as compared to other hydrocarbons, showing an annual gain of approximately 1.4%, or 5 MT, to 364 MT in 2020. While the economic recovery in Asia, and particularly in China, lifted LNG demand in the second half of the year, uncertainty about the pandemic’s track remains the primary near-term risk to LNG trade. A slow return towards normal is expected to occur in the coming months, depending on the speed of vaccine rollout within regions, vaccine effectiveness against mutations and the speed and shape of economic recovery across the LNG importing nations. The continued improvements in global economic indicators seen in the fourth quarter is encouraging especially in China, which represents one of the key countries for LNG demand growth.
In the fourth quarter of 2020, natural gas and LNG spot prices significantly increased in line with the increase in economic activity and with seasonal norms. After falling to all-time lows in the second quarter, global LNG price benchmarks have made an impressive climb and exited the year at the highest levels since March 2019. As an example, the Dutch Title Transfer Facility (“TTF”), a virtual trading point for natural gas in the Netherlands, settled December at $5.08/MMBtu, $3.94/MMBtu higher than its June 2020 settlement. Similarly, the Japan Korea Marker (“JKM”), an LNG benchmark price assessment for spot physical cargoes delivered ex-ship into certain key markets in Asia, settled December at $6.90/MMBtu, which is $4.84/MMBtu higher than its all-time low July 2020 settlement. Record-low winter temperatures, supply outages and transportation bottlenecks contributed to drive JKM prices up to all-time highs by mid-January 2021. In a projection published in July 2020, IHS Markit estimated LNG demand to reach 383 MT in 2021, implying a return to higher growth in 2021.
We have limited exposure to the fluctuations in oil and LNG spot prices as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements linked to a Henry Hub price. For this reason, we do not expect price fluctuations to have a material impact on our forecasted financial results for 2021.
The number of LNG cargoes for which customers notified us that they would not take delivery has reduced from this summer, a sign that the market is continuing to adjust and rebalance toward equilibrium. We do not expect these events to have a material adverse impact on our forecasted financial results for 2021, due to the highly contracted nature of our business and the fact that customers continue to be obligated to pay fixed fees for cargoes with respect to which they have exercised their contractual right to cancel. As such, during the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We experienced decreased revenues during the year ended December 31, 2020 associated with LNG cargoes that were scheduled for delivery for which customers notified us that they would not take delivery of such cargoes.
In addition, in response to the COVID-19 pandemic, Cheniere has modified certain business and workforce practices to protect the safety and welfare of its employees who continue to work at its facilities and offices worldwide, as well as implemented certain mitigation efforts to ensure business continuity. In March 2020, Cheniere began consulting with a medical advisor, and implemented social distancing through revised shift schedules, work from home policies and designated remote work locations where appropriate, restricted non-essential business travel and began requiring self-screening for employees and contractors. In April 2020, Cheniere began providing temporary housing for its workforce for our facilities, implemented temperature testing, incorporated medical and social workers to support employees, implemented prior self-isolation and screening for temporary housing and implemented marine operations with zero contact during loading activities. These measures have resulted in increased costs. While response measures continue to evolve and in most cases have moderated or ceased, we expect Cheniere to incur incremental operating costs associated with business continuity and protection of its workforce until the risks associated with the pandemic diminish. We have incurred approximately $31 million of such costs during the year ended December 31, 2020.
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Results of Operations
The following charts summarize the number of Trains that were in operation during the years ended December 31, 2020, 2019 and 2018 and total revenues and total LNG volumes loaded (including both operational and commissioning volumes) for the respective periods:
| (1) | The year ended December 31, 2020 excludes 17 TBtu that was loaded at our affiliate’s facility. | |||||||||||||||||||
Our net income was $943 million for the year ended December 31, 2020, compared to $873 million in the year ended December 31, 2019. This $70 million increase in net income was primarily a result of increased margins due to lower pricing of natural gas feedstock and additional LNG volume available to be sold from an additional Train that has reached substantial completion between the periods, a portion of which the customers elected not to take delivery but were required to pay a fixed fee with respect to the contracted volumes. This increase was partially offset by increased losses on commodity derivatives to secure natural gas feedstock for the Liquefaction Project and increased loss on modification or extinguishment of debt incurred in conjunction with the refinancing of the 2021 Senior Notes.
Our net income was $944 million in the year ended December 31, 2018.This $71 million decrease in net income in 2019 compared to 2018 was primarily a result of an increase in (1) operating and maintenance expense, (2) interest expense, net
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of capitalized interest and (3) depreciation and amortization expense, partially offset by increased gross margins due to higher volumes of LNG sold but decreased pricing on LNG.
We enter into derivative instruments to manage our exposure to commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Financial Statements. In some cases, the underlying transactions economically hedged receive accrual accounting treatment, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.
Revenues
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions, except volumes) | 2020 | 2019 | Change | 2018 | Change | ||||||||||||||||||||||||||||||||||||||||||
| LNG revenues | $ | 5,195 | $ | 5,211 | $ | (16) | $ | 4,827 | $ | 384 | |||||||||||||||||||||||||||||||||||||
| LNG revenues—affiliate | 662 | 1,312 | (650) | 1,299 | 13 | ||||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 5,857 | $ | 6,523 | $ | (666) | $ | 6,126 | $ | 397 | |||||||||||||||||||||||||||||||||||||
| LNG volumes recognized as revenues (in TBtu) (1) | 991 | 1,180 | (189) | 955 | 225 | ||||||||||||||||||||||||||||||||||||||||||
(1) Excludes volume associated with cargoes for which customers notified us that they would not take delivery and includes volume that was loaded at our affiliate’s facility.
2020 vs. 2019 and 2019 vs. 2018
Total revenues decreased during the year ended December 31, 2020 from the comparable 2019 period, primarily as a result of decreased volumes recognized as revenues between the periods due to LNG cargoes for which customers notified us that they would not take delivery, although the decrease due to volume was partially offset by the revenues associated with such cargoes. During the year ended December 31, 2020, we recognized $553 million in such revenues. LNG revenues—affiliate also decreased during the year ended December 31, 2020 from the comparable periods due to less sales made to Cheniere Marketing at lower pricing. The increase in LNG revenues during the years ended December 31, 2019 from the comparable 2018 period was primarily attributable to the increased volume of LNG sold following the achievement of substantial completion of the Trains, partially offset by decreased revenues per MMBtu.We expect our LNG revenues to increase in the future upon Train 6 of the Liquefaction Project becoming operational.
Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the years ended December 31, 2019 and 2018, we realized offsets to LNG terminal costs of $48 million corresponding to 10 TBtu of LNG and $94 million corresponding to 13 TBtu of LNG, respectively, that were related to the sale of commissioning cargoes. We did not realize any offsets to LNG terminal costs during the year ended December 31, 2020.
Also included in LNG revenues are sales of unutilized natural gas procured for the liquefaction process and gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized revenues of $255 million, $150 million and $151 million during the years ended December 31, 2020, 2019 and 2018, respectively, related to these transactions.
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Operating costs and expenses
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | 2020 | 2019 | Change | 2018 | Change | ||||||||||||||||||||||||||||||||||||||||||
| Cost of sales | $ | 2,504 | $ | 3,373 | $ | (869) | $ | 3,403 | $ | (30) | |||||||||||||||||||||||||||||||||||||
| Cost of sales—affiliate | 110 | 47 | 63 | 32 | 15 | ||||||||||||||||||||||||||||||||||||||||||
| Operating and maintenance expense | 547 | 547 | — | 342 | 205 | ||||||||||||||||||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | 466 | 450 | 16 | 423 | 27 | ||||||||||||||||||||||||||||||||||||||||||
| Operating and maintenance expense—related party | 13 | — | 13 | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Development expense | — | — | — | 2 | (2) | ||||||||||||||||||||||||||||||||||||||||||
| General and administrative expense | 9 | 6 | 3 | 5 | 1 | ||||||||||||||||||||||||||||||||||||||||||
| General and administrative expense—affiliate | 71 | 79 | (8) | 50 | 29 | ||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization expense | 465 | 447 | 18 | 349 | 98 | ||||||||||||||||||||||||||||||||||||||||||
| Impairment expense and loss on disposal of assets | 1 | 6 | (5) | — | 6 | ||||||||||||||||||||||||||||||||||||||||||
| Total operating costs and expenses | $ | 4,186 | $ | 4,955 | $ | (769) | $ | 4,606 | $ | 349 | |||||||||||||||||||||||||||||||||||||
2020 vs. 2019 and 2019 vs. 2018
Our total operating costs and expenses decreased during the year ended December 31, 2020 from the year ended December 31, 2019, primarily as a result of decreased cost of sales from lower volumes and pricing of natural gas feedstock. Total operating costs and expenses increased during the year ended December 31, 2019 from the year ended December 31, 2018 primarily as a result of additional Trains that were operating between the periods.During the year ended December 31, 2019, we achievedfurther incurred increased TUA reservation charges paid to SPLNG and to Total from payments under the partial TUA assignment agreement and increased third-party service and maintenance costs from turnaround and related activities at the Liquefaction Project.
Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. Cost of sales decreased during the year ended December 31, 2020 from the comparable period in 2019 primarily due to decreases in both the volumes and pricing of natural gas feedstock. Partially offsetting these decreases was increased losses from commodity derivatives to secure natural gas feedstock for the Liquefaction Project, primarily due to an unfavorable shift in long-term forward prices relative to our hedged position and increases in costs associated with a portion of derivative instruments that settle through physical delivery. Cost of sales decreased during the year ended December 31, 2019 from the comparable period in 2018 due to increased derivative gains from an increase in fair value of the derivatives associated with economic hedges to secure natural gas feedstock for the Liquefaction Project, primarily due to a favorable shift in long-term forward prices.Partially offsetting this increase was a decrease in pricing of natural gas feedstock between the years, which in turn was partially offset by increased volumes of natural gas feedstock for our LNG sales as a result of substantial completion of Train 5 of the Liquefaction Project.Cost of sales also includes variable transportation and storage costs and other costs to convert natural gas into LNG.
Cost of sales—affiliate increased during the year ended December 31, 2020 for the cost of cargoes procured from our affiliate to fulfill our commitments to our long-term customers during operational interruption, such as the one we experienced during the shutdown of the Liquefaction Project during Hurricane Laura in September 2020.
Operating and commencedmaintenance expense (including affiliate) primarily includes costs associated with operating activities.
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Depreciation and amortization expense increased during each of the years ended December 31, 2020 and 2019, as the assets related to the Train 45 of the Liquefaction Project began depreciating upon reaching substantial completion in March 2019.
Other expense
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | 2020 | 2019 | Change | 2018 | Change | ||||||||||||||||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | $ | 685 | $ | 705 | $ | (20) | $ | 589 | $ | 116 | |||||||||||||||||||||||||||||||||||||
| Loss on modification or extinguishment of debt | 43 | — | 43 | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Other income, net | — | (10) | 10 | (13) | 3 | ||||||||||||||||||||||||||||||||||||||||||
| Total other expense | $ | 728 | $ | 695 | $ | 33 | $ | 576 | $ | 119 | |||||||||||||||||||||||||||||||||||||
2020 vs 2019 and 2019 vs 2018
Interest expense, net of capitalized interest, decreased during the year ended December 31, 2020 compared to the comparable 2019 period, primarily due to lower interest costs as a result of refinancing higher cost debt and an increase in the portion of total interest costs that was eligible for capitalization as the construction of Train 6 commenced in May 2019. Interest expense, net of capitalized interest, increased during the year ended December 31, 2019 from the comparable 2018 period primarily as a result of a decrease in the portion of total interest costs that could be capitalized as additional Trains of the Liquefaction Project completed construction between the periods. During the years ended December 31, 2020, 2019 and 2018, we incurred $779 million, $790 million and $791 million of total interest cost, respectively, of which we capitalized $94 million, $85 million and $202 million, respectively. Capitalized interest primarily related to interest costs incurred to construct the remaining assets of the Liquefaction Project.
Loss on modification or extinguishment of debt increased during the year ended December 31, 2020 from the comparable 2019 and 2018 periods. Loss on modification or extinguishment of debt recognized in 2020 was attributable to $43 million of debt extinguishment costs relating to the payment of early redemption fees and write off of unamortized debt premiums and issuance costs associated with the redemption of the 2021 Senior Notes.
Liquidity and Capital Resources
The following table provides a summary of our liquidity position at December 31, 20192020 and 20182019 (in millions):
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Cash and cash equivalents | $ | — | $ | — | |||||||
| Restricted cash designated for the Liquefaction Project | 97 | 181 | |||||||||
| Available commitments under the following credit facilities: | |||||||||||
| $1.2 billion Amended and Restated Working Capital Facility (“2015 Working Capital Facility”) | — | 786 | |||||||||
| 2020 Working Capital Facility | 787 | — | |||||||||
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| December 31, | |||||||
| 2019 | 2018 | ||||||
| Cash and cash equivalents | $ | — | $ | — | |||
| Restricted cash designated for the Liquefaction Project | 181 | 756 | |||||
| Available commitments under the $1.2 billion Working Capital Facility (“Working Capital Facility”) | 786 | 775 | |||||
Liquefaction Facilities
The Liquefaction Project is one of the largest LNG production facilities in the world. We are currently operating five Trains and two marine berths at the Liquefaction Project, and are constructing one additional Train.Train that is expected to be substantially completed in the second half of 2022, and a third marine berth. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. Additionally, SPLNG has received authorization from the FERC for the construction of the third marine berth. We have achieved substantial completion of the first five Trains of the Liquefaction Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the Liquefaction Project as of December 31, 2019:
2020:
| Train 6 | |||||||||||
| Overall project completion percentage | |||||||||||
| Completion percentage of: | |||||||||||
| Engineering | |||||||||||
| Procurement | |||||||||||
| Subcontract work | |||||||||||
| Construction | |||||||||||
| Date of expected substantial completion | |||||||||||
The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:
•Trains 1 through 4—FTA countries for a 30-year term, which commenced in May 2016, and non-FTA countries for a 20-year term, which commenced in June 2016,through December 31, 2050, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).
•Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term, both of which commenced inthrough December 2018,31, 2050, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).
•Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, which partially commenced in June 2019 and the remainder commenced in September 2019,through December 31, 2050, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
In each case,December 2020, the terms of theseDOE announced a new policy in which it would no longer issue short-term export authorizations began onseparately from long-term authorizations. Accordingly, the earlier of the date of first export thereunder or the date specified in the particular order. In addition, we received an order providing for a three-year makeup period with respect toDOE amended each of our long-term authorizations to include short-term export authority, and vacated the non-FTA orders for LNG volumes we were authorized but unable to export during any portion of the initial 20-year export period of such order.short-term orders.
An application was filed in September 2019 seeking authorization to authorizemake additional exports from the Liquefaction Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 153 Bcf/yr of natural gas, for a total Liquefaction Project export capacity of approximately 1,662 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of the volumes contemplated in the application. TheIn April 2020, the DOE issued an order authorizing us 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 us to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the Liquefaction Project from the currently authorized level to approximately 1,662 Bcf/yr was also submitted to the FERC and is currently pending before DOE.pending.
Customers
We have entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 17 years (plus extension rights) with eight third parties for Trains 1 through 6 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 75% of the total production capacity from these Trains.Trains, potentially increasing up to approximately 85% after giving effect to an SPA that Cheniere has committed to provide to us. Under these SPAs, the customers will purchase LNG from us 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
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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 fees under our 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 us, 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.
In addition, Cheniere Marketing has agreements with us to purchase: (1) at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers and (2) up to 4330 cargoes scheduled for delivery in 20202021 at a price of 115% of Henry Hub plus $1.67$0.728 per MMBtu.
Natural Gas Transportation, Storage and Supply
To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. We have entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project. We have also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2019,2020, we 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.
Construction
We have entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause us to enter into a change order, or we agree with Bechtel to a change order.
The total contract price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion, including estimated costs for 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.
Terminal Use Agreements
We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. Cheniere Partners has guaranteed our obligations under our TUA. During the years ended December 31, 2020, 2019 2018 and 2017,2018, we recorded operating and maintenance expense—affiliate of $265 million, $261 million $256 million and $190$256 million respectively, for the TUA Fees and cost of sales—affiliate of $33 million, $40 million $32 million and $23$32 million, respectively, for cargo loading services incurred under the TUA.
Additionally, we have entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 5 of the Liquefaction Project, we gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit us to more flexibly manage our LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.
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During the years ended December 31, 2020, 2019 2018 and 2017,2018, we recorded $129 million, $104 million $30 million and $23$30 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.
Capital Resources
We currently expect that our capital resources requirements with respect to the Liquefaction Project will be financed through project debt and borrowings, cash flows under the SPAs and equity contributions from Cheniere Partners. We believe that with the net proceeds of borrowings, available commitments under the 2020 Working Capital Facility, cash flows from operations and equity contributions from Cheniere Partners, we will have adequate financial resources available to meet our currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the Liquefaction Project.
The following table provides a summary of our capital resources from borrowings and available commitments for the Liquefaction Project, excluding equity contributions from Cheniere Partners and cash flows from operations (as described in Sources and Uses of Cash), at December 31, 20192020 and 20182019 (in millions):
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Senior notes (1) | $ | 13,650 | $ | 13,650 | ||||
| Working Capital Facility outstanding balance | — | — | ||||||
| Letters of credit issued under Working Capital Facility | 414 | 425 | ||||||
| Available commitments under Working Capital Facility | 786 | 775 | ||||||
| Total capital resources from borrowings and available commitments (2) | $ | 14,850 | $ | 14,850 | ||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| Senior notes (1) | $ | 13,650 | $ | 13,650 | ||||||||||
| Credit facilities outstanding balance (2) | — | — | ||||||||||||
| Letters of credit issued (2) | 413 | 414 | ||||||||||||
| Available commitments under credit facilities (2) | 787 | 786 | ||||||||||||
| Total capital resources from borrowings and available commitments (3) | $ | 14,850 | $ | 14,850 | ||||||||||
(1)Includes 2021 Senior Notes, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 Senior Notes”), 2030 Senior Notes and 5.00% Senior Secured Notes due 2037 (the “2037 Senior Notes”) (collectively, the “Senior Notes”).
(2)Includes outstanding balances under the 2015 Working Capital Facility and 2020 Working Capital Facility, inclusive of any portion of the 2020 Working Capital Facility that may be used for general corporate purposes.
(3)Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash equivalents.
Senior Notes
The Senior Notes are governed by a common indenture (the “Indenture”) and the terms of the 2037 Senior Notes are governed by a separate indenture (the “2037 Senior Notes Indenture”). Both the Indenture and the 2037 Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of our restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of our assets and enter into certain LNG sales contracts. Subject to permitted liens, the Senior Notes are secured on a pari passu first-priority basis by a security interest in all of ourthe membership interests in us and substantially all of our assets. We may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.
At any time prior to three months before the respective dates of maturity for each series of the Senior Notes (except for the 2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes, 2030 Senior Notes and 2037 Senior Notes, in which case the time period is six months before the respective dates of maturity), we may redeem all or part of such series of the Senior Notes at a redemption price equal to the “make-whole”‘make-whole’ price (except for the 2037 Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. We may also, at any time within three months of the respective maturity dates for each series of the Senior Notes (except for the 2026 Senior Notes, 2027 Senior Notes, 2028 Senior Notes, 2030 Senior
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Notes and 2037 Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the Senior Notes at a redemption price equal to 100% of the principal amount of such series of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
Both the indenture governing the 2037 Senior Notes (the “2037 Senior Notes Indenture”)Indenture and the common indenture governing the remainder of the Senior Notes (the “Indenture”)Indenture include restrictive covenants. We may incur additional indebtedness
in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than our current outstanding indebtedness, including the Senior Notes and the 2020 Working Capital Facility. Under the 2037 Senior Notes Indenture and the Indenture, we may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025 and are fully amortizing according to a fixed sculpted amortization schedule.
2015 Working Capital Facility
In SeptemberMarch 2020, we terminated the remaining commitments under the 2015 Working Capital Facility. As of December 31, 2019, we had $786 million of available commitments, $414 million aggregate amount of issued letters of credit and no outstanding borrowings under the 2015 Working Capital Facility.
2020 Working Capital Facility
In March 2020, we entered into the 2020 Working Capital Facility with aggregate commitments of $1.2 billion, which was amended in May 2019 in connection with commercialization and financing of Train 6 ofreplaced the Liquefaction Project.2015 Working Capital Facility. The 2020 Working Capital Facility is intended to be used for loans (“Working Capital Loans”),to us, swing line loans to us and the issuance of letters of credit as well as for swing line loans (“Swing Line Loans”),on behalf of us, primarily for certain working capital requirements(1) the refinancing of the 2015 Working Capital Facility, (2) fees and expenses related to developingthe 2020 Working Capital Facility, (3) our gas purchase obligations and placing into operation the Liquefaction Project.gas purchase obligations of our future subsidiaries and (4) general corporate purposes of us and certain of our future subsidiaries. We may, from time to time, request increases in the commitments under the 2020 Working Capital Facility of up to $760 million and incremental increases in commitments of up to an additional $390$800 million. As of December 31, 2019 and 2018,2020, we had $786 million and $775$787 million of available commitments, and $414 million and $425$413 million aggregate amount of issued letters of credit under the Working Capital Facility, respectively. We did not have anyand no outstanding borrowings under the 2020 Working Capital Facility as of both December 31, 2019 and 2018.Facility.
The 2020 Working Capital Facility matures on December 31, 2020, and the outstanding balanceMarch 19, 2025, but may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. LC Loans deemed made in connectionextended with a draw upon a letterconsent of credit have a term of up to one year. Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of thelenders. The 2020 Working Capital Facility (2) the date 15 days after such Swing Line Loan is made and (3) the first borrowing dateprovides for a Working Capital Loan or Swing Line Loan occurring at least three business days following the date the Swing Line Loan is made. We are required to reduce the aggregate outstanding principal amount of all Working Capital Loans to zero for a period of five consecutive business days at least once each year.mandatory prepayments under customary circumstances.
The 2020 Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligationsWe are restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, satisfaction of a 12-month forward-looking and backward-looking 1.25:1.00 debt service reserve ratio test. Obligations under the 2020 Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of theour and future subsidiaries membership interests in us on a pari passu basis by a first priority lien with the Senior Notes.
Restrictive Debt Covenants
As of December 31, 2019,2020, we were in compliance with all covenants related to our debt agreements.
LIBOR
The use of LIBOR is expected to be phased out by the end of 2021. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue to workworking with our lenders to pursue any amendments to our debt agreements that are currently subject to LIBOR and will continue to monitor, assess and plan for the phase out of LIBOR.
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Sources and Uses of Cash
The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the years ended December 31, 2020, 2019 2018 and 20172018 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| Sources of cash, cash equivalents and restricted cash: | ||||||||||||||||||||
| Net cash provided by operating activities | $ | 1,424 | $ | 1,161 | $ | 1,423 | ||||||||||||||
| Proceeds from issuances of debt | 1,995 | — | — | |||||||||||||||||
| Capital contributions | 488 | 1,046 | 129 | |||||||||||||||||
| $ | 3,907 | $ | 2,207 | $ | 1,552 | |||||||||||||||
| Uses of cash, cash equivalents and restricted cash: | ||||||||||||||||||||
| Property, plant and equipment, net | $ | (916) | $ | (1,282) | $ | (771) | ||||||||||||||
| Repayments of debt | (2,000) | — | — | |||||||||||||||||
| Debt issuance and other financing costs | (35) | — | — | |||||||||||||||||
| Debt extinguishment costs | (39) | — | — | |||||||||||||||||
| Distributions | (1,001) | (1,499) | (569) | |||||||||||||||||
| Other | — | (1) | — | |||||||||||||||||
| (3,991) | (2,782) | (1,340) | ||||||||||||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | $ | (84) | $ | (575) | $ | 212 | ||||||||||||||
| Year Ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| Operating cash flows | $ | 1,161 | $ | 1,423 | $ | 657 | ||||||
| Investing cash flows | (1,283 | ) | (771 | ) | (1,279 | ) | ||||||
| Financing cash flows | (453 | ) | (440 | ) | 808 | |||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | (575 | ) | 212 | 186 | ||||||||
| Cash, cash equivalents and restricted cash—beginning of period | 756 | 544 | 358 | |||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 181 | $ | 756 | $ | 544 | ||||||
Operating Cash Flows
Our operating cash net inflows during the years ended December 31, 2020, 2019 and 2018 and 2017 were $1,424 million, $1,161 million and $1,423 million, respectively. The $263 million increase in operating cash inflows in 2020 compared to 2019 was primarily related to decreased operating costs and $657 million, respectively.expenses. The $262 million decrease in operating cash inflows in 2019 compared to 2018 was primarily related to increased operating costs and expenses, which were partially offset by increased cash receipts from the sale of LNG cargoes, as a result of an additional Train that was operating at the Liquefaction Project in 2019. The $766
Proceeds from Issuance of Debt, Repayments of Debt, Debt Issuance and Other Financing Costs and Debt Extinguishment Costs
During the year ended December 31, 2020, we issued an aggregate principal amount of $2.0 billion of the 2030 Senior Notes, which was used to redeem all of the outstanding 2021 Senior Notes. We incurred $35 million increase in operating cash inflows in 2018 compared to 2017 wasof debt issuance costs primarily related to increased cash receipts fromup-front fees paid and $39 million of debt extinguishment costs upon the saleclosing of LNG cargoes, partially offset by increased operating coststhis transaction.
Property, Plant and expenses as a result of the additional Trains that were operating at the Liquefaction Project in 2018.Equipment, net
Contractual Obligations
We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 20192020 (in millions):
| Payments Due By Period (1) | ||||||||||||||||||||
| Total | 2020 | 2021 - 2022 | 2023 - 2024 | Thereafter | ||||||||||||||||
| Debt (2) | $ | 13,650 | $ | — | $ | 3,000 | $ | 3,500 | $ | 7,150 | ||||||||||
| Interest payments (2) | 3,879 | 747 | 1,293 | 959 | 880 | |||||||||||||||
| Operating lease obligations (3) | 42 | 1 | 3 | 3 | 35 | |||||||||||||||
| Purchase obligations: (4) | ||||||||||||||||||||
| Construction obligations (5) | 894 | 455 | 398 | 41 | — | |||||||||||||||
| Natural gas supply, transportation and storage service agreements (6) | 8,670 | 2,329 | 2,347 | 1,123 | 2,871 | |||||||||||||||
| Other purchase obligations (7) | 6,483 | 443 | 886 | 886 | 4,268 | |||||||||||||||
| Total | $ | 33,618 | $ | 3,975 | $ | 7,927 | $ | 6,512 | $ | 15,204 | ||||||||||
| Payments Due By Period (1) | ||||||||||||||||||||||||||||||||
| Total | 2021 | 2022 - 2023 | 2024 - 2025 | Thereafter | ||||||||||||||||||||||||||||
| Debt (2) | $ | 13,650 | $ | — | $ | 2,500 | $ | 4,023 | $ | 7,127 | ||||||||||||||||||||||
| Interest payments (2) | 3,931 | 724 | 1,312 | 926 | 969 | |||||||||||||||||||||||||||
| Operating lease obligations (3) | 45 | 1 | 3 | 3 | 38 | |||||||||||||||||||||||||||
| Purchase obligations: (4) | ||||||||||||||||||||||||||||||||
| Construction obligations (5) | 618 | 355 | 263 | — | — | |||||||||||||||||||||||||||
| Natural gas supply, transportation and storage service agreements (6) | 11,171 | 3,030 | 3,242 | 1,814 | 3,085 | |||||||||||||||||||||||||||
| Other purchase obligations (7) | 6,066 | 445 | 891 | 891 | 3,839 | |||||||||||||||||||||||||||
| Total | $ | 35,481 | $ | 4,555 | $ | 8,211 | $ | 7,657 | $ | 15,058 | ||||||||||||||||||||||
(1)Agreements in force as of December 31, 2020 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2020. (2)Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2020. A discussion of our debt obligations can be found in Note 10—Debt of our Notes to Financial Statements. (3)Operating lease obligations primarily relate to land sites related to the Liquefaction Project. (4)Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include only contracts for which conditions precedent have been met. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly. We include contracts for which we have an early termination option if the option is not expected to be exercised. (5)Construction obligations primarily consist of the estimated remaining cost pursuant to our EPC contracts as of December 31, 2020 for projects with respect to which we have made an FID to commence construction. A discussion of these obligations can be found at Note 13—Commitments and Contingencies of our Notes to Financial Statements. (6)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2020. Natural gas transportation and storage agreements includes $1.3 billion in payments under the transportation precedent agreement with CTPL and $366 million in payments under agreements with a related party as discussed in Note 12—Related Party Transactions of our Notes to Financial Statements. (7)Other purchase obligations primarily consist of $4.0 billion in payments under our TUA agreement with SPLNG, as discussed in Note 12—Related Party Transactions of our Notes to Financial Statements, as well as payments under our partial TUA assignment agreement with Total, as discussed in Note 13—Commitments and Contingencies of our Notes to Financial Statements. |
In addition, as of December 31, 2019,2020, we had $414$413 million aggregate amount of issued letters of credit under the Working Capital Facility.
| Year Ended December 31, | |||||||||||||||||||
| (in millions, except volumes) | 2019 | 2018 | Change | 2017 | Change | ||||||||||||||
| LNG revenues | $ | 5,211 | $ | 4,827 | $ | 384 | $ | 2,635 | $ | 2,192 | |||||||||
| LNG revenues—affiliate | 1,312 | 1,299 | 13 | 1,389 | (90 | ) | |||||||||||||
| Total revenues | $ | 6,523 | $ | 6,126 | $ | 397 | $ | 4,024 | $ | 2,102 | |||||||||
| LNG volumes recognized as revenues (in TBtu) | 1,180 | 955 | 225 | 684 | 271 | ||||||||||||||
| Year Ended December 31, | |||||||||||||||||||
| (in millions) | 2019 | 2018 | Change | 2017 | Change | ||||||||||||||
| Cost of sales | $ | 3,373 | $ | 3,403 | $ | (30 | ) | $ | 2,317 | $ | 1,086 | ||||||||
| Cost of sales—affiliate | 47 | 32 | 15 | 23 | 9 | ||||||||||||||
| Operating and maintenance expense | 547 | 342 | 205 | 243 | 99 | ||||||||||||||
| Operating and maintenance expense—affiliate | 450 | 423 | 27 | 329 | 94 | ||||||||||||||
| Development expense | — | 2 | (2 | ) | 2 | — | |||||||||||||
| General and administrative expense | 6 | 5 | 1 | 7 | (2 | ) | |||||||||||||
| General and administrative expense—affiliate | 79 | 50 | 29 | 58 | (8 | ) | |||||||||||||
| Depreciation and amortization expense | 447 | 349 | 98 | 264 | 85 | ||||||||||||||
| Impairment expense and loss on disposal of assets | 6 | — | 6 | — | — | ||||||||||||||
| Total operating costs and expenses | $ | 4,955 | $ | 4,606 | $ | 349 | $ | 3,243 | $ | 1,363 | |||||||||
| Year Ended December 31, | |||||||||||||||||||
| (in millions) | 2019 | 2018 | Change | 2017 | Change | ||||||||||||||
| Interest expense, net of capitalized interest | $ | 705 | $ | 589 | $ | 116 | $ | 494 | $ | 95 | |||||||||
| Loss on modification or extinguishment of debt | — | — | — | 42 | (42 | ) | |||||||||||||
| Derivative loss, net | — | — | — | 2 | (2 | ) | |||||||||||||
| Other income | (10 | ) | (13 | ) | 3 | (7 | ) | (6 | ) | ||||||||||
| Total other expense | $ | 695 | $ | 576 | $ | 119 | $ | 531 | $ | 45 | |||||||||
Off-Balance Sheet Arrangements
As of December 31, 2019,2020, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our financial position or operating results.
Summary of Critical Accounting Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.
Fair Value of Derivative Instruments
All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market.
Our derivative instruments consist of financial commodity derivative contracts transacted in an over-the-counter market and physical commodity contracts. Valuation of our financial commodity derivative contracts is determined using observable commodity price curves and other relevant data.
Valuation of our physical commodity contracts is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our physical commodity contracts incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. A portion of our physical commodity contracts require us to make critical accounting estimates that involve significant judgment, as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future Henry Hub basis spread for unobservable periods, liquidity, volatility and contract duration.
Gains and losses on derivative instruments are recognized in earnings. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a change in the estimated fair value could occur in the near future as interest rates and commodity prices change.
Recent Accounting Standards
For descriptions of recently issued accounting standards, see Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements.
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):
| December 31, 2020 | December 31, 2019 | ||||||||||||||||||||||
| Fair Value | Change in Fair Value | Fair Value | Change in Fair Value | ||||||||||||||||||||
| Liquefaction Supply Derivatives | $ | (21) | $ | 4 | $ | 24 | $ | 1 | |||||||||||||||
| December 31, 2019 | December 31, 2018 | ||||||||||||||
| Fair Value | Change in Fair Value | Fair Value | Change in Fair Value | ||||||||||||
| Liquefaction Supply Derivatives | $ | 24 | $ | 1 | $ | (43 | ) | $ | 7 | ||||||
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
SABINE PASS LIQUEFACTION, LLC
38
MANAGEMENT’S REPORT TO THE MEMBER OF SABINE PASS LIQUEFACTION, LLC
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Sabine Pass Liquefaction, LLC (“Sabine Pass Liquefaction”). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Sabine Pass Liquefaction’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
Based on our assessment, we have concluded that Sabine Pass Liquefaction maintained effective internal control over financial reporting as of December 31, 2019,2020, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.
This annual report does not include an attestation report of Sabine Pass Liquefaction’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Sabine Pass Liquefaction’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Management’s Certifications
The certifications of Sabine Pass Liquefaction’s Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Sabine Pass Liquefaction’s Form 10-K.
| By: | /s/ Jack A. Fusco | By: | /s/ | |||||||||||
| Jack A. Fusco | ||||||||||||||
| Chief Executive Officer (Principal Executive Officer) | Manager and Chief Financial Officer (Principal Financial Officer) | |||||||||||||
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Member of Sabine Pass Liquefaction, LLC and
Board of Directors of Cheniere Energy Partners GP, LLC
Sabine Pass Liquefaction, LLC:
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Sabine Pass Liquefaction, LLC (the Company) as of December 31, 20192020 and 2018,2019, the related statements of income, member’s equity, (deficit), and cash flows for each of the years in the three-year period ended December 31, 2019,2020, and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019,2020, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 2 and 7 to the financial statements, the Company recorded fair value of level 3 physical liquefaction supply derivatives of $(21) million, as of December 31, 2020. The physical liquefaction supply derivatives consist of natural gas supply contracts for the operation of the liquefied natural gas facility. The fair value of the level 3 physical liquefaction supply derivatives is developed through the use of internal models which incorporate significant unobservable inputs.
We identified the evaluation of the fair value of the level 3 physical liquefaction supply derivatives as a critical audit matter. Specifically, there is subjectivity in certain assumptions used to estimate the fair value, including assumptions for future prices of energy units for unobservable periods and liquidity.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the valuation of the level 3 physical liquefaction supply derivatives. This included controls related to the assumptions for significant unobservable inputs. For the level 3 liquefaction supply derivatives selected, we involved valuation professionals with specialized skills who assisted in:
40
•developing independent fair value estimates and comparing the independently developed estimates to the Company’s fair value estimates
•testing the future prices of energy units for unobservable periods and liquidity assumptions by comparing to market data, including quoted or published forward prices for similar commodities.
In addition, we evaluated the Company’s assumptions for future prices of energy units for unobservable periods and liquidity by comparing to market or third-party data, including adjustments for third party quoted transportation prices.
| /s/ KPMG LLP | ||
| KPMG LLP | ||
We have served as the Company’s auditor since 2014.
Houston, Texas
February 24, 202023, 2021
SABINE PASS LIQUEFACTION, LLC
(in millions)
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||
| Revenues | ||||||||||||||||||||||||||||||||
| LNG revenues | $ | 5,195 | $ | 5,211 | $ | 4,827 | ||||||||||||||||||||||||||
| LNG revenues—affiliate | 662 | 1,312 | 1,299 | |||||||||||||||||||||||||||||
| Total revenues | 5,857 | 6,523 | 6,126 | |||||||||||||||||||||||||||||
| Operating costs and expenses | ||||||||||||||||||||||||||||||||
| Cost of sales (excluding items shown separately below) | 2,504 | 3,373 | 3,403 | |||||||||||||||||||||||||||||
| Cost of sales—affiliate | 110 | 47 | 32 | |||||||||||||||||||||||||||||
| Operating and maintenance expense | 547 | 547 | 342 | |||||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | 466 | 450 | 423 | |||||||||||||||||||||||||||||
| Operating and maintenance expense—related party | 13 | 0 | 0 | |||||||||||||||||||||||||||||
| Development expense | 0 | 0 | 2 | |||||||||||||||||||||||||||||
| General and administrative expense | 9 | 6 | 5 | |||||||||||||||||||||||||||||
| General and administrative expense—affiliate | 71 | 79 | 50 | |||||||||||||||||||||||||||||
| Depreciation and amortization expense | 465 | 447 | 349 | |||||||||||||||||||||||||||||
| Impairment expense and loss on disposal of assets | 1 | 6 | 0 | |||||||||||||||||||||||||||||
| Total operating costs and expenses | 4,186 | 4,955 | 4,606 | |||||||||||||||||||||||||||||
| Income from operations | 1,671 | 1,568 | 1,520 | |||||||||||||||||||||||||||||
| Other income (expense) | ||||||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (685) | (705) | (589) | |||||||||||||||||||||||||||||
| Loss on modification or extinguishment of debt | (43) | 0 | 0 | |||||||||||||||||||||||||||||
| Other income (expense), net | 0 | 10 | 13 | |||||||||||||||||||||||||||||
| Total other expense | (728) | (695) | (576) | |||||||||||||||||||||||||||||
| Net income | $ | 943 | $ | 873 | $ | 944 | ||||||||||||||||||||||||||
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | — | $ | — | ||||
| Restricted cash | 181 | 756 | ||||||
| Accounts and other receivables | 292 | 346 | ||||||
| Accounts receivable—affiliate | 104 | 113 | ||||||
| Advances to affiliate | 133 | 210 | ||||||
| Inventory | 103 | 87 | ||||||
| Derivative assets | 17 | 6 | ||||||
| Other current assets | 36 | 18 | ||||||
| Other current assets—affiliate | 22 | 21 | ||||||
| Total current assets | 888 | 1,557 | ||||||
| Property, plant and equipment, net | 13,861 | 13,209 | ||||||
| Debt issuance costs, net | 6 | 12 | ||||||
| Non-current derivative assets | 32 | 31 | ||||||
| Other non-current assets, net | 165 | 158 | ||||||
| Total assets | $ | 14,952 | $ | 14,967 | ||||
| LIABILITIES AND MEMBER’S EQUITY | ||||||||
| Current liabilities | ||||||||
| Accounts payable | $ | 38 | $ | 11 | ||||
| Accrued liabilities | 629 | 768 | ||||||
| Due to affiliates | 49 | 48 | ||||||
| Deferred revenue | 132 | 91 | ||||||
| Derivative liabilities | 9 | 66 | ||||||
| Total current liabilities | 857 | 984 | ||||||
| Long-term debt, net | 13,524 | 13,500 | ||||||
| Non-current derivative liabilities | 16 | 14 | ||||||
| Other non-current liabilities | 5 | 3 | ||||||
| Other non-current liabilities—affiliate | 16 | — | ||||||
| Commitments and contingencies (see Note 14) | ||||||||
| Member’s equity | 534 | 466 | ||||||
| Total liabilities and member’s equity | $ | 14,952 | $ | 14,967 | ||||
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
(in millions)
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Revenues | |||||||||||
| LNG revenues | $ | 5,211 | $ | 4,827 | $ | 2,635 | |||||
| LNG revenues—affiliate | 1,312 | 1,299 | 1,389 | ||||||||
| Total revenues | 6,523 | 6,126 | 4,024 | ||||||||
| Operating costs and expenses | |||||||||||
| Cost of sales (excluding depreciation and amortization expense shown separately below) | 3,373 | 3,403 | 2,317 | ||||||||
| Cost of sales—affiliate | 47 | 32 | 23 | ||||||||
| Operating and maintenance expense | 547 | 342 | 243 | ||||||||
| Operating and maintenance expense—affiliate | 450 | 423 | 329 | ||||||||
| Development expense | — | 2 | 2 | ||||||||
| General and administrative expense | 6 | 5 | 7 | ||||||||
| General and administrative expense—affiliate | 79 | 50 | 58 | ||||||||
| Depreciation and amortization expense | 447 | 349 | 264 | ||||||||
| Impairment expense and loss on disposal of assets | 6 | — | — | ||||||||
| Total operating costs and expenses | 4,955 | 4,606 | 3,243 | ||||||||
| Income from operations | 1,568 | 1,520 | 781 | ||||||||
| Other income (expense) | |||||||||||
| Interest expense, net of capitalized interest | (705 | ) | (589 | ) | (494 | ) | |||||
| Loss on modification or extinguishment of debt | — | — | (42 | ) | |||||||
| Derivative loss, net | — | — | (2 | ) | |||||||
| Other income | 10 | 13 | 7 | ||||||||
| Total other expense | (695 | ) | (576 | ) | (531 | ) | |||||
| Net income | $ | 873 | $ | 944 | $ | 250 | |||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| ASSETS | ||||||||||||||
| Current assets | ||||||||||||||
| Cash and cash equivalents | $ | 0 | $ | 0 | ||||||||||
| Restricted cash | 97 | 181 | ||||||||||||
| Accounts and other receivables, net | 309 | 292 | ||||||||||||
| Accounts receivable—affiliate | 185 | 104 | ||||||||||||
| Advances to affiliate | 122 | 133 | ||||||||||||
| Inventory | 93 | 103 | ||||||||||||
| Derivative assets | 14 | 17 | ||||||||||||
| Prepaid expenses | 27 | 29 | ||||||||||||
| Other current assets | 14 | 7 | ||||||||||||
| Other current assets—affiliate | 21 | 22 | ||||||||||||
| Total current assets | 882 | 888 | ||||||||||||
| Property, plant and equipment, net | 14,255 | 13,861 | ||||||||||||
| Debt issuance costs, net | 10 | 6 | ||||||||||||
| Non-current derivative assets | 11 | 32 | ||||||||||||
| Other non-current assets, net | 165 | 165 | ||||||||||||
| Total assets | $ | 15,323 | $ | 14,952 | ||||||||||
| LIABILITIES AND MEMBER’S EQUITY | ||||||||||||||
| Current liabilities | ||||||||||||||
| Accounts payable | $ | 8 | $ | 38 | ||||||||||
| Accrued liabilities | 591 | 629 | ||||||||||||
| Accrued liabilities—related party | 4 | 0 | ||||||||||||
| Due to affiliates | 59 | 49 | ||||||||||||
| Deferred revenue | 114 | 132 | ||||||||||||
| Derivative liabilities | 11 | 9 | ||||||||||||
| Total current liabilities | 787 | 857 | ||||||||||||
| Long-term debt, net | 13,520 | 13,524 | ||||||||||||
| Non-current derivative liabilities | 35 | 16 | ||||||||||||
| Other non-current liabilities | 8 | 5 | ||||||||||||
| Other non-current liabilities—affiliate | 15 | 16 | ||||||||||||
| Commitments and contingencies (see Note 13) | 0 | 0 | ||||||||||||
| Member’s equity | 958 | 534 | ||||||||||||
| Total liabilities and member’s equity | $ | 15,323 | $ | 14,952 | ||||||||||
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF MEMBER’S EQUITY (DEFICIT)
(in millions)
| Sabine Pass LNG-LP, LLC | Total Member’s Equity | ||||||||||||||||
| Balance at December 31, 2017 | $ | (38) | $ | (38) | |||||||||||||
| Capital contributions | 129 | 129 | |||||||||||||||
| Distributions | (569) | (569) | |||||||||||||||
| Net income | 944 | 944 | |||||||||||||||
| Balance at December 31, 2018 | 466 | 466 | |||||||||||||||
| Capital contributions | 1,046 | 1,046 | |||||||||||||||
| Distributions | (1,851) | (1,851) | |||||||||||||||
| Net income | 873 | 873 | |||||||||||||||
| Balance at December 31, 2019 | 534 | 534 | |||||||||||||||
| Capital contributions | 488 | 488 | |||||||||||||||
| Distributions | (1,007) | (1,007) | |||||||||||||||
| Net income | 943 | 943 | |||||||||||||||
| Balance at December 31, 2020 | $ | 958 | $ | 958 | |||||||||||||
| Sabine Pass LNG-LP, LLC | Total Member’s Equity (Deficit) | ||||||
| Balance at December 31, 2016 | $ | 486 | $ | 486 | |||
| Capital contributions | 7 | 7 | |||||
| Distributions | (781 | ) | (781 | ) | |||
| Net income | 250 | 250 | |||||
| Balance at December 31, 2017 | (38 | ) | (38 | ) | |||
| Capital contributions | 129 | 129 | |||||
| Distributions | (569 | ) | (569 | ) | |||
| Net income | 944 | 944 | |||||
| Balance at December 31, 2018 | 466 | 466 | |||||
| Capital contributions | 1,046 | 1,046 | |||||
| Distributions | (1,851 | ) | (1,851 | ) | |||
| Net income | 873 | 873 | |||||
| Balance at December 31, 2019 | $ | 534 | $ | 534 | |||
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF CASH FLOWS
(in millions)
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Cash flows from operating activities | |||||||||||
| Net income | $ | 873 | $ | 944 | $ | 250 | |||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation and amortization expense | 447 | 349 | 264 | ||||||||
| Amortization of debt issuance costs, deferred commitment fees, premium and discount | 27 | 22 | 19 | ||||||||
| Loss on modification or extinguishment of debt | — | — | 42 | ||||||||
| Total losses (gains) on derivatives, net | (72 | ) | 101 | 26 | |||||||
| Net cash provided by (used for) settlement of derivative instruments | 5 | (3 | ) | (14 | ) | ||||||
| Impairment expense and loss on disposal of assets | 6 | — | — | ||||||||
| Changes in operating assets and liabilities: | |||||||||||
| Accounts and other receivables | 19 | (122 | ) | (99 | ) | ||||||
| Accounts receivable—affiliate | 9 | 49 | (63 | ) | |||||||
| Advances to affiliate | (34 | ) | (76 | ) | (13 | ) | |||||
| Inventory | (16 | ) | (3 | ) | 11 | ||||||
| Accounts payable and accrued liabilities | (138 | ) | 165 | 190 | |||||||
| Due to affiliates | 8 | (6 | ) | 22 | |||||||
| Deferred revenue | 40 | 7 | 38 | ||||||||
| Other, net | (13 | ) | (4 | ) | (4 | ) | |||||
| Other, net—affiliate | — | — | (12 | ) | |||||||
| Net cash provided by operating activities | 1,161 | 1,423 | 657 | ||||||||
| Cash flows from investing activities | |||||||||||
| Property, plant and equipment, net | (1,282 | ) | (771 | ) | (1,279 | ) | |||||
| Other | (1 | ) | — | — | |||||||
| Net cash used in investing activities | (1,283 | ) | (771 | ) | (1,279 | ) | |||||
| Cash flows from financing activities | |||||||||||
| Proceeds from issuances of debt | — | — | 2,314 | ||||||||
| Repayments of debt | — | — | (703 | ) | |||||||
| Debt issuance and deferred financing costs | — | — | (29 | ) | |||||||
| Capital contributions | 1,046 | 129 | 7 | ||||||||
| Distributions | (1,499 | ) | (569 | ) | (781 | ) | |||||
| Net cash provided by (used in) financing activities | (453 | ) | (440 | ) | 808 | ||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | (575 | ) | 212 | 186 | |||||||
| Cash, cash equivalents and restricted cash—beginning of period | 756 | 544 | 358 | ||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 181 | $ | 756 | $ | 544 | |||||
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
| Net income | $ | 943 | $ | 873 | $ | 944 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization expense | 465 | 447 | 349 | ||||||||||||||
| Amortization of debt issuance costs, premium and discount | 24 | 27 | 22 | ||||||||||||||
| Loss on modification or extinguishment of debt | 43 | 0 | 0 | ||||||||||||||
| Total losses (gains) on derivatives, net | 49 | (72) | 101 | ||||||||||||||
| Net cash provided by (used for) settlement of derivative instruments | (4) | 5 | (3) | ||||||||||||||
| Impairment expense and loss on disposal of assets | 1 | 6 | 0 | ||||||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||||
| Accounts and other receivables, net | (17) | 19 | (122) | ||||||||||||||
| Accounts receivable—affiliate | (80) | 9 | 49 | ||||||||||||||
| Advances to affiliate | 5 | (34) | (76) | ||||||||||||||
| Inventory | 9 | (16) | (3) | ||||||||||||||
| Accounts payable and accrued liabilities | 2 | (138) | 165 | ||||||||||||||
| Accrued liabilities—related party | 4 | 0 | 0 | ||||||||||||||
| Due to affiliates | 9 | 8 | (6) | ||||||||||||||
| Deferred revenue | (18) | 40 | 7 | ||||||||||||||
| Other, net | (10) | (13) | (4) | ||||||||||||||
| Other, net—affiliate | (1) | 0 | 0 | ||||||||||||||
| Net cash provided by operating activities | 1,424 | 1,161 | 1,423 | ||||||||||||||
| Cash flows from investing activities | |||||||||||||||||
| Property, plant and equipment, net | (916) | (1,282) | (771) | ||||||||||||||
| Other | 0 | (1) | 0 | ||||||||||||||
| Net cash used in investing activities | (916) | (1,283) | (771) | ||||||||||||||
| Cash flows from financing activities | |||||||||||||||||
| Proceeds from issuances of debt | 1,995 | 0 | 0 | ||||||||||||||
| Repayments of debt | (2,000) | 0 | 0 | ||||||||||||||
| Debt issuance and other financing costs | (35) | 0 | 0 | ||||||||||||||
| Debt extinguishment costs | (39) | 0 | — | ||||||||||||||
| Capital contributions | 488 | 1,046 | 129 | ||||||||||||||
| Distributions | (1,001) | (1,499) | (569) | ||||||||||||||
| Net cash used in financing activities | (592) | (453) | (440) | ||||||||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | (84) | (575) | 212 | ||||||||||||||
| Cash, cash equivalents and restricted cash—beginning of period | 181 | 756 | 544 | ||||||||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 97 | $ | 181 | $ | 756 | |||||||||||
Balances per Balance Sheets:
| December 31, | December 31, | |||||||||||||||||
| 2019 | 2018 | 2020 | 2019 | |||||||||||||||
| Cash and cash equivalents | $ | — | $ | — | Cash and cash equivalents | $ | 0 | $ | 0 | |||||||||
| Restricted cash | 181 | 756 | Restricted cash | 97 | 181 | |||||||||||||
| Total cash, cash equivalents and restricted cash | $ | 181 | $ | 756 | Total cash, cash equivalents and restricted cash | $ | 97 | $ | 181 | |||||||||
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
We are a Delaware limited liability company formed by Cheniere Partners. We are a Houston-based company with 1 member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of Cheniere Partners. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of Cheniere Partners, a publicly traded limited partnership (NYSE MKT: CQP). Cheniere Partners is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses. Cheniere also owns 100% of the general partner interest in Cheniere Partners through ownership in Cheniere Energy Partners GP, LLC.
We are currently operating 5 natural gas liquefaction Trains and are constructing 1 additional Train that is expected to be substantially completed in the second half of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast, adjacent to the existing regasification facilities owned and operated by SPLNG.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Financial Statements have been prepared in accordance with GAAP. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our financial position, results of operations or cash flows.
Recent Accounting Standards
Use of Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements, revenue recognition, property, plant and equipment, derivative instruments and asset retirement obligations (“AROs”), as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market
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participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.
Revenue Recognition
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash
Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets.
Accounts Receivable
Accounts receivable is reported net of any allowances for doubtful accounts. We periodicallycurrent expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the collectabilitycounterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Statements of Income. As of December 31, 2020 and 2019, we had current expected credit losses on our accounts receivable of $5 million and recognize an allowance if there is probability of non-collection, based on historical write-off and customer-specific factors. We did 0t have an allowance on our accounts receivable as of December 31, 2019 and 2018.0, respectively.
Inventory
LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued.
Accounting for LNG Activities
Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.
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Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We did 0t record any impairments related to property, plant and equipment during the years ended December 31, 2020, 2019 and 2018.
Interest Capitalization
We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.
Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did 0t have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2020, 2019 2018 and 2017.2018. See Note 7—Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.
We have entered into fixed price long-term SPAs generally with terms of 20 years with 8 third parties and have entered into agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their
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willingness to perform under their respective SPAs. See Note 14—Customer Concentration for additional details about our customer concentration.
Debt
Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, they are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective
interest method. Gains and losses on the extinguishment or modification of debt are recorded in gain (loss) on modification or extinguishment of debt on our Statements of Income.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
We have 0t recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.
Income Taxes
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss which may vary substantially from the net income or loss reported on our Statements of Income, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Cheniere Partners is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of Cheniere Partners taxable income. Accordingly, 0 provision or liability for federal or state income taxes is included in the accompanying Financial Statements.
At December 31, 2019,2020, the tax basis of our assets and liabilities was $4.6$7.0 billion less than the reported amounts of our assets and liabilities.
Pursuant to the indentures governing our debt, we are permitted to make distributions (“Tax Distributions”) for any fiscal year or portion thereof in which we are a limited partnership, disregarded entity or other substantially similar pass-through entity for federal and state income tax purposes. The Tax Distributions are equal to the tax that we would owe if we were a corporation subject to federal and state income tax that filed separate federal and state income tax returns, excluding the amounts covered by the state tax sharing agreement discussed in Note 12—Related Party Transactions. The Tax Distributions are limited to the amount of federal and/or state income taxes paid by Cheniere to the appropriate taxing authorities and are payable by us within 30 days of the date that Cheniere is required to make federal or state income tax payments to the appropriate taxing authorities.
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Business Segment
Our liquefaction operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of SPL in total when evaluating financial performance and for purposes of allocating resources.
NOTE 3—RESTRICTED CASH
Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. As of December 31, 2020 and 2019, we had $97 million and 2018,$181 million of current restricted cash, consisted of the following (in millions):respectively.
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Current restricted cash | ||||||||
| Liquefaction Project | $ | 181 | $ | 756 | ||||
Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.
NOTE 4—ACCOUNTS AND OTHER RECEIVABLES
As of December 31, 20192020 and 2018,2019, accounts and other receivables, net consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| Trade receivable | $ | 300 | $ | 283 | ||||||||||
| Other accounts receivable | 9 | 9 | ||||||||||||
| Total accounts and other receivables, net | $ | 309 | $ | 292 | ||||||||||
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Trade receivable | $ | 283 | $ | 330 | ||||
| Other accounts receivable | 9 | 16 | ||||||
| Total accounts and other receivables | $ | 292 | $ | 346 | ||||
NOTE 5—INVENTORY
As of December 31, 20192020 and 2018,2019, inventory consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| Natural gas | $ | 17 | $ | 9 | ||||||||||
| LNG | 8 | 27 | ||||||||||||
| Materials and other | 68 | 67 | ||||||||||||
| Total inventory | $ | 93 | $ | 103 | ||||||||||
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| Natural gas | $ | 9 | $ | 28 | ||||
| LNG | 27 | 6 | ||||||
| Materials and other | 67 | 53 | ||||||
| Total inventory | $ | 103 | $ | 87 | ||||
NOTE 6—PROPERTY, PLANT AND EQUIPMENT
As of December 31, 20192020 and 2018,2019, property, plant and equipment, net consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| LNG terminal costs | ||||||||||||||
| LNG terminal | $ | 13,711 | $ | 13,736 | ||||||||||
| LNG terminal construction-in-process | 2,100 | 1,222 | ||||||||||||
| Accumulated depreciation | (1,561) | (1,104) | ||||||||||||
| Total LNG terminal costs, net | 14,250 | 13,854 | ||||||||||||
| Fixed assets | ||||||||||||||
| Fixed assets | 19 | 18 | ||||||||||||
| Accumulated depreciation | (14) | (11) | ||||||||||||
| Total fixed assets, net | 5 | 7 | ||||||||||||
| Property, plant and equipment, net | $ | 14,255 | $ | 13,861 | ||||||||||
| December 31, | ||||||||
| 2019 | 2018 | |||||||
| LNG terminal costs | ||||||||
| LNG terminal | $ | 13,736 | $ | 10,004 | ||||
| LNG terminal construction-in-process | 1,222 | 3,866 | ||||||
| Accumulated depreciation | (1,104 | ) | (667 | ) | ||||
| Total LNG terminal costs, net | 13,854 | 13,203 | ||||||
| Fixed assets | ||||||||
| Fixed assets | 18 | 14 | ||||||
| Accumulated depreciation | (11 | ) | (8 | ) | ||||
| Total fixed assets, net | 7 | 6 | ||||||
| Property, plant and equipment, net | $ | 13,861 | $ | 13,209 | ||||