PART I
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ITEMS 1. AND 2. | BUSINESS AND PROPERTIES |
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
We are a Delaware limited liability company formed by Cheniere Energy Partners, L.P. (“Cheniere Partners”) in June 2010.CQP. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.
LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.
We are currently operating fiveown a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, which has six operational Trains, and are constructing one additionalwith Train 6 having achieved substantial completion on February 4, 2022, for a total operational 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 existingTerminal also has operational regasification facilities owned and operated by Sabine PassSPLNG.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted most of our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG L.P. (“SPLNG”).cargoes, and under IPM agreements, in which the gas producer sells natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total production capacity from the Liquefaction Project with approximately 15 years of weighted average remaining life as of December 31, 2022. For further discussion of the contracted future cash flows under our revenue arrangements, see Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG terminal,Terminal, which provides opportunity for further liquefaction capacity expansion. FurtherThe development of the Sabine Passthis site or other projects, including infrastructure projects in support of natural gas supply and LNG terminaldemand, will require, among other things, acceptable commercial and financing arrangements before we can make a positive final investment decision (“FID”).decision.
Our Business Strategy
Our primary business strategy is to develop, construct and operate assets supported byto meet our long-term fixed fee contracts.customers’ energy demands. We plan to implement our strategy by:
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• | •safely, efficiently and reliably operating and maintaining our assets, including our Trains; • 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 sixeight of eighteleven third party long-term SPA customers as of December 31, 2019;2022;
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;
•optimizing the Liquefaction Project by leveraging existing infrastructure;
•maintaining a prudent and cost-effective capital structure; and
•strategically identifying actionable environmental solutions.
Our Business
Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Liquefaction Facilities
The Liquefaction Project, as described above under the caption General, is one of the largest LNG production facilities in the world. We are currently operating fiveworld with six Trains and twothree marine berths atberths.
The following summarizes the Liquefaction Project and are constructing one additional Train. Wevolumes of natural gas for which we have received authorizationapprovals from the FERC to site, construct and operate Trains 1 through 6. 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:
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| | Train 6 |
Overall project completion percentage | | 43.7% |
Completion percentage of: | |
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Engineering | | 91.5% |
Procurement | | 60.9% |
Subcontract work | | 37.4% |
Construction | | 9.7% |
Date of expected substantial completion | | 1H 2023 |
The following orders we have been issued byreceived from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:Terminal through December 31, 2050:
Trains 1 through 4—FTA countries for a 30-year term, which commenced in May 2016, | | | | | | | | | | | | | | | | | | | | | | | |
| FERC Approved Volume | | DOE Approved Volume |
| (in Bcf/yr) | | (in mtpa) | | (in Bcf/yr) | | (in mtpa) |
| FTA countries | 1,661.94 | | 33 | | 1,661.94 | | 33 |
| Non-FTA countries | 1,661.94 | | 33 | | 1,661.94 | | 33 |
Natural Gas Supply, Transportation and non-FTA countries for a 20-year term, which commenced in June 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).Storage
Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term, both of which commenced in December 2018, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of
We have secured natural gas (approximately 4 mtpa).
Trains 5 and 6—FTA countries and non-FTA countriesfeedstock for a 20-year term, which partially commenced in June 2019 and the remainder commenced in September 2019, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
In each case, the terms of these authorizations began on 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 to each of 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.
The DOE issued orders authorizing us to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing January 2020, in an aggregate amount up to the equivalent of 600 Bcf ofTerminal through long-term natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).
An application was filed in September 2019supply agreements, including an IPM agreement. Additionally, to authorize 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 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. The application is currently pending before DOE.
Customers
We have entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) with eight third parties for Trains 1 through 6 of the Liquefaction Project to make available an aggregate amount of LNGensure that is approximately 75% of the total production capacity from these Trains. 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 equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable 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 43 cargoes scheduled for delivery in 2020 at a price of 115% of Henry Hub plus $1.67 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.
The following table shows customers with revenues of 10% or greater of total revenues from external customers:
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| | 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,Terminal and manage inventory levels, 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, we had secured up to approximately 3,850 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.parties.
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 optional third marine berth. As of December 31, 2019, we have incurred $1.1 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, 2019, 2018 and 2017, we recorded operating and maintenance expense—affiliate of $261 million, $256 million and $190 million, respectively, for the TUA Fees and cost of sales—affiliate of $40 million, $32 million and $23 million, respectively, for cargo loading services incurred under the TUA.
Additionally, we have entered into a partial TUA assignment agreement with
Total,TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), 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 providesprovide us with additional berthing and storage capacity at the Sabine Pass LNG
terminal that mayTerminal. Refer to Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of our TUA agreements.
Customers
Information regarding our customer contracts can be usedfound in Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following table shows customers with revenues of 10% or greater of total revenues from external customers:
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| | | | | | Percentage of Total Revenues from External Customers |
| | | | Year Ended December 31, |
| | | | | | 2022 | | 2021 | | 2020 |
| BG Gulf Coast LNG, LLC and affiliates | | | | | | 24% | | 25% | | 25% |
| GAIL (India) Limited | | | | | | 17% | | 18% | | 19% |
| Korea Gas Corporation | | | | | | 17% | | 17% | | 18% |
| Naturgy LNG GOM, Limited | | | | | | 16% | | 16% | | 16% |
| TotalEnergies | | | | | | * | | 10% | | * |
* Less than 10%
All of the above customers contribute 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, 2019, 2018 and 2017, we recorded $104 million, $30 million and $23 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.revenues through SPA contracts.
Governmental Regulation
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.
Federal Energy Regulatory Commission
The design, construction, operation, maintenance and expansion of the Liquefaction Project are highly regulated activities subject to the jurisdiction of the FERC pursuant to the Natural Gas Act of 1938, as amended (the “NGA”). Under the NGA, the FERC’s jurisdiction generally extends to the sale for resale of natural gas in interstate commerce and to the construction, operation, maintenance and expansion of liquefaction facilities.
The FERC issued its final ordersOrder Granting Section 3 Authority (“Order”) in April and July 2012 approving our application for an order under Section 3 of the NGA authorizing the siting, construction and operation of Trains 1 through 4 of the Liquefaction Project (and related facilities). Subsequently, in May 2012, the FERC issued written approval to commence site preparation work for Trains 1 through 4. In October 2012, we applied to amend the FERC approval to reflect certain modifications to the Liquefaction Project, and in August 2013, the FERC issued an orderOrder approving the modifications. In October 2013, we applied to further amend the FERC approval, requesting authorization to increase the total permitted LNG production capacity of Trains 1 through 4 from the then authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity of Trains 1 through 4. In February 2014, the FERC issued an order approving the October 2013 application (the “February 2014 Order”). A party to the proceeding requested a rehearing of the February 2014 Order, and in September 2014, the FERC issued an order denying the rehearing request (the “FERC Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review the February 2014 Order and the FERC Order Denying Rehearing. The court denied the petition in June 2016. In September 2013, we filed an application with the FERC for authorization to add Trains 5 and 6 to the Liquefaction Project, which was granted by the FERC in an orderOrder issued in April 2015 and an orderOrder denying rehearing issued in June 2015. These ordersOrders are not subject to appellate court review. In October of 2018, 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. FERC issued written approval to commence site preparation work for the third berth in June 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. The DOE issued Orders granting authorization to export LNG to FTA countries in April 2020 and to non-FTA countries in March 2022. In October 2021, the FERC issued its Orders Amending Authorization under Section 3 of the NGA. In March 2022, the DOE authorized the export of an additional 152.64 Bcf/yr of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050 to non-FTA countries, that were previously authorized for FTA countries only.
On February 18, 2022, the FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for the FERC’s decision-making process, which would now include, among other things, reasonably foreseeable greenhouse gas emissions that may be attributable to the project and the project’s impact on environmental justice communities. These FERC changes are the first revision in more than 20 years to the FERC’s policy for the certification of new interstate natural gas pipeline projects under Section 7 of the NGA. The updated Policy Statement has more limited applicability to LNG projects regulated under Section 3 of the Natural Gas Act. While the impact on our future projects and expansions is not known at this time, we do not expect it to have a material adverse effect on our operations.
All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other material governmental and regulatory approvals and permits will beare 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 terminalTerminal 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, 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.
Commodity Futures Trading Commission (“CFTC”)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.those markets. The regulatory regime created byCFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, is designed primarily to (1) regulate certain participants inincluding the swaps markets, including entities falling within
speculative position limit rules. Given the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of standardized swaps of certain classes as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authorityrecent enactment of the CFTC andspeculative position limit rules, as well as the SEC regarding the derivatives markets. Mostimpact of the regulations are already in effect, while other rules and regulations includingunder the proposed margin rules, position limits and commodity clearing requirements, remain to be finalized or effectuated. Therefore,Dodd-Frank Act, the impact of thosesuch rules and regulations on our business continues to be uncertain.uncertain, but is not expected to be material.
A provision of the Dodd-Frank Act requires the CFTC, in order to diminish or prevent excessive speculation in commodity markets, to adopt rules, as it finds necessary and appropriate, imposing new position limits on certain physical commodity futures contracts and options thereon, as well as economically equivalent swaps traded on registered swap trading platforms and on over-the-counter swaps that perform a significant price discovery function with respect to certain markets. In that regard, the CFTC has re-proposed position limits rules that would modify and expand the applicability of limits on speculative positions in certain physical commodity futures contracts and economically equivalent futures, options and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging and other types of transactions. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.
Pursuant to rules adopted by the CFTC, certain interest rate swaps and index credit default swaps must be cleared through a derivatives clearing organization and executed on an exchange or swap execution facility. The CFTC has not yet proposed to designate swaps in any other asset classes, including swaps relating to physical commodities, for mandatory clearing and trade execution, but could do so in the future. Although we expect to qualify for the end-user exception from the mandatory clearing
and exchange-trading requirements applicable to any swaps that we enter into to hedge our commercial risks, the mandatory clearing and exchange-trading requirements may apply to other market participants, including our counterparties (who may be registered as Swap Dealers), with respect to other swaps, and the application of such rules may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.
As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators havealso adopted rules to requirerequiring Swap Dealers and Major Swap Participants,(as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.
Any new rules or changes to existing rules promulgated under the Dodd-Frank Act could (1) impair the availability of derivatives, (2) materially increase the cost of, or decrease the liquidity of, the derivatives we use to hedge, (3) significantly alter the terms and conditions of derivatives and (4) potentially increase our exposure to less creditworthy counterparties. Further, any resulting reduction in the use of derivatives could make cash flow more volatile and less predictable, which in turn could adversely affect our ability to plan for and fund capital expenditures.
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.pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. 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,On February 28, 2022, the EPA promulgatedremoved a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and finalizedoperators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022. We do not believe that our operations, or the Mandatory Greenhouse Gas Reporting Rule requiring annual reportingconstruction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.
We are supportive of regulations reducing 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,over time. Since 2009, the EPA has definedpromulgated and finalized multiple GHG emissions thresholds that would subjectregulations related to reporting and reductions of GHG emissions from our facilities. The EPA has proposed additional new regulations to reduce methane emissions from both new and modified industrialexisting sources to regulation ifwithin the Crude Oil and Natural Gas 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 generationcategory that impact our assets and the oil and gas exploration and production industries, those rules have largely been stayed or repealed including by amendments adopted by the EPA on February 23, 2018, additional proposed amendments to new source performance standards for the oil and gas industry on September 24, 2019, and the EPA’s June 19, 2019 adoption of the Affordable Clean Energy rule for power generation.our supply chain.
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory actionOn August 16, 2022, President Biden signed H.R. 5376(P.L. 117-169), the Inflation Reduction Act of 2022 (“IRA”) which includes a charge on methane emissions above a certain threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program (“GHGRP”) Part 98 (“Subpart W”) regulations. The charge starts at $900 per metric ton of methane in 2024, $1,200 per metric ton in 2025, and increasing to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap$1,500 per metric ton in 2026 and trade programs. It is not possible atbeyond. At this time, we do not expect it to predict how future regulations
or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, contracts,operations, financial condition operatingor results cash flow, liquidity and prospects.of operations.
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). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.
Resource Conservation and Recovery Act (“RCRA”)
The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.
Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act, (the “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. FishIt is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and Wildlife Service (the “FWS”) announced a series of changes to the rules implementing the ESA, including revisions to the regulations governing interagency cooperation, listing specieswetlands and delisting critical habitat and prohibitions related to threatened wildlife and plants. The revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions.
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, the FWS issued a proposed rule defining the scope of the MBTA to cover only actions directed at migratory birds, their nests or their eggs.
Weimpact 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 two Trains and is constructing 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) 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 longerMarket Factors
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 extent of energy security needs in the European Union and elsewhere, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and other overarching factors such as global economic growth in developing countries.and the pace of any transition from fossil-based systems of energy production and consumption to renewable energy sources. In addition, Cheniere’sour ability to obtain additional funding to execute itsour business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and Cheniere’sour 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. GlobalMarket participants around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand forand infrastructure growth. Currently, significant amounts of money are being invested across Europe, Asia and Latin America in natural gas is projected byprojects under construction, and more continues to be earmarked to planned projects globally. In Europe, there are various plans to install more than 80 mtpa of import capacity over the International Energy Agencynear-term to grow by approximately 27 trillion cubic feet (“Tcf”) between 2018secure access to LNG and 2030 displace Russian gas imports. In India, there are nearly 12,000 kilometers of gas pipelines under construction to expand the gas distribution network
and 39 Tcf between 2018increase access to natural gas. And in China, billions of U.S. dollars have already been invested and 2035. LNG’s share is seen growing from about 11%hundreds of billions of U.S. dollars are expected to be further invested all along the natural gas value chain to decrease harmful emissions.
As a result of these dynamics, we expect gas and LNG to continue to play an important role in 2018 to about 16% of the global gas market in 2030 and 18% in 2035.satisfying energy demand going forward. In its fourth quarter 2022 forecast, Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 79%53%, from approximately 316388.5 mtpa, or 15.218.6 Tcf, in 2018,2021, to approximately 566595.7 mtpa, or 27.228.6 Tcf, in 2030 and to 678677.8 mtpa or 32.632.5 Tcf in 2035.2040. In its fourth quarter 2022 forecast, WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 469537 mtpa in 2030, declining to 430490 mtpa in 2035.2040. This willcould result in a market need for construction of an additional approximately 9759 mtpa of LNG production by 2030 and about 248187 mtpa by 2035.2040. As a cleaner burning fuel with 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 pricesprice movements as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes. AsThrough our SPAs and IPM agreement, we have contracted approximately 85% of Januarythe total production capacity from the Liquefaction Project, with approximately 15 years of weighted average remaining life as of December 31, 2020, U.S.2022, which includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes.
Competition
When we need to replace any existing SPA or enter into new SPAs, we will compete on the basis of price per contracted volume of LNG with other natural gas prices indicateliquefaction projects throughout the world, including our affiliate Corpus Christi Liquefaction, LLC (“CCL”), which operates three Trains at a natural gas liquefaction facility near Corpus Christi, Texas. Revenues associated with any incremental volumes of the Liquefaction Project, including those under the Cheniere Marketing SPA, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to LNG markets than us.
Corporate Responsibility
As described in Market Factors and Competition, we expect that global demand for natural gas and LNG exported fromwill continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Our vision is to provide clean, secure and affordable energy to the U.S.world. This vision underpins our focus on responding to the world’s shared energy challenges—expanding the global supply of clean and affordable energy, improving air quality, reducing emissions and supporting the transition to a lower-carbon future. Our approach to corporate responsibility is guided by our Climate and Sustainability Principles: Transparency, Science, Supply Chain and Operational Excellence. In 2022, Cheniere published Acting Now, Securing Tomorrow, its third Corporate Responsibility (“CR”) report, which outlines Cheniere’s focus on sustainability and its performance on key environmental, social and governance (“ESG”) metrics. Cheniere’s CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K.
Cheniere’s climate strategy is to measure and mitigate emissions – to better position our LNG supplies to remain competitive in a lower carbon future, providing energy, economic and environmental security to our customers across the world. To maximize the environmental benefits of our LNG, we believe it is important to develop future climate goals and strategies based on an accurate and holistic assessment of the emissions profile of our LNG, accounting for all steps in the supply chain.
Consequently, we are collaborating with natural gas midstream companies, methane detection technology providers and/or leading academic institutions on quantification, monitoring, reporting and verification (“QMRV”) of GHG research and development projects, co-founding and sponsoring multidisciplinary research and education initiatives led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines.
Cheniere also joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative in October 2022.
Our total expenditures related to the climate initiatives, including capital expenditures, were not material to our Financial Statements during the years ended December 31, 2022, 2021 and 2020. However, as the transition to a lower-carbon economy continues to be competitively priced, supportingevolve, as described in Market Factors and Competition, we expect the opportunityscope and extent of our future initiatives to evolve accordingly. While we have not incurred material direct capital expenditures related to climate change, we aspire to conduct our business in a safe and responsible manner and are proactive in our management of environmental impacts, risks and opportunities. We face certain business and operational risks associated with physical impacts from climate change, such as potential increases in severe weather events or changes in weather patterns, in addition to transition risks. Please see Item 1A. Risk Factors for U.S. LNG to fill uncontracted future demand through the execution of long-term and medium-term contracting of LNG from our terminal.additional discussion.
Employees
We have no employees. We have contracts with subsidiaries of Cheniere and Cheniere PartnersCQP for operations, maintenance and management services. As of JanuaryDecember 31, 2020,2022, Cheniere and its subsidiaries had 1,5301,551 full-time employees, including 490517 employees who directly supported the Liquefaction Project. See Note 12—Related Party Transactions of our Notes to Financial Statements for a discussion of the services agreements pursuant to which general and administrative services are provided to us.
Available Information
Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.
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ITEM 1A. | 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
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, 2019,2022, we had no cash and cash equivalents, $181$92 million of current restricted cash and $13.7cash equivalents, $872 million of available commitments under the our $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “Working Capital Facility”) and $12.1 billion of total debt outstanding (before unamortized premium, discount and debt issuance costs), excluding $414 million of outstanding letters of credit.. We incur, and will incur, significant interest expense relating to financing 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.
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, 2019,2022, we had SPAs with eight third-partyterms of 10 or more years with a total of 11 different third party customers. We
While substantially all of our long-term third party customer arrangements are dependent on each customer’s continued willingness and ability to perform its obligations under its SPA. Weexecuted with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to the credit risk of any guarantor of these customers’ obligations under their respective SPA in the event of a customer default that requires us to seek recourse.
Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we must seek recoursefail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs upon the occurrence of certain events of force majeure.
Although we have not had a guaranty. If anyhistory of material customer failsdefault or termination events, the occurrence of such events are largely outside of our control and may expose us to perform its obligations under its SPA,unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the SPA.affected.
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 exposureefforts to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter options and swaps with other natural gas merchantsmanage commodity and financial institutions. Hedging arrangements could expose us to risk of financial loss in some circumstances,risks through derivative instruments, including when:
expected supply is less than the amount hedged;
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 hedgingour IPM 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 earnings reported under GAAP and affect our liquidity.
We use derivative instruments to manage commodity, currency and financial market risks. The extent of our derivative position at any given time depends on our assessments of the markets for these commodities and related exposures. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, other than certain derivatives for which we have elected to apply accrual accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Financial Statements. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile. As described in Results of Operations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, our net income for the year ended December 31, 2022 includes $1.1 billion of losses resulting from changes in fair values of our derivatives, of which substantially all of such losses were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreement.
These transactions and other derivative transactions have and may continue to result in substantial volatility in results of operations reported under GAAP, particularly in periods of significant commodity, currency or financial market variability. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
In addition, our liquidity may be adversely impacted by the cash margin requirements of the commodities exchanges or the failure of a counterparty to perform in accordance with a contract. As of December 31, 2022 and 2021, we had collateral posted with counterparties by us of $35 million and $7 million, respectively, which are included in margin deposits in our Balance Sheets.
Risks Relating to Our Operations and Industry
Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us.
Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our facilities. In August 2020, we entered into an arrangement with our affiliate to provide the ability, in limited circumstances, to hedge riskspotentially fulfill commitments to LNG buyers from the other facility in the event operational conditions impact operations at the Sabine Pass LNG Terminal or at our affiliate’s terminal. During the year ended December 31, 2021, eight TBtu was loaded at affiliate facilities pursuant to this agreement. Our risk of loss related to weather events or other disasters is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our businessFinancial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or interruption of operations at our terminal or related infrastructure, which could impact our operating results, increase insurance premiums or deductibles paid and cash flows.
The provisions ofdelay or increase costs associated with the Dodd-Frank Actconstruction 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”) derivatives market and entities like us that participate in that market may adversely affect our ability to manage certaindevelopment of our risks on a cost effective basis. Such lawsother facilities. Our LNG terminal infrastructure and regulations may also adversely affect our ability to execute our strategiesLNG facility located in or near Sabine Pass, Louisiana are designed in accordance with respect to hedging our exposure to variability in expected future cash flows attributablerequirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.
Disruptions to the future sale of our LNG inventory and to price risk attributable to future purchasesthird party supply of natural gas to be utilized as fuel to operate our LNG terminal and to secure natural gas feedstock for our Liquefaction Project.
The CFTC has re-proposed position limits rules that would modify and expand the applicability of position limits on the amounts of certain speculative futures contracts, as well as economically equivalent options, futures and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging positions and other types of transactions. To the extent the revised CFTC position limits proposal becomes final, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.
Under the Dodd-Frank Act and the rules adopted thereunder, certain swaps may be required to be cleared through a derivatives clearing organization. While the CFTC has designated certain interest rate swaps and index credit default swaps for mandatory clearing, it has not yet finalized rules designating any physical commodity swaps, for mandatory clearing or mandatory exchange trading. Further, we qualify for the end-user exception from the mandatory clearing and trade execution requirements for our swaps entered into to hedge our commercial risks. If we fail to qualify for that exception as to any swap we enter into and have to clear that swap through a derivatives clearing organization, we could be required to post margin (or post higher margin than if we entered into an uncleared OTC swap) with respect to such swap, our cost of entering into and maintaining such swap could increase and we would not enjoy the same flexibility with the cleared swaps that we enjoy with the uncleared OTC swaps we enter into. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.
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.
The Dodd-Frank Act also imposes other regulatory requirements on swaps market participants, including end users of swaps, such as regulations relating to swap documentation, reporting and recordkeeping, and certain business conduct rules applicable to swap dealers and major swap participants. Together with the Basel III capital requirements on certain swaps market participants, the regulatory requirements of the Dodd-Frank Act and the rules thereunder relating to swaps and derivatives market participants could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter and reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.
We expect that our hedging activities will remain subject to significant and developing regulations and regulatory oversight. However, the full impact of the various U.S. (and non-U.S.) regulatory developments in connection with these activities will not
be known with certainty until such derivatives market regulations are fully implemented and related market practices and structures are fully developed.
Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business
Operation of the Liquefaction Project involves significant risks.
As more fully discussed in these Risk Factors, the Liquefaction Project faces operational risks, including the following:
the facilities’ performing below expected levels of efficiency;
breakdown or failures of equipment;
operational errors by vessel or tug operators;
operational errors by us or any contracted facility operator;
labor disputes; and
weather-related interruptions of operations.
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,facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The actual construction costs of the 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 Bechtel 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.
Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to the EPC contracts with Bechtel 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 caused temporary suspension in construction of our Liquefaction Project or caused minor damage to our Liquefaction Project. 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 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, Cheniere and its subsidiaries had 1,530 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 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 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 43 cargoes scheduled for delivery in 2020 at a price of 115% of Henry Hub plus $1.67 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;
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-partythird party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to meet our SPA obligations andreceive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be restricted, thereby reducingadversely impacted. Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the risk factor Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of sufficient quantitiesnatural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply 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 gasour pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transport across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected 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 as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. TheAlthough losses incurred as a result of self- insured risk have not been material historically, 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,flow, 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;change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;
•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 producingcustomer 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,flow, liquidity and prospects.
Failure of exported LNG to be a long term 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 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 toAs described in Market Factors and Competition, it is expected that global demand for natural gas and LNG also competes with otherwill continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to alternative fossil fuel energy sources such as oil and coal. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy including coal, oil, nuclear, hydroelectric, wind and solar energy.as such alternative sources emerge. Additionally, 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 described in Market Factors and Competition, we have contracted through our SPAs and IPM agreements approximately 85% of the total production capacity from the Liquefaction Project with approximately 15 years of weighted average remaining life as of December 31, 2022. However, as a result of thesethe factors described above and other factors, the LNG we produce may not beremain a long term 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.internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or 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 shortages of LNG vessels worldwide, 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, and the availability of the vessels could be delayed 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;
political or economic disturbances in the countries where the vessels are being constructed;
changes in governmental regulations or maritime self-regulatory organizations;
work stoppages or other labor disturbances at the shipyards;
bankruptcy or other financial crisis of shipbuilders;
quality or engineering problems;
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
shortages of or delays in the receipt of necessary construction materials.
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.
TheOur 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.SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from theour 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 theour Liquefaction Project;
•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
•increases in capacity and utilization of nuclear power and related facilities; and
•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
A cyber incidentsattack involving our business, operational control systems or military campaigns may adverselyrelated infrastructure, or that of third party pipelines which supply the Liquefaction Project, could negatively impact our business.operations, result in data security breaches, impede the processing of transactions, or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
The LNG industry is increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our liquefaction and shipping operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Project. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should multiple of the third party pipelines which supply our Liquefaction Project suffer similar concurrent attacks, the Liquefaction Project may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A terroristcyber attack cyber incidentinvolving our business or military incident involving an LNG facility, ouroperational control systems or related infrastructure, or an LNG vessel maythat of third-party pipelines with which we do business, could negatively impact our operations, result in delays in,data security breaches, impede the processing of transactions, or cancellationdelay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
Outbreaks of constructioninfectious diseases, such as the outbreak of new LNGCOVID-19, at our 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 businessoperations.
Our facilities at the Liquefaction Project are critical infrastructure and continued to operate during the COVID-19 pandemic through our customers,implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including their abilitythe Delta and Omicron variants, has had no adverse impact on our on-going operations during this time, the risk of future variants is unknown. While we believe we can continue to satisfy their obligationsmitigate any significant adverse impact to us under our commercial agreements. Instabilityemployees and operations at our critical facilities related to the virus in its current form, the outbreak of a more potent variant or another infectious disease in the financial markets as a resultfuture at one or more of terrorism, cyber incidents or warour facilities could also materially adversely affect our operations.
We are entirely dependent on Cheniere and CQP, including employees of Cheniere and its subsidiaries, for key personnel, and the unavailability of skilled workers or failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our key personnel could affect our business results.
As of December 31, 2022, Cheniere and its subsidiaries had 1,551 full-time employees, including 517 employees who directly supported the Liquefaction Project. We have contracted with subsidiaries of Cheniere and CQP to provide the personnel necessary for the operation, maintenance and management of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing, including its liquefaction project at Corpus Christi, Texas, for the time and expertise of Cheniere’s personnel. Further, Cheniere faces competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.
Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our ability to raise capital. The continuationengage, and Cheniere’s ability to attract and retain, additional qualified personnel.
A shortage in the labor pool of skilled workers, remoteness of our site locations, or other general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. All of these developmentsagreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently operating three Trains at a natural gas liquefaction facility near Corpus Christi, Texas and CCL has entered into fixed price SPAs with third-parties for the sale of LNG from this natural gas liquefaction facility, and may subject our constructioncontinue to enter into with respect to any future expansion of the Liquefaction Project.
We expect that there will be additional agreements or arrangements with Cheniere and our operations to increased risks,its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements with one or more Cheniere-affiliated entities as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.
We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs,costs.
Risks Relating to Regulations
Failure to obtain and dependingmaintain 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 their ultimate magnitude,us.
The design, construction and operation of the Liquefaction Project and the export of LNG are highly regulated activities. Approvals of the FERC and DOE under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and export LNG. To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the Liquefaction Project. To date, the DOE has also issued orders under Section 4 of the NGA authorizing us to export domestically produced LNG.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. We are currently in compliance with such conditions; however, failure to comply or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns, could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Existing and future safety, 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 LNGour terminal, including the FERC, PHMSA, EPA and Coast Guard, to issue compliance orders,regulatory enforcement actions, 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, difficulty obtaining and maintaining permits from regulatory agencies 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 has finalized or proposed multiple GHG regulations that impact our assets and supply chain. Further, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of GHGIRA includes a charge on methane emissions from stationary sourcesabove certain emissions thresholds employing empirical emissions data that will apply to our facilities beginning in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals.calendar year 2024. 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 have largely been stayed or repealed including by amendments adopted by the EPA on February 23, 2018, additional proposed amendments to new source performance standards for the oil and gas industry on September 24, 2019, and the EPA’s June 19, 2019 adoption of the Affordable Clean Energy rule for power generation. However, Congress or a future Administration may reverse these decisions. Otherother international, 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 carbonGHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminal,terminals, or could increase compliance costs for our operations.
Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels 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. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.
On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022. We do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.
Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Sabine Pass LNG terminalTerminal 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.
Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Financial Statements for the years ended December 31, 2022 and 2021. 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 2020 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 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.
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ITEM 1B. | UNRESOLVED STAFF COMMENTS |
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 terminalTerminal and the commissioning of the Liquefaction Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of Cheniere’s subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of Cheniere’s subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.
PHMSA Matter
In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to us in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal.Terminal (the “2018 tank incident”). These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, we and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to us returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to us alleging violations of federal pipeline safety regulations relating to the 2018 tank incident and proposing civil penalties totaling $2,214,900.On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200.On October 12, 2021, we responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty.PHMSA notified us in a letter dated November 9, 2021 that the case was considered “closed.” We continue to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak,tank incident, including repair approach and related analysis.One tank has been placed back into operational service. We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.
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ITEM 4. | MINE SAFETY DISCLOSURE |
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
PART II
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ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.
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ITEM 6. | SELECTED FINANCIAL DATA |
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.ITEM 6. [Reserved]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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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 |
|
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Discussion of 2020 items and variance drivers between the year ended December 31, 2021 as compared to December 31, 2020 are not included herein and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K forthe fiscal year ended December 31, 2021.
Our discussion and analysis includes the following subjects:
Overview
We are a limited liability company formed by CQP to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We own the natural gas liquefaction and export facility located at Sabine Pass, Louisiana (the “Sabine Pass LNG Terminal”) with six operational natural gas liquefaction Trains (the “Liquefaction Project”). For further discussion of our business, see Items 1. and 2. Business and Properties.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We contract our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total production capacity from the Liquefaction Project with approximately 15 years of weighted average remaining life as of December 31, 2022. We believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our business in the future.
Overview of Significant Events
Liquidity and Capital Resources
Contractual Obligations
Results of Operations
Off-Balance Sheet Arrangements
Summary of Critical Accounting Estimates
Recent Accounting Standards
Overview of Business
We provide clean, secure and affordable energy to the world, while responsibly delivering a reliable, competitive and integrated source of LNG, in a safe and rewarding work environment. We are currently operating five natural gas liquefaction Trains and are constructing one additional Train 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, 20192022 and through the filing date of this Form 10-K include the following:
Strategic
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• | In May 2019, the board of directors of the general partner of Cheniere Partners made a positive final investment decision (“FID”) with respect to Train 6 of the Liquefaction Project and issued a full notice to proceed with construction to Bechtel Oil, Gas and Chemicals, Inc.(“Bechtel”) in June 2019.•In February 2023, we and our affiliate initiated the pre-filing review process with the FERC under the National Environmental Policy Act for an expansion adjacent to the Liquefaction Project consisting of up to three Trains with an expected total production capacity of approximately 20 mtpa of LNG. This expansion may be developed and constructed by an affiliate of ours outside of the Liquefaction Project. •In November 2022, we entered into an SPA with Cheniere Marketing for approximately 0.85 mtpa of LNG associated with the IPM agreement between us and Tourmaline Oil Marketing Corp., a subsidiary of Tourmaline Oil Corp (as supplier) (“Tourmaline”), discussed below. •In June 2022, we entered into an SPA with Chevron U.S.A. Inc. (“Chevron”) to sell Chevron approximately 1.0 mtpa of LNG between 2026 and 2042. •In February 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project: ◦Cheniere Marketing entered into agreements to novate to us certain SPAs entered into with ENN LNG (Singapore) Pte Ltd. and a subsidiary of Glencore plc, with effective dates of January 1, 2023 and February 17, 2022, respectively, aggregating approximately 21 million tonnes of LNG to be delivered between 2023 and 2035. ◦The board of directors of CQP approved our entry into (1) an agreement to novate to us an IPM agreement between Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”), formerly a wholly owned direct subsidiary of Cheniere (as purchaser) that merged with and into Corpus Christi Liquefaction, LLC, and Tourmaline to purchase 140,000 MMBtu per day of natural gas at a price based on Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023 (the “Tourmaline IPM”) and (2) a FOB SPA with Cheniere Marketing International LLP to sell LNG associated with the natural gas to be supplied under the IPM agreement. The agreement to assign the Tourmaline IPM agreement from CCL Stage III to us was executed and the assignment was effective on March 15, 2022.
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Operational
•As of February 21, 2020, over 90017, 2023, approximately 1,990 cumulative LNG cargoes totaling over 60135 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
In March 2019, we achieved•On February 4, 2022, substantial completion of Train 5 of the Liquefaction Project and commenced operating activities.
Financial
In September 2019, the date of first commercial delivery was reached under the 20-year SPAs with Centrica plc and Total Gas & Power North America, Inc. (“Total”) relating to Train 5 of the Liquefaction Project.
In March 2019, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC relating to Train 4 of the Liquefaction Project.
Liquidity and Capital Resources
The following table provides a summary of our liquidity position at December 31, 2019 and 2018 (in millions):
|
| | | | | | | |
| | 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 |
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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. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. 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 was achieved (the “Train 6 Completion”).
Financial
•In December and November 2022, we issued an aggregate principal amount of $70 million of 6.293% Senior Secured Notes due 2037 (the “6.293% Senior Notes”) and $430 million of 5.900% Senior Secured Amortizing Notes due 2037 (the “5.900% Senior Notes”), respectively, with a weighted average life of approximately 9.6 years and 9.5 years, respectively. The proceeds from the 6.293% Senior Notes and the 5.900% Senior Notes, together with cash on hand, were used to redeem the remaining outstanding amount of SPL’s $1.5 billion aggregate principal amount of Senior Secured Notes due 2023 (the “2023 Senior Notes”), subsequent to the $300 million redemption in October 2022.
•In September 2022, Moody’s Corporation (“Moody’s”) upgraded our issuer credit ratings from Baa3 to Baa2, with a stable outlook. Additionally, in September 2022, Fitch Ratings (“Fitch”) upgraded our issuer credit ratings from BBB- to BBB, an investment grade credit rating, with a stable outlook. In February 2023, S&P Global Ratings (“S&P”) upgraded our issuer credit ratings from BBB to BBB+ with stable outlook.
Market Environment
The LNG market in 2022 saw unprecedented price volatility across all natural gas and LNG benchmarks. Gas market fundamentals across the globe were tight and exacerbated by the Russia / Ukraine war risks, and later by the drastic reduction in Russian natural gas flows to the European Union (“EU”). Concerns over low natural gas and LNG inventories and low additional LNG supply availability early in the year were intensified by the war dynamics in Europe and by further constraints on natural gas and LNG supplies caused by the outage at the Freeport LNG facility in June and the explosion on the Nordstream 1 and Nordstream 2 Pipelines in September. Several EU policy initiatives were passed to ensure underground gas storage in the region was filled before winter. Europe had to compete for LNG cargoes resulting in unprecedented price spikes. These conditions were worsened by high coal prices, low nuclear generation output and low hydro levels in Europe, which limited optionality for power generators and deepened the energy crisis in Europe.
Despite the generally tight supply conditions, according to Kpler, global LNG demand grew by approximately 5% from 2021, adding an additional 19.5 million tonnes to the overall market. LNG imports into Europe and Turkey, increased by 45.9 million tonnes, or 61% year-over-year in 2022. This growth was primarily accompanied by a pronounced slowdown in economic activity in China, which contributed to a 7% decrease in Asia’s LNG demand of 19.1 million tonnes from 2021. These sizeable EU LNG requirements resulting from the war fallout and the increase in global demand, especially demand for increased imports to Europe and Turkey, exposed the vulnerability of the LNG industry in terms of supply constraints and under-investments. This was manifested in the price levels and the magnitude of the price spreads between the benchmarks. As an example, the Dutch Title Transfer Facility (“TTF”) monthly settlement prices averaged $40.9/MMBtu in 2022, approximately 184% higher than the $14.4/MMBtu average in 2021, and the TTF monthly settlement prices averaged $42.3/MMBtu in the fourth quarter of 2022, approximately 46% higher than the $28.9/MMBtu average in the fourth quarter of 2021. Similarly, the 2022 average settlement price for the JKM increased 128% year-over-year to an average of $34.2/MMBtu in 2022, and the fourth quarter of 2022 average settlement price for the JKM increased 38% year-over-year to an average of $38.5/MMBtu. This extreme price increase triggered a strong supply response from the U.S., which played a significant role in balancing the global LNG market. Despite the outage at Freeport LNG, the U.S. exported approximately 77 million tonnes of LNG in 2022, a gain of approximately 9% from 2021, as the market continued to pull on supplies from our facilities and those of our competitors. Exports from our Liquefaction Project reached 29.1 million tonnes, representing over 70% of the gain in the U.S. total for the year.
Despite the global impacts of the Russia / Ukraine war, we do not believe we have significant exposure to adverse direct or indirect impacts of the war, as we do not conduct business in Russia and refrain from business dealings with Russian entities. Additionally, we are not aware of any specific adverse direct or indirect effects of the war on our supply chain. Consequently, we believe we are well positioned to help meet the needs of our international LNG customers to overcome their supply shortages.
Results of Operations
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, | | |
| (in millions) | | | | | | 2022 | | 2021 | | Variance |
| Revenues | | | | | | | | | | |
| LNG revenues | | | | | | $ | 11,507 | | | $ | 7,639 | | | $ | 3,868 | |
| LNG revenues—affiliate | | | | | | 4,568 | | | 1,472 | | | 3,096 | |
| LNG revenues—related party | | | | | | — | | | 1 | | | (1) | |
| | | | | | | | | | |
| Total revenues | | | | | | 16,075 | | | 9,112 | | | 6,963 | |
| | | | | | | | | | |
| Operating costs and expenses | | | | | | | | | | |
| Cost of sales (excluding items shown separately below) | | | | | | 11,885 | | | 5,289 | | | 6,596 | |
| Cost of sales—affiliate | | | | | | 262 | | | 128 | | | 134 | |
| Cost of sales—related party | | | | | | — | | | 17 | | | (17) | |
| Operating and maintenance expense | | | | | | 652 | | | 548 | | | 104 | |
| Operating and maintenance expense—affiliate | | | | | | 482 | | | 457 | | | 25 | |
| Operating and maintenance expense—related party | | | | | | 72 | | | 46 | | | 26 | |
| | | | | | | | | | |
| | | | | | | | | | |
| General and administrative expense | | | | | | — | | | 4 | | | (4) | |
| General and administrative expense—affiliate | | | | | | 66 | | | 61 | | | 5 | |
| Depreciation and amortization expense | | | | | | 539 | | | 468 | | | 71 | |
| Other | | | | | | — | | | 6 | | | (6) | |
| | | | | | | | | | |
| Total operating costs and expenses | | | | | | 13,958 | | | 7,024 | | | 6,934 | |
| | | | | | | | | | |
| Income from operations | | | | | | 2,117 | | | 2,088 | | | 29 | |
| | | | | | | | | | |
| Other income (expense) | | | | | | | | | | |
| Interest expense, net of capitalized interest | | | | | | (667) | | | (622) | | | (45) | |
| Loss on modification or extinguishment of debt | | | | | | (2) | | | (5) | | | 3 | |
| Other income, net | | | | | | 7 | | | — | | | 7 | |
| Total other expense | | | | | | (662) | | | (627) | | | (35) | |
| | | | | | | | | | |
| Net income | | | | | | $ | 1,455 | | | $ | 1,461 | | | $ | (6) | |
Operational volumes loaded and recognized from the Liquefaction Project
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | |
| | | | | | | 2022 | | 2021 | | | | Variance |
| | | | | | | | | | | | | | | | | |
| LNG volumes loaded and recognized as revenues (in TBtu) (1) | | | | | | | 1,520 | | | 1,288 | | | | | 232 | | | | | |
| | | | | | | | | | | | | | | | | |
(1)The year ended December 31, 2019:2021 includes eight TBtu that were loaded at our affiliate’s facility.
Net income
Our net income was $1.5 billion for both of the years ended December 31, 2022 and 2021.
There was an unfavorable variance of $1.2 billion in derivative losses from changes in fair value in the year ended December 31, 2022 as compared to the same period of 2021. During the year ended December 31, 2022 we incurred losses of $757 million on the derivative liability associated with the Tourmaline IPM agreement following its assignment to us from CCL Stage III in March 2022. See Overview of Significant Eventsfor further discussion of the assignment. The associated losses following the assignment were primarily attributed to our lower credit risk profile relative to that of CCL Stage III, resulting in a higher derivative liability given reduced risk of our own nonperformance and unfavorable shifts in the international forward commodity curve. The losses on the Tourmaline IPM agreement, along with losses on our other derivative instruments, were offset by an increase in LNG revenues, net of cost of sales and excluding the effect of derivative losses, of $1.4 billion, approximately half of which was attributable to higher margins on sales indexed to Henry Hub, with variable consideration on our long-term SPAs generally priced at 115% of Henry Hub, and half of which was attributable to increased volume delivered between the comparable periods, in part due to the Train 6 Completion.
The following is additional detailed discussion of the significant variance drivers of the change in net income by line item:
Revenues. $7.0 billion increase between comparable periods primarily attributable to:
•$5.2 billion increase due to higher pricing per MMBtu, from increased Henry Hub pricing; and
•$1.8 billion increase due to higher volumes of LNG delivered between the periods, which increased 38 TBtu or 5%, as result of the additional production capacity of approximately 5 mtpa arising from the Train 6 Completion.
Operating costs and expenses. $6.9 billion increase between comparable periods primarily attributable to:
•$5.5 billion increase in cost of sales excluding the effect of derivative losses described below, primarily as a result of $5.4 billion in increased cost of natural gas feedstock largely due to higher U.S. natural gas prices and, to a lesser extent, from increased volume of natural gas liquified and delivered as LNG, as discussed above under the caption Revenues; and
•$1.2 billion unfavorable variance in derivative losses from changes in fair value and settlements included in cost of sales, from $32 million derivative gain in the year ended December 31, 2021 to $1.2 billion derivative loss in the year ended December 31, 2022, primarily due to non-cash unfavorable changes in fair value of our commodity derivatives that are attributed to positions indexed to international gas prices, specifically associated with the Tourmaline IPM agreement that was assigned to us as discussed in Net income above.
Significant factors affecting our results of operations
In addition to sources and uses of liquidity as discussed in Liquidity and Capital Resources, below are additional significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risks and are reported at fair value on our Financial Statements. For commodity derivative instruments related to our IPM agreement assigned to us during the year ended December 31, 2022 as described further in Overview of Significant Events, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside our control, notwithstanding the operational intent to mitigate risk exposure over time.
Commissioning cargoes
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, 2022 and 2021, we realized offsets to LNG terminal costs of $148 million and $105 million, respectively, corresponding to 13 TBtu and 12 TBtu, respectively, that were related to the sale of commissioning cargoes from Train 6 of the Liquefaction Project.
Liquidity and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
| | | | | | | |
| December 31, 2022 |
| | | |
| | | |
| Restricted cash and cash equivalents designated for the Liquefaction Project | $ | Train 692 | | | |
Overall project completion percentage | | 43.7% | |
Completion percentage of: | |
| |
EngineeringAvailable commitments under our working capital revolving credit and letter of credit reimbursement agreement (the “Working Capital Facility”) (1) | 872 | 91.5% | | |
Procurement | | 60.9% | |
Subcontract workTotal available liquidity | $ | 37.4% |
Construction964 | | 9.7% |
Date of expected substantial completion | | 1H 2023 |
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under the Working Capital Facility as of December 31, 2022. See Note 10—Debt of our Notes to Financial Statements for additional information on the Working Capital Facility and other debt instruments.
Our liquidity position subsequent to December 31, 2022 will be driven by future sources of liquidity and future cash requirements as further discussed below under the caption Future Sources and Uses of Liquidity.
Future Sources and Uses of Liquidity
Future Sources of Liquidity under Executed Contracts
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs which has not yet been recognized as revenue. This future consideration is in most cases not yet legally due to us and was not reflected on our Balance Sheets as of December 31, 2022. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following orderstable summarizes our estimate of future material sources of liquidity to be received from executed contracts as of December 31, 2022 (in billions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Revenues Under Executed Contracts by Period (1) |
| | | | | | | | |
| | | 2023 | | 2024 - 2027 | | Thereafter | | Total |
| LNG revenues (fixed fees) (2) | | $ | 3.7 | | | $ | 14.7 | | | $ | 34.4 | | | $ | 52.8 | |
| | | | | | | | |
| LNG revenues (variable fees) (2) (3) | | 8.1 | | | 30.6 | | | 69.9 | | | 108.6 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Total | | $ | 11.8 | | | $ | 45.3 | | | $ | 104.3 | | | $ | 161.4 | |
(1)Agreements in force as of December 31, 2022 that have been issued byterms dependent on project milestone dates are based on the DOE authorizingestimated dates as of December 31, 2022. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the exporttiming difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of domestically produced December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)LNG by vesselrevenues (including $2.0 billion and $12.9 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises their contractual right to not take delivery of an LNG cargo under the Sabine Passcontract. Variable fees are receivable only in connection with LNG terminal:cargoes that are delivered.
Trains 1 through 4—FTA countries for(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2022. The pricing structure of our SPA arrangements with our customers incorporates a 30-year term,variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which commencedis paid upon delivery, thus limiting our net exposure to future increases in May 2016, and non-FTA countries for a 20-year term, which commenced in June 2016, 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 in December 2018, 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 2019prices. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the remainder commenced in September 2019, in an amount up to a combined totalmovement of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
In each case, the terms of these authorizations began on 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 to each of the non-FTA orders for LNG volumes we were authorized but unable to export during any portion of the initial 20-year export period ofvarious indexes. We have not included such order.
The DOE issued orders authorizing us to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing January 2020, in an aggregate amount upvariable consideration to the equivalent of 600 Bcf of natural gas (however, exports under this order, when combined with exports underextent the orders above, may not exceed 1,509 Bcf/yr).
An application was filed in September 2019 to authorize 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 upconsideration is considered constrained due to the equivalentuncertainty of approximately 153 Bcf/yr of natural gas, for a total Liquefaction Project export 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. The application is currently pending before DOE.ultimate pricing and receipt.
Customers
We
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):
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, 2019,2022, 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/ Michael J. WortleyZach Davis |
| Jack A. Fusco | | | Michael J. WortleyZach Davis |
| Chief Executive Officer
(Principal Executive Officer) | | | Manager and Chief Financial Officer
(Principal Financial Officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Member of Sabine Pass Liquefaction, LLC and
Board of Directors of Cheniere Energy Partners GP, LLC
Sabine Pass Liquefaction, LLC:
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Sabine Pass Liquefaction, LLC (the Company) as of December 31, 20192022 and 2018,2021, 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, 2019,2022, 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, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019,2022, 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 $(3,719) million, as of December 31, 2022. The physical liquefaction supply derivatives consist of natural gas supply contracts for the operation of the liquefied natural gas facility. The fair value of the level 3 physical liquefaction supply derivatives is developed using internal models that incorporate significant unobservable inputs.
We identified the evaluation of the fair value of the level 3 physical liquefaction supply derivatives as a critical audit matter. Specifically, there is subjectivity in certain assumptions used to estimate the fair value, including assumptions for future prices of energy units for unobservable periods and liquidity.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of the level 3 physical liquefaction supply derivatives. This included controls related to the assumptions for significant unobservable inputs and the fair value model. For a selection of level 3 liquefaction supply derivatives, we involved valuation professionals with specialized skills and knowledge who assisted in:
•evaluating the future prices of energy units for observable periods by comparing to market data, including quoted or published forward prices
•developing independent fair value estimates and comparing the independently developed estimates to the Company’s fair value estimates.
In addition, we evaluated the Company’s assumptions for future prices of energy units for unobservable periods and liquidity by comparing them to market or third-party data, including adjustments for third party quoted transportation prices.
We have served as the Company’s auditor since 2014.
Houston, Texas
February 24, 202022, 2023
SABINE PASS LIQUEFACTION, LLC
BALANCE SHEETSSTATEMENTS OF INCOME
(in millions)
|
| | | | | | | | |
| | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2022 | | 2021 | | 2020 |
| Revenues | | | | | | | | | | |
| LNG revenues | | | | | | $ | 11,507 | | | $ | 7,639 | | | $ | 5,195 | |
| LNG revenues—affiliate | | | | | | 4,568 | | | 1,472 | | | 662 | |
| LNG revenues—related party | | | | | | — | | | 1 | | | — | |
| | | | | | | | | | |
| Total revenues | | | | | | 16,075 | | | 9,112 | | | 5,857 | |
| | | | | | | | | | |
| Operating costs and expenses | | | | | | | | | | |
| Cost of sales (excluding items shown separately below) | | | | | | 11,885 | | | 5,289 | | | 2,504 | |
| Cost of sales—affiliate | | | | | | 262 | | | 128 | | | 110 | |
| Cost of sales—related party | | | | | | — | | | 17 | | | — | |
| Operating and maintenance expense | | | | | | 652 | | | 548 | | | 547 | |
| Operating and maintenance expense—affiliate | | | | | | 482 | | | 457 | | | 466 | |
| Operating and maintenance expense—related party | | | | | | 72 | | | 46 | | | 13 | |
| | | | | | | | | | |
| | | | | | | | | | |
| General and administrative expense | | | | | | — | | | 4 | | | 9 | |
| General and administrative expense—affiliate | | | | | | 66 | | | 61 | | | 71 | |
| Depreciation and amortization expense | | | | | | 539 | | | 468 | | | 465 | |
| Other | | | | | | — | | | 6 | | | 1 | |
| | | | | | | | | | |
| Total operating costs and expenses | | | | | | 13,958 | | | 7,024 | | | 4,186 | |
| | | | | | | | | | |
| Income from operations | | | | | | 2,117 | | | 2,088 | | | 1,671 | |
| | | | | | | | | | |
| Other income (expense) | | | | | | | | | | |
| Interest expense, net of capitalized interest | | | | | | (667) | | | (622) | | | (685) | |
| Loss on modification or extinguishment of debt | | | | | | (2) | | | (5) | | | (43) | |
| Other income, net | | | | | | 7 | | | — | | | — | |
| Total other expense | | | | | | (662) | | | (627) | | | (728) | |
| | | | | | | | | | |
| Net income | | | | | | $ | 1,455 | | | $ | 1,461 | | | $ | 943 | |
The accompanying notes are an integral part of these financial statements.
3735
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF INCOMEBALANCE SHEETS
(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, |
| | | | |
| | 2022 | | 2021 |
| ASSETS | | | | |
| Current assets | | | | |
| | | | |
| Restricted cash and cash equivalents | | $ | 92 | | | $ | 98 | |
| Trade and other receivables, net of current expected credit losses | | 622 | | | 571 | |
| Accounts receivable—affiliate | | 553 | | | 232 | |
| Accounts receivable—related party | | — | | | 1 | |
| Advances to affiliate | | 151 | | | 127 | |
| Inventory | | 143 | | | 159 | |
| Current derivative assets | | 24 | | | 21 | |
| Margin deposits | | 35 | | | 7 | |
| | | | |
| Other current assets | | 33 | | | 53 | |
| Other current assets—affiliate | | 21 | | | 21 | |
| Total current assets | | 1,674 | | | 1,290 | |
| | | | |
| | | | |
| Property, plant and equipment, net of accumulated depreciation | | 13,805 | | | 14,433 | |
| | | | |
| Debt issuance costs, net of accumulated amortization | | 5 | | | 7 | |
| Derivative assets | | 28 | | | 33 | |
| Other non-current assets, net | | 160 | | | 171 | |
| | | | |
| Total assets | | $ | 15,672 | | | $ | 15,934 | |
| | | | |
| LIABILITIES AND MEMBER’S EQUITY (DEFICIT) | | | | |
| Current liabilities | | | | |
| Accounts payable | | $ | 28 | | | $ | 18 | |
| Accrued liabilities | | 1,314 | | | 1,012 | |
| Accrued liabilities—related party | | 6 | | | 4 | |
| | | | |
| Due to affiliates | | 80 | | | 73 | |
| Deferred revenue | | 132 | | | 132 | |
| | | | |
| Current derivative liabilities | | 769 | | | 16 | |
| | | | |
| | | | |
| Total current liabilities | | 2,329 | | | 1,255 | |
| | | | |
| Long-term debt, net of premium, discount and debt issuance costs | | 12,040 | | | 13,023 | |
| | | | |
| Derivative liabilities | | 3,024 | | | 11 | |
| Other non-current liabilities | | 7 | | | 7 | |
| Other non-current liabilities—affiliate | | 20 | | | 17 | |
| | | | |
Commitments and contingencies (see Note 13) | | | | |
| | | | |
| Member’s equity (deficit) | | (1,748) | | | 1,621 | |
| Total liabilities and member’s equity (deficit) | | $ | 15,672 | | | $ | 15,934 | |
The accompanying notes are an integral part of these financial statements.
3836
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF MEMBER’S EQUITY (DEFICIT)
(in millions)
|
| | | | | | | |
| | 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 |
|
| | | | | | | | | | | | | |
|
| Sabine Pass LNG-LP, LLC | | | | Total Member’s Equity (Deficit) |
| Balance at December 31, 2019 | $ | 534 | | | | | $ | 534 | |
| Capital contributions | 488 | | | | | 488 | |
| Distributions | (1,007) | | | | | (1,007) | |
| Net income | 943 | | | | | 943 | |
| Balance at December 31, 2020 | 958 | | | | | 958 | |
| Capital contributions | 821 | | | | | 821 | |
| Distributions | (1,619) | | | | | (1,619) | |
| Net income | 1,461 | | | | | 1,461 | |
| Balance at December 31, 2021 | 1,621 | | | | | 1,621 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Capital contributions | 225 | | | | | 225 | |
Novated IPM Agreement (see Note 15) | (2,712) | | | | | (2,712) | |
Non-cash distributions to affiliates for conveyance of assets (see Note 12) | (576) | | | | | (576) | |
| Distributions | (1,761) | | | | | (1,761) | |
| Net income | 1,455 | | | | | 1,455 | |
| Balance at December 31, 2022 | $ | (1,748) | | | | | $ | (1,748) | |
The accompanying notes are an integral part of these financial statements.
3937
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, |
| 2022 | | 2021 | | 2020 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 1,455 | | | $ | 1,461 | | | $ | 943 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| | | | | |
| Depreciation and amortization expense | 539 | | | 468 | | | 465 | |
| Amortization of debt issuance costs, premium and discount | 24 | | | 22 | | | 24 | |
| Loss on modification of debt | 2 | | | 5 | | | 43 | |
| Losses (gains) on derivative instruments, net | 1,158 | | | (29) | | | 49 | |
| Total gains on derivatives instruments, net—related party | — | | | (2) | | | — | |
| Net cash used for settlement of derivative instruments | (102) | | | (17) | | | (4) | |
| Other | 7 | | | 6 | | | 1 | |
| Changes in operating assets and liabilities: | | | | | |
| Trade and other receivables, net of current expected credit losses | (116) | | | (203) | | | (17) | |
| Accounts receivable—affiliate | (337) | | | (32) | | | (80) | |
| Accounts receivable—related party | — | | | (1) | | | — | |
| Advances to affiliate | (24) | | | (5) | | | 5 | |
| Inventory | 15 | | | (66) | | | 9 | |
| Margin deposits | (28) | | | (3) | | | (2) | |
| Accounts payable and accrued liabilities | 348 | | | 326 | | | 2 | |
| Accrued liabilities—related party | 3 | | | (1) | | | 4 | |
| Due to affiliates | 22 | | | (1) | | | 9 | |
| Deferred revenue | — | | | 18 | | | (18) | |
| Deferred revenue—affiliate | — | | | — | | | (10) | |
| Other, net | 2 | | | (11) | | | 1 | |
| Other, net—affiliate | 5 | | | 2 | | | — | |
| Net cash provided by operating activities | 2,973 | | | 1,937 | | | 1,424 | |
| | | | | |
| Cash flows from investing activities | | | | | |
| Property, plant and equipment | (434) | | | (612) | | | (916) | |
| | | | | |
| | | | | |
| Net cash used in investing activities | (434) | | | (612) | | | (916) | |
| | | | | |
| Cash flows from financing activities | | | | | |
| Proceeds from issuances of debt | 560 | | | 482 | | | 1,995 | |
| Redemptions and repayments of debt | (1,560) | | | (1,000) | | | (2,000) | |
| Debt issuance and other financing costs | (7) | | | (5) | | | (35) | |
| Debt extinguishment costs | (2) | | | (3) | | | (39) | |
| Capital contributions | 225 | | | 821 | | | 488 | |
| Distributions | (1,761) | | | (1,619) | | | (1,001) | |
| Net cash used in financing activities | (2,545) | | | (1,324) | | | (592) | |
| | | | | |
| Net increase (decrease) in restricted cash and cash equivalents | (6) | | | 1 | | | (84) | |
| Restricted cash and cash equivalents—beginning of period | 98 | | | 97 | | | 181 | |
| Restricted cash and cash equivalents—end of period | $ | 92 | | | $ | 98 | | | $ | 97 | |
Balances per Balance Sheets:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Cash and cash equivalents | $ | — |
| | $ | — |
|
| Restricted cash | 181 |
| | 756 |
|
| Total cash, cash equivalents and restricted cash | $ | 181 |
| | $ | 756 |
|
The accompanying notes are an integral part of these financial statements.
4038
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 companyCQP and based in Houston with 1one member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of Cheniere Partners.CQP. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of Cheniere Partners,CQP, a publicly traded limited partnership (NYSE MKT: CQP). Cheniere PartnersCQP 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 PartnersCQP through ownership in Cheniere Energy Partners GP, LLC.
We are currently operating 5The natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) has six operational Trains, and are constructing 1 additionalwith Train 6 having achieved substantial completion on February 4, 2022, for a total operational production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities owned by SPLNG.
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.Terminal, which provides opportunity for further liquefaction capacity expansion. The Sabine Passdevelopment of this site or other projects, including infrastructure projects in support of natural gas supply and 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 owneddemand, will require, among other things, acceptable commercial and operated by SPLNG.financing arrangements before we make a positive final investment decision.
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
We adopted Accounting Standards Update (“ASU”) 2016-02,
Leases (Topic 842), and subsequent amendments thereto on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. The adoption of the standard did not materially impact our Financial Statements. Upon adoption of the standard we recorded right-of-use assets of $20 million in other non-current assets, net, and lease liabilities of $4 million in other non-current liabilities and $16 million in other non-current liabilities—affiliate.
Use of Estimates
The preparation of our 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,of derivatives and other instruments, useful lives of 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 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.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
The carrying amount of restricted cash and cash equivalents, restricted cash,trade and other receivables, net of current expected credit losses, margin deposits, accounts receivablepayable and accounts payableaccrued liabilities 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
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
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.our revenue streams and accounting policies related to revenue recognition.
Restricted 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 consistsand cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Accounts ReceivableCurrent Expected Credit Losses
Accounts receivable isTrade and other receivables are reported net of any allowances for doubtful accounts. We periodically reviewcurrent expected credit losses. Current expected credit losses consider the collectability on our accounts receivable and recognize an allowance if there is probabilityrisk of non-collection,loss based on historical write-offpast events, current conditions and customer-specific factors. We did 0t have an allowance onreasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our accounts receivable asassessment 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, 20192022 and 2018.2021, we had current expected credit losses of zero and $5 million, respectively, on our trade and other receivables and as of both December 31, 2022 and 2021, we had current expected credit losses of zero on our non-current contract assets.
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 subsequentlyvalue. Inventory is charged to expense when issued.sold, or for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.
AccountingProperty, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for LNG Activitiesconstruction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.
Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to the Train.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. 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.
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.method over assigned useful lives. Refer to Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in impairment expenseother operating costs and loss (gain) on disposal of assets.expenses.
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
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 not record any material impairments related to property, plant and equipment during the years ended December 31, 2022, 2021 and 2020.
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,placing the underlying asset in service, these costs are transferred out of construction-in-process into terminalthe respective in-service asset category and interconnecting pipeline facilities assets and are amortizeddepreciated over the estimated useful life of the asset.corresponding assets, except for capitalized interest associated with land, which is not depreciated.
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.exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intendintent to net settle, derivative assets and liabilities are reported on a net basis.
ChangesFor those derivative instruments measured at fair value, changes in the fair value of our derivativethe instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did 0tnot have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2019, 20182022, 2021 and 2017.2020. 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. Wereceivable related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets.margin deposits. 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 811 third parties and have entered into agreements with Cheniere Marketing. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.
Debt
Our debt consists of current and long-term secured and unsecured debt securities and a credit facilitiesfacility 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, printing costs and printing costs.in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, theythe debt issuance costs are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
interest method. Gains and losses on the extinguishment or modification of debt are recorded in gain (loss)loss on modification or extinguishment of debt on our Statements of Income.
We classify debt on our Balance Sheets based on contractual maturity, with the following exceptions:
•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.
•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
We have 0tnot recorded an ARO associated with the Sabine Pass LNG terminal.Terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal,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 terminalTerminal 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 terminalTerminal 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,CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP taxable income. Accordingly, 0no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.
At December 31, 2019,2022, the tax
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
basis of our assets and liabilities was $4.6$5.8 billion less than the reported amounts of our assets and liabilities.
See 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 for details about 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 incomeunder our tax payments to the appropriate taxing authorities.sharing agreement.
Business Segment
Our liquefaction operations at the Sabine Pass LNG terminalTerminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of SPL in total when evaluating financial performance and for purposes of allocating resources.
Recent Accounting Standards
ASU 2020-04
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard. We have not yet applied the optional expedients available under the standard because we have not yet modified any of our existing contracts indexed to LIBOR, mainly our credit facility as further described in Note 10—Debt, for reference rate reform. However, we do not expect the impact of applying the optional expedients to any future contract modifications to be material, and we do not expect the transition to a replacement rate index to have a material impact on our future cash flows.
NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS
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, 2019 and 2018, restricted cash consisted of the following (in millions):
|
| | | | | | | | |
| | | 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.
As of December 31, 2022 and 2021, we had $92 million and $98 million of restricted cash and cash equivalents, respectively, as required by the above agreement.
NOTE 4—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES
Trade and other receivables, net of current expected credit losses consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2022 | | 2021 |
| Trade receivables | | $ | 603 | | | $ | 546 | |
| Other receivables | | 19 | | | 25 | |
| Total trade and other receivables, net of current expected credit losses | | $ | 622 | | | $ | 571 | |
NOTE 5—INVENTORY
Inventory consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2022 | | 2021 |
| Materials | | $ | 87 | | | $ | 71 | |
| LNG | | 26 | | | 44 | |
| Natural gas | | 28 | | | 43 | |
| Other | | 2 | | | 1 | |
| Total inventory | | $ | 143 | | | $ | 159 | |
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 4—ACCOUNTS6—PROPERTY, PLANT AND OTHER RECEIVABLESEQUIPMENT, NET OF ACCUMULATED DEPRECIATION
AsProperty, plant and equipment, net of December 31, 2019 and 2018, accounts and other receivablesaccumulated depreciation consisted of the following (in millions):
|
| | | | | | | | |
| | | December 31, |
| | | 2019 | | 2018 |
| Trade receivable | | $ | 283 |
| | $ | 330 |
|
| Other accounts receivable | | 9 |
| | 16 |
|
| Total accounts and other receivables | | $ | 292 |
| | $ | 346 |
|
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2022 | | 2021 |
| LNG terminal | | | | |
| Terminal | | $ | 16,240 | | | $ | 13,751 | |
| Construction-in-process (1) | | 114 | | | 2,699 | |
| Accumulated depreciation | | (2,553) | | | (2,021) | |
| Total LNG terminal, net of accumulated depreciation | | 13,801 | | | 14,429 | |
| Fixed assets | | | | |
| Fixed assets | | 19 | | | 19 | |
| Accumulated depreciation | | (15) | | | (15) | |
| Total fixed assets, net of accumulated depreciation | | 4 | | | 4 | |
| Property, plant and equipment, net of accumulated depreciation | | $ | 13,805 | | | $ | 14,433 | |
NOTE 5—INVENTORY
As of December 31, 2019 and 2018, inventory consisted(1)In October 2022, we completed construction of the following (in millions):
|
| | | | | | | | |
| | | 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
Asthird marine berth at the Sabine Pass LNG Terminal for a total cost of December 31, 2019$576 million and 2018,upon completion, we conveyed the property, plant and equipment net consisted ofassociated with the following (in millions):third berth to SPLNG.
|
| | | | | | | | |
| | | 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 |
|
DepreciationThe following table shows depreciation expense was $442 million, $339 million and $257 million during the years ended December 31, 2019, 2018 and 2017, respectively.
We realized offsets to LNG terminal costs of $48 million, $94 million and $301 million during the years ended December 31, 2019, 2018 and 2017, respectively, that were(in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2022 | | 2021 | | 2020 |
| Depreciation expense | | | | | | $ | 534 | | | $ | 463 | | | $ | 460 | |
| Offsets to LNG terminal costs (1) | | | | | | 148 | | | 105 | | | — | |
(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.
LNG Terminal Costs
LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 76 and 50 years, as follows:
|
| | | | | | | |
| Components | | Useful life (yrs)(years) |
| Water pipelines | | 30 |
| Liquefaction processing equipment | | 7-506-50 |
| Other | | 10-30 |
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
Fixed Assets and Other
Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
NOTE 7—DERIVATIVE INSTRUMENTS
We have entered into commodity derivatives consisting of natural gas supply contracts, including those under our IPM agreement, for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). We had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of our credit facilities (“Interest Rate Derivatives”), and these Interest Rate Derivatives were settled in March 2017.
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Statements of Income to the extent not utilized for the commissioning process.process, in which case such changes are capitalized.
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2019 and 2018, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements as of |
| December 31, 2022 | | December 31, 2021 |
| Quoted Prices in Active Markets
(Level 1) | | Significant Other Observable Inputs
(Level 2) | | Significant Unobservable Inputs
(Level 3) | | Total | | Quoted Prices in Active Markets
(Level 1) | | Significant Other Observable Inputs
(Level 2) | | Significant Unobservable Inputs
(Level 3) | | Total |
| | | | | | | | | | | | | | | |
| Liquefaction Supply Derivatives asset (liability) | $ | (12) | | | $ | (10) | | | $ | (3,719) | | | $ | (3,741) | | | $ | 2 | | | $ | (13) | | | $ | 38 | | | $ | 27 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements as of |
| | December 31, 2019 | | December 31, 2018 |
| | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| Liquefaction Supply Derivatives asset (liability) | $ | 3 |
| | $ | (3 | ) | | $ | 24 |
| | $ | 24 |
| | $ | 5 |
| | $ | (23 | ) | | $ | (25 | ) | | $ | (43 | ) |
We value our Liquefaction Supply Derivatives using a market-basedmarket or option-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.
The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value including, evaluatingbut not limited to, evaluation of whether the respective market is availableexists from the perspective of market participants as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives 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. As of December 31, 2019 and 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.
We include a significant portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity volatility and contract duration.volatility.
The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2019:2022:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net Fair Value Asset Liability
(in millions) | | Valuation Approach | | Significant Unobservable Input | | Range of Significant Unobservable Inputs Range/ Weighted Average (1) |
Physical Liquefaction Supply Derivatives | | $24(3,719) | | Market approach incorporating present value techniques | | Henry Hub basis spread | | $(0.350)(1.775) - $0.058$0.660 / $(0.063) |
| | | | Option pricing model | | International LNG pricing spread, relative to Henry Hub (2) | | 77% - 515% / 193% |
(1)Unobservable inputs were weighted by the relative fair value of the instruments.
(2)Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.
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NOTES TO FINANCIAL STATEMENTS—CONTINUED
The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2019, 2018 and 2017 (in millions):
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| Balance, beginning of period | | $ | (25 | ) | | $ | 43 |
| | $ | 79 |
|
| Realized and mark-to-market gains (losses): | | | | | | |
| Included in cost of sales | | 6 |
| | (3 | ) | | (37 | ) |
| Purchases and settlements: | | | | | | |
| Purchases | | — |
| | (37 | ) | | 14 |
|
| Settlements | | 42 |
| | (29 | ) | | (12 | ) |
| Transfers out of Level 3 (1) | | 1 |
| | 1 |
| | (1 | ) |
| Balance, end of period | | $ | 24 |
| | $ | (25 | ) | | $ | 43 |
|
| Change in unrealized gains (losses) relating to instruments still held at end of period | | $ | 6 |
| | $ | (3 | ) | | $ | (37 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2022 | | 2021 | | 2020 |
| Balance, beginning of period | | | | | | $ | 38 | | | $ | (21) | | | $ | 24 | |
| Realized and change in fair value gains (losses) included in net income (1): | | | | | | | | | | |
| Included in cost of sales, existing deals (2) | | | | | | (228) | | | 74 | | | (43) | |
| Included in cost of sales, new deals (3) | | | | | | (804) | | | — | | | — | |
| Purchases and settlements: | | | | | | | | | | |
| Purchases (4) | | | | | | (2,712) | | | (10) | | | 5 | |
| Settlements (5) | | | | | | (13) | | | (5) | | | (7) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Balance, end of period | | | | | | $ | (3,719) | | | $ | 38 | | | $ | (21) | |
| Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period | | | | | | $ | (1,032) | | | $ | 74 | | | $ | (43) | |
(1) TransferredDoes not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to Level 2contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.
(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as a resultderivatives assigned or novated during the reporting period and continuing to exist at the end of observable market forthe period. For further discussion of IPM agreements that were novated to us during the period, see Note 15—Supplemental Cash Flow Information. (5)Roll-off in the current period of amounts recognized in our Balance Sheets at the end of the previous period due to settlement of the underlying natural gas purchase agreements.instruments in the current period.
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as allAll counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements.measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
Interest Rate Derivatives
In March 2017, we settled the Interest Rate Derivatives we previously had to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities we entered into in June 2015.
The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Statements of Income during the years ended December 31, 2019, 2018 and 2017 (in millions):
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| Interest Rate Derivatives loss | | $ | — |
| | $ | — |
| | $ | (2 | ) |
Liquefaction Supply Derivatives
We have entered intohold Liquefaction Supply Derivatives which are primarily index-based physicalindexed to the natural gas supply contractsmarket and associated economic hedges to purchase natural gas for the commissioning and operationinternational LNG indices. The terms of the Liquefaction Project. The remaining terms of the physical natural gas supply contractsSupply Derivatives range up to 1015 years, some of which commence upon the satisfaction of certain events or states of affairs.
The forward notional natural gas position ofamount for our Liquefaction Supply Derivatives was approximately 3,6635,972 TBtu and 2,9785,194 TBtu as of December 31, 20192022 and 2018, respectively.2021, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of December 31, 2022.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Statements of Income (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Gain (Loss) Recognized in Statements of Income |
| Statements of Income Location (1) | | | | Year Ended December 31, |
| | | | | | 2022 | | 2021 | | 2020 |
| LNG revenues | | | | | | $ | 1 | | | $ | (1) | | | $ | — | |
| Cost of sales | | | | | | (1,159) | | | 30 | | | (49) | |
| Cost of sales—related party | | | | | | — | | | 2 | | | — | |
(1)Does not include the value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
Fair Value and Location of Derivative Assets and Liabilities on the Balance Sheets
The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions):
|
| | | | | | | | |
| | | Fair Value Measurements as of (1) |
| Balance Sheet Location | | December 31, 2019 | | December 31, 2018 |
| Derivative assets | | $ | 17 |
| | $ | 6 |
|
| Non-current derivative assets | | 32 |
| | 31 |
|
| Total derivative assets | | 49 |
| | 37 |
|
| | | | | |
| Derivative liabilities | | (9 | ) | | (66 | ) |
| Non-current derivative liabilities | | (16 | ) | | (14 | ) |
| Total derivative liabilities | | (25 | ) | | (80 | ) |
| | | | | |
| Derivative asset (liability), net | | $ | 24 |
| | $ | (43 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | |
| | | | | | | | | | | | |
| | Fair Value Measurements as of (1) | | | | |
| Balance Sheets Location | | December 31, 2022 | | | | | | December 31, 2021 | | | | |
| Current derivative assets | | $ | 24 | | | | | | | $ | 21 | | | | | |
| Derivative assets | | 28 | | | | | | | 33 | | | | | |
| Total derivative assets | | 52 | | | | | | | 54 | | | | | |
| | | | | | | | | | | | |
| Current derivative liabilities | | (769) | | | | | | | (16) | | | | | |
| Derivative liabilities | | (3,024) | | | | | | | (11) | | | | | |
| Total derivative liabilities | | (3,793) | | | | | | | (27) | | | | | |
| | | | | | | | | | | | |
| Derivative asset (liability), net | | $ | (3,741) | | | | | | | $ | 27 | | | | | |
| |
(1) | Does not include collateral posted with counterparties by us of $2(1)Does not include collateral posted with counterparties by us of $35 million and $7 million, and $1 million for such contracts, which are included in other current assets in our Balance Sheets as of December 31, 2019 and 2018, respectively. |
The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Statements of Income during the years ended December 31, 2019, 20182022 and 2017 (in millions):2021, respectively, which are included in margin deposits in our Balance Sheets.
|
| | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | Statement of Income Location (1) | | 2019 | | 2018 | | 2017 |
| Liquefaction Supply Derivatives gain (loss) | LNG revenues | | $ | 1 |
| | $ | (1 | ) | | $ | — |
|
| Liquefaction Supply Derivatives gain (loss) | Cost of sales | | 71 |
| | (100 | ) | | (24 | ) |
| |
(1) | Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument. |
Balance SheetSheets Presentation
Our derivative instruments are presented on a net basis on our Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions): for our derivative instruments that are presented on a net basis on our Balance Sheets:
| | | | | | | | |
| | Liquefaction Supply Derivatives |
| As of December 31, 2022 | | |
| Gross assets | | $ | 57 | |
| Offsetting amounts | | (5) | |
| Net assets | | $ | 52 | |
| | |
| Gross liabilities | | $ | (3,814) | |
| Offsetting amounts | | 21 | |
| Net liabilities | | $ | (3,793) | |
| | |
| As of December 31, 2021 | | |
| Gross assets | | $ | 79 | |
| Offsetting amounts | | (25) | |
| Net assets | | $ | 54 | |
| | |
| Gross liabilities | | $ | (33) | |
| Offsetting amounts | | 6 | |
| Net liabilities | | $ | (27) | |
|
| | | | | | | | | | | | |
| | | Gross Amounts Recognized | | Gross Amounts Offset in the Balance Sheets | | Net Amounts Presented in the Balance Sheets |
| Offsetting Derivative Assets (Liabilities) | | | |
| As of December 31, 2019 | | | | | | |
| Liquefaction Supply Derivatives | | $ | 51 |
| | $ | (2 | ) | | $ | 49 |
|
| Liquefaction Supply Derivatives | | (27 | ) | | 2 |
| | (25 | ) |
| As of December 31, 2018 | | | | | | |
| Liquefaction Supply Derivatives | | $ | 63 |
| | $ | (26 | ) | | $ | 37 |
|
| Liquefaction Supply Derivatives | | (92 | ) | | 12 |
| | (80 | ) |
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 8—OTHER NON-CURRENT ASSETS, NET
As of December 31, 2019 and 2018, otherOther non-current assets, net consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2022 | | 2021 |
| Advances made to municipalities for water system enhancements | | $ | 78 | | | $ | 81 | |
| Advances and other asset conveyances to third parties to support LNG terminal | | 31 | | | 37 | |
| Operating lease assets | | 23 | | | 23 | |
| | | | |
| Advances made under EPC and non-EPC contracts | | — | | | 5 | |
| Information technology service prepayments | | 4 | | | 4 | |
| Other | | 24 | | | 21 | |
| Total other non-current assets, net | | $ | 160 | | | $ | 171 | |
|
| | | | | | | | |
| | | December 31, |
| | | 2019 | | 2018 |
| Advances made to municipalities for water system enhancements | | $ | 87 |
| | $ | 90 |
|
| Advances and other asset conveyances to third parties to support LNG terminal | | 35 |
| | 36 |
|
| Operating lease assets | | 21 |
| | — |
|
| Information technology service prepayments | | 6 |
| | 16 |
|
| Advances made under EPC and non-EPC contracts | | 15 |
| | 14 |
|
| Other | | 1 |
| | 2 |
|
| Total other non-current assets, net | | $ | 165 |
| | $ | 158 |
|
NOTE 9—ACCRUED LIABILITIES
As of December 31, 2019 and 2018, accruedAccrued liabilities consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2022 | | 2021 |
| Natural gas purchases | | $ | 1,017 | | | $ | 786 | |
| Interest costs and related debt fees | | 165 | | | 133 | |
| Liquefaction Project costs | | 125 | | | 89 | |
| Other accrued liabilities | | 7 | | | 4 | |
| Total accrued liabilities | | $ | 1,314 | | | $ | 1,012 | |
|
| | | | | | | | |
| | | December 31, |
| | | 2019 | | 2018 |
| Interest costs and related debt fees | | $ | 186 |
| | $ | 186 |
|
| Accrued natural gas purchases | | 325 |
| | 518 |
|
| Liquefaction Project costs | | 116 |
| | 64 |
|
| Other accrued liabilities | | 2 |
| | — |
|
| Total accrued liabilities | | $ | 629 |
| | $ | 768 |
|
NOTE 10—DEBT
As of December 31, 2019 and 2018, our debtDebt consisted of the following (in millions):
| | | | | | | | | | | | | | |
| | December 31, |
| | | | |
| | 2022 | | 2021 |
| Senior Secured Notes: | | | | |
| | | | |
| 5.625% due 2023 | | $ | — | | | $ | 1,500 | |
| 5.75% due 2024 | | 2,000 | | | 2,000 | |
| 5.625% due 2025 | | 2,000 | | | 2,000 | |
| 5.875% due 2026 | | 1,500 | | | 1,500 | |
| 5.00% due 2027 | | 1,500 | | | 1,500 | |
| 4.200% due 2028 | | 1,350 | | | 1,350 | |
| 4.500% due 2030 | | 2,000 | | | 2,000 | |
| 4.746% weighted average rate due 2037 | | 1,782 | | | 1,282 | |
| Total Senior Secured Notes | | 12,132 | | | 13,132 | |
| Working capital revolving credit and letter of credit reimbursement agreement (the “Working Capital Facility”) | | — | | | — | |
| Total debt | | 12,132 | | | 13,132 | |
| | | | |
| | | | |
| | | | |
| Unamortized premium, discount and debt issuance costs, net | | (92) | | | (109) | |
| Total long-term debt, net of premium, discount and debt issuance costs | | $ | 12,040 | | | $ | 13,023 | |
|
| | | | | | | | |
| | | December 31, |
| | | 2019 | | 2018 |
| Long-term debt | | | | |
| 5.625% Senior Secured Notes due 2021 (“2021 Senior Notes”) | | $ | 2,000 |
| | $ | 2,000 |
|
| 6.25% Senior Secured Notes due 2022 (“2022 Senior Notes”) | | 1,000 |
| | 1,000 |
|
| 5.625% Senior Secured Notes due 2023 (“2023 Senior Notes”) | | 1,500 |
| | 1,500 |
|
| 5.75% Senior Secured Notes due 2024 (“2024 Senior Notes”) | | 2,000 |
| | 2,000 |
|
| 5.625% Senior Secured Notes due 2025 (“2025 Senior Notes”) | | 2,000 |
| | 2,000 |
|
| 5.875% Senior Secured Notes due 2026 (“2026 Senior Notes”) | | 1,500 |
| | 1,500 |
|
| 5.00% Senior Secured Notes due 2027 (“2027 Senior Notes”) | | 1,500 |
| | 1,500 |
|
| 4.200% Senior Secured Notes due 2028 (“2028 Senior Notes”) | | 1,350 |
| | 1,350 |
|
| 5.00% Senior Secured Notes due 2037 (“2037 Senior Notes”) | | 800 |
| | 800 |
|
| Unamortized discount, premium and debt issuance costs, net | | (126 | ) | | (150 | ) |
| Total long-term debt, net | | 13,524 |
| | 13,500 |
|
| | | | | |
| Current debt | | | | |
| $1.2 billion Working Capital Facility (“Working Capital Facility”) | | — |
| | — |
|
| Total debt, net | | $ | 13,524 |
|
| $ | 13,500 |
|
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2019 (in millions):
|
| | | | |
| Years Ending December 31, | | Principal Payments |
| 2020 | | $ | — |
|
| 2021 | | 2,000 |
|
| 2022 | | 1,000 |
|
| 2023 | | 1,500 |
|
| 2024 | | 2,000 |
|
| Thereafter | | 7,150 |
|
| Total | | $ | 13,650 |
|
Senior Notes
The terms of the 2021 Senior Notes, 2022 Senior Notes, 2023 Senior Notes, 2024 Senior Notes, 2025 Senior Notes, 2026 Senior Notes, 2027 Senior Notes and 2028 Senior Notes (collectively with the 2037 Senior Notes, the “Senior Notes”) are governed by a common indenture (the “Indenture”) and the terms of the 2037 SeniorSecured Notes are governedour senior secured obligations, ranking equally in right of payment with our other existing and future senior debt and secured by a separate indenture (the “2037 Senior Notes Indenture”). Both the Indenturesame collateral and the 2037 Senior Notes Indenture contain customary terms and eventssenior in right of default and certain covenants that, among other things, limit our ability and the abilitypayment to any of our restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock orits future 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.debt. Subject to permitted liens, the Senior Secured Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in us and substantially all of our assets. We may, not makeat 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. Interest on the Senior Notes is payable semi-annually in arrears.
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 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 Secured Notes at a redemption price equal to the “make-whole” price (except for the 2037 Senior Notes, in which case the redemption price is equal to the “optional redemption” price)specified prices set forth in the respective indentures governing the Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. We may also, at any time within three monthsThe series of Senior Secured Notes due in 2037 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective maturity dates for each seriesindentures.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Below is within six monthsa schedule of the respective dates of maturity), redeem all or part of such series of the Senior Notesfuture principal payments that we are obligated to make on our outstanding debt 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.December 31, 2022 (in millions):
| | | | | | | | |
| Years Ending December 31, | | Principal Payments |
| 2023 | | $ | — | |
| 2024 | | 2,000 | |
| 2025 | | 2,051 | |
| 2026 | | 1,608 | |
| 2027 | | 1,612 | |
| Thereafter | | 4,861 | |
| Total | | $ | 12,132 | |
Working Capital Facility
Below is a summary of our Working Capital Facility as of December 31, 20192022 (in millions):
|
| | | |
| | Working Capital Facility |
| Original facility size | $ | 1,200 |
|
| Less: | |
| Outstanding balance | — |
|
| Letters of credit issued | 414 |
|
| Available commitment | $ | 786 |
|
| | |
| Interest rate on available balance | LIBOR plus 1.75% or base rate plus 0.75% |
| Weighted average interest rate of outstanding balance | n/a |
| Maturity date | December 31, 2020 |
| | | | | | | | |
| | | | Working Capital Facility (1) |
| Total facility size | | | | $ | 1,200 | |
| Less: | | | | |
| Outstanding balance | | | | — | |
| Letters of credit issued | | | | 328 | |
| Available commitment | | | | $ | 872 | |
| | | | |
| Priority ranking | | | | Senior secured |
| Interest rate on available balance (2) | | | | LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750% |
| | | | |
| Commitment fees on undrawn balance (2) | | | | 0.10% - 0.30% |
| Maturity date | | | | March 19, 2025 |
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
In September 2015, we entered into the 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 of the Liquefaction Project. The Working Capital Facility is intended to be used for loans (“Working Capital Loans”), the issuance of letters of credit, as well as for swing line loans (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. We may, from time to time, request increases in the commitments under the Working Capital Facility of up to $760 million and incremental increases in commitments of up to an additional $390 million.
Loans under the Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR loans under the Working Capital Facility is 1.75% per annum, and the applicable margin for base rate loans under the Working Capital Facility is 0.75% per annum. Interest on Swing Line Loans and loans deemed made in connection with a draw upon a letter of credit (“LC Loans”) is due and payable on the date the loan becomes due. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period, and interest on base rate loans is due and payable at the end of each fiscal quarter. However, if such base rate loan is converted into a LIBOR loan, interest is due and payable on that date. Additionally, if the loans become due prior to such periods, the interest also becomes due on that date.
We pay (1) a commitment fee equal to an annual rate of 0.70% on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding Swing Line Loans and (2) a letter of credit fee equal to an annual rate of 1.75% of the undrawn portion of all letters of credit issued under the Working Capital Facility. If draws are made upon a letter of credit issued under the Working Capital Facility and we do not elect for such draw (an “LC Draw”) to be deemed an LC Loan, we are required to pay the full amount of the LC Draw on or prior to the business day following the notice of the LC Draw. An LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of December 31, 2019, 0 LC Draws had been made upon any letters of credit issued under the Working Capital Facility.
The Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. LC Loans have a term of up to one year. Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the Working Capital Facility, (2) the date 15 days after such Swing Line Loan is made and (3) the first borrowing date 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 0 for a period of five consecutive business days at least once each year.
The Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. (1)Our obligations under the Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu basis by a first priority lien with the Senior Notes.Working Capital Facility. The Working Capital Facility contains customary conditions precedent for extensions.
(2)The margin on the interest rate and the commitment fees are subject to change based on our credit rating.
Restrictive Debt Covenants
The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit our ability to make certain investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.
As of December 31, 2019,2022, we werein compliance with all covenants related to our debt agreements.
Interest Expense
Total interest expense, net of capitalized interest consisted of the following (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | | | | | 2022 | | 2021 | | 2020 |
| Total interest cost | | | | | | $ | 706 | | | $ | 754 | | | $ | 779 | |
| Capitalized interest | | | | | | (39) | | | (132) | | | (94) | |
| Total interest expense, net of capitalized interest | | | | | | $ | 667 | | | $ | 622 | | | $ | 685 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Total interest cost | $ | 790 |
| | $ | 791 |
| | $ | 779 |
|
| Capitalized interest | (85 | ) | | (202 | ) | | (285 | ) |
| Total interest expense, net | $ | 705 |
| | $ | 589 |
| | $ | 494 |
|
We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 20192022 and 20182021 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2019 and 2018:satisfied:
(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
| |
(1) | The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price. |
| |
(2) | Includes future consideration from agreement contractually assigned to us from Cheniere Marketing. |
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
| |
(1) | We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less. |
| |
(2) | We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes substantially all variable consideration under our SPAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 52% and 57% of our LNG revenues during the years ended December 31, 2019 and 2018, respectively, were related to variable consideration received from customers. All of our LNG revenues—affiliate were related to variable consideration received from customers during each of the years ended December 31, 2019 and 2018. |
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 74% and 61% of our LNG revenues from contracts included in the table above during the years ended December 31, 2022 and 2021, respectively, were related to variable consideration received from customers. Approximately 75% and 96% of our LNG revenues—affiliate from contracts included in the table above during the years ended December 31, 2022 and 2021, respectively, were related to variable consideration received from customers.
We have enteredmay enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 12—RELATED PARTY TRANSACTIONS
Below is a summary of our related party transactions as reported on our Statements of Income for the years ended December 31, 2019, 2018 and 2017 (in millions):
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| LNG revenues—affiliate | | | | | |
| Cheniere Marketing Agreements | $ | 1,309 |
| | $ | 1,299 |
| | $ | 1,389 |
|
| Contracts for Sale and Purchase of Natural Gas and LNG | 3 |
| | — |
| | — |
|
| Total LNG revenues—affiliate | 1,312 |
| | 1,299 |
| | 1,389 |
|
| | | | | | |
| Cost of sales—affiliate | | | | | |
| Cargo loading fees under TUA | 40 |
| | 32 |
| | 23 |
|
| Contracts for Sale and Purchase of Natural Gas and LNG | 7 |
| | — |
| | — |
|
| Total cost of sales—affiliate | 47 |
| | 32 |
| | 23 |
|
| | | | | | |
| Operating and maintenance expense—affiliate | | | | | |
| TUA | 261 |
| | 256 |
| | 190 |
|
| Natural Gas Transportation Agreement | 81 |
| | 80 |
| | 73 |
|
| Services Agreements | 107 |
| | 87 |
| | 65 |
|
| LNG Site Sublease Agreement | 1 |
| | — |
| | 1 |
|
| Total operating and maintenance expense—affiliate | 450 |
|
| 423 |
| | 329 |
|
| | | | | | |
| General and administrative expense—affiliate | | | | | |
| Services Agreements | 79 |
| | 50 |
| | 58 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | 2022 | | 2021 | | 2020 |
| LNG revenues—affiliate | | | | | | | | | |
| Cheniere Marketing Agreements (1) | | | | | $ | 4,565 | | | $ | 1,453 | | | $ | 632 | |
| Contracts for Sale and Purchase of Natural Gas and LNG (2) | | | | | 3 | | | 19 | | | 30 | |
| Total LNG revenues—affiliate | | | | | 4,568 | | | 1,472 | | | 662 | |
| | | | | | | | | | |
| LNG revenues—related party | | | | | | | | | |
| Natural Gas Transportation and Storage Agreements (3) | | | | | — | | | 1 | | | — | |
| | | | | | | | | |
| Cost of sales—affiliate | | | | | | | | | |
| Cheniere Marketing Agreements (1) | | | | | — | | | 34 | | | 61 | |
| Cargo loading fees under TUA (4) | | | | | 51 | | | 43 | | | 33 | |
| Contracts for Sale and Purchase of Natural Gas and LNG (2) | | | | | 211 | | | 51 | | | 16 | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total cost of sales—affiliate | | | | | 262 | | | 128 | | | 110 | |
| | | | | | | | | |
| Cost of sales—related party | | | | | | | | | |
| Natural Gas Transportation and Storage Agreements (3) | | | | | — | | | 1 | | | — | |
| Natural Gas Supply Agreements (5) | | | | | — | | | 16 | | | — | |
| Total cost of sales—related party | | | | | — | | | 17 | | | — | |
| | | | | | | | | | |
| Operating and maintenance expense—affiliate | | | | | | | | | |
| TUA (4) | | | | | 269 | | | 266 | | | 265 | |
| Natural Gas Transportation Agreement (6) | | | | | 81 | | | 81 | | | 82 | |
| Services Agreements (7) | | | | | 131 | | | 109 | | | 118 | |
| LNG Site Sublease Agreement (8) | | | | | 1 | | | 1 | | | 1 | |
| Total operating and maintenance expense—affiliate | | | | | 482 | | | 457 | | | 466 | |
| | | | | | | | | | |
| Operating and maintenance expense—related party | | | | | | | | | |
| Natural Gas Transportation and Storage Agreements (3) | | | | | 72 | | | 46 | | | 13 | |
| | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| General and administrative expense—affiliate | | | | | | | | | |
| Services Agreements (7) | | | | | 66 | | | 61 | | | 71 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
(1)We primarily sell LNG to Cheniere Marketing under SPAs and letter agreements at a price equal to 115% of Henry Hub plus a fixed fee, except for an SPA associated with an IPM agreement for which pricing is linked to international natural gas prices, which will commence in January 2023. We also have a master SPA agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. As of December 31, 20192022 and 2018,2021, we had $104$551 million and $113$232 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing. In addition, we have 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 the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price.
(2)We have agreements described below.with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process.
LNG Terminal-Related Agreements
Terminal Use AgreementsSABINE PASS LIQUEFACTION, LLC
recorded accrued liabilities—related party of $6 million and $4 million as of December 31, 2022 and 2021, respectively, with this related party.
(4)We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”)(a portion of which is indexed for inflation), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA.
Cheniere Partners has guaranteed our obligations under our TUA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities which is capitalized as LNG terminal construction-in-process.
In connection with our TUA,Additionally, we are required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is based on our share of the commercial LNG storage capacity at the Sabine Pass LNG terminal. We are also required to reimburse SPLNG for our proportionate share of ad valorem taxes and certain other costs, which are considered variable consideration that are distinctly attributableincurred based on our contracted share of SPLNG’s regasification capacity. CQP has guaranteed our obligations under our TUA.
(5)We were a party to the specific yearsa natural gas supply agreement with a related party in the TUA.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Cheniere Marketing Agreements
Cheniere Marketing SPA
Cheniere Marketing has an SPA (“Base SPA”) with usordinary course of business, to purchase, at Cheniere Marketing’s option, any LNG produced by us in excessobtain a fixed minimum daily volume of that requiredfeed gas for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.
In May 2019, we and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6operation of the Liquefaction Project and provide that cargoes rejectedProject. This related party was partially owned by Cheniere Marketing under the Base SPA can be soldBlackstone, who also partially owns CQP’s limited partner interests. However, this entity was acquired by us to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the salenon-related party on December 31, 2021; therefore, as of such cargo.
Cheniere Marketing Master SPA(6)
We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. We executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project.
Cheniere Marketing Letter Agreements
In May 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu that were delivered between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu.
In December 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes scheduled for delivery in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.
Natural Gas Transportation Agreements
To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal,Terminal, we have a transportation precedent agreement, firm transportation service agreement and a negotiated rate agreementagreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners,CQP, and third-partythird party pipeline companies. These
(7)We do not have employees and thus we have various services agreements have a primary term that continues until 20 years from May 2016with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and thereafter continue in effect from yearmaintain the Liquefaction Project, and administrative services. Prior to year until terminated by either party upon written noticethe substantial completion of one year or the termeach Train of the Liquefaction Project, our payments under the services agreements whichever is less. Inwere primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition we have the right to elect to extend the term of the agreements for up to 2 consecutive terms of 10 years. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise.
Services Agreements
reimbursement of costs. As of December 31, 20192022 and 2018,2021, we had $133$151 million and $210$127 million of advances to affiliates, respectively, under the services agreements described below.agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.
Cheniere Investments Information Technology Services Agreement
Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Liquefaction O&M Agreement
We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on our behalf, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train.
Liquefaction MSA
We have a management services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.
LNG Site Sublease Agreement
(8)We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminalTerminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034,million, with renewal options to renew for multiple periods of 10 years with similar terms as the initial terms. The annual sublease payments will be adjustedand adjustment for inflation every five years based on a consumer price index,years. As of both December 31, 2022 and 2021, we recorded other non-current liabilities—affiliate of $15 million related to this agreement.
We had $80 million and $73 million due to affiliates as definedof December 31, 2022 and 2021, respectively, under agreements with affiliates as described above.
Disclosure of future consideration under revenue contracts with affiliates is included in the sublease agreements.Note 11—Revenues. Additionally, disclosure of future contractual obligations with affiliates and related parties is included in Note 13—Commitments and Contingencies.
Other Agreements
Cooperation Agreement
We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. In October 2022, we completed construction of the third marine berth at the Sabine Pass LNG Terminal for a total cost of $576 million and upon completion, we conveyed the property, plant and equipment associated with the third berth to SPLNG. We did not convey any assets to SPLNG under this agreement during the year ended December 31, 2021. We conveyed $351$6 million in assets to SPLNG under this agreement during the year ended December 31, 2019. We did 0t convey any assets to SPLNG under this agreement during the years ended December 31, 2018 and 2017.2020.
Contracts for Sale and Purchase of Natural Gas and LNG
We have agreements with SPLNG, CTPL and CCL that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under these agreements is recorded as LNG revenues—affiliate.
State Tax Sharing Agreement
We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. ThereTo date, there have been 0no state and local taxes paidtax payments demanded by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us.the tax sharing agreement. The agreement is effective for tax returns due on or after August 2012.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 13—COMMITMENTS AND CONTINGENCIES
Commitments
We have various contractualfuture commitments under executed contracts that include unconditional purchase obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain purchase commitments and other executed contractscommitments which do not meet the definition of a liability as of December 31, 2019,2022 and thus are not recognized as liabilities but require disclosures in our Financial Statements.
LNG Terminal Commitments and Contingencies
Obligations under EPC Contract
We have a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 6 of the Liquefaction Project. The EPC contract price for Train 6 of the Liquefaction Project is approximately $2.5 billion, reflecting amounts incurred under change orders through December 31, 2019, and including estimated costs for an optional third marine berth. As of December 31, 2019, we have incurred $1.1 billion under this contract. We have the right to terminate the EPC contract for our convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.
Obligations under SPAs
We have third-party SPAs which obligate us to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project.
Obligations under Natural Gas Supply, Transportation and Storage Service Agreements
We have physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. As of December 31, 2019, we have secured up to approximately 3,850 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the certain events or states of affairs are satisfied.15 years.
Additionally, we have natural gas transportation and storage service agreements for the Liquefaction Project. The initial term of the natural gas transportation agreements rangesrange up to 20 years, with renewal options for certain contracts, and commencescommence upon the occurrence of conditions precedent. The initial terms of our natural gas storage service agreements range up to 10 years.
As of December 31, 2019,2022, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met or are currently expected to be met were as follows (in millions)billions):
|
| | | |
| Years Ending December 31, | Payments Due (1) |
| 2020 | $ | 2,329 |
|
| 2021 | 1,416 |
|
| 2022 | 931 |
|
| 2023 | 722 |
|
| 2024 | 401 |
|
| Thereafter | 2,871 |
|
| Total | $ | 8,670 |
|
| | | | | | | | | | | | | | | | | |
| Years Ending December 31, | Payments Due to Third Parties (1) (2) | | Payments Due to Affiliates (1) | | Payments Due to Related Parties (1) |
| 2023 | $ | 6.6 | | | $ | 0.1 | | | $ | 0.1 | |
| 2024 | 4.5 | | | 0.1 | | | 0.1 | |
| 2025 | 3.6 | | | 0.1 | | | 0.1 | |
| 2026 | 2.9 | | | 0.1 | | | — | |
| 2027 | 2.5 | | | 0.1 | | | — | |
| Thereafter | 9.7 | | | 0.6 | | | — | |
| Total | $ | 29.8 | | | $ | 1.1 | | | $ | 0.3 | |
| |
(1) | Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2019.(1)Pricing of natural gas supply contracts is variable based on market commodity basis prices adjusted for basis spread, and pricing of our IPM agreement is variable based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2022. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services. (2)Includes $0.4 billion under natural gas supply agreements with unsatisfied conditions precedent.
Services Agreements |
ObligationsWe have certain fixed commitments under LNG TUAs
We have
Substantially all of our commitments to affiliates consist of a TUA with SPLNG pursuant to which we have reserved approximately 2 Bcf/d of regasification capacity. See Note 12—Related Party Transactions for additional information regarding this TUA.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Additionally, we have a partial TUA assignment agreement with TotalTotalEnergies Gas & Power North America, Inc. (“Total”TotalEnergies”), another TUA customer, whereby upon substantial completion of Train 5, we gained access to substantially all of Total’sTotalEnergies’ capacity and other services provided under Total’sTotalEnergies’ TUA with SPLNG. This agreement provides
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
us with additional berthing and storage capacity at the Sabine Pass LNG terminalTerminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity 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.
Services Agreements
capacity.
Other Commitments
State Tax Sharing Agreements
Other Agreements
In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.
Environmental and Regulatory Matters
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.
Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In the opinion of management, as of December 31, 2019,2022, there were 0no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 14—CUSTOMER CONCENTRATION
The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivabletrade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivabletrade and other receivables, net of current expected credit losses from external customers:customers and contract assets, net of current expected credit losses from external customers, respectively:
| | | | | | | | | | | | | | Percentage of Total Revenues from External Customers | | Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers |
| | Percentage of Total Revenues from External Customers | | Percentage of Accounts Receivable from External Customers | | | Year Ended December 31, | | December 31, |
| | | Year Ended December 31, | | December 31, | |
| | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 |
| Customer A | | 29% | | 30% | | 43% | | 22% | | 35% | Customer A | | | 24% | | 25% | | 25% | | 28% | | 29% |
| Customer B | | 19% | | 23% | | 30% | | 13% | | 23% | Customer B | | | 17% | | 18% | | 19% | | 18% | | 17% |
| Customer C | | 21% | | 24% | | 25% | | 22% | | 30% | Customer C | | | 17% | | 17% | | 18% | | * | | * |
| Customer D | | 21% | | 20% | | —% | | 13% | | * | Customer D | | | 16% | | 16% | | 16% | | 18% | | 14% |
| Customer E | | * | | —% | | —% | | 13% | | —% | Customer E | | | * | | 10% | | * | | * | | 13% |
| Customer F | | * | | —% | | —% | | 14% | | —% | Customer F | | | * | | * | | * | | 13% | | 12% |
The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.
The following table provides supplemental disclosure of cash flow information (in millions):
None.
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
None.
Omitted pursuant to Instruction I of Form 10-K.
Omitted pursuant to Instruction I of Form 10-K.
Omitted pursuant to Instruction I of Form 10-K.
Omitted pursuant to Instruction I of Form 10-K.
We are not a public company and we are not listed on any stock exchange. As a result, we are not required to, and do not, have an independent audit committee, a financial expert or a majority of independent directors. The audit committee of the general partner of Cheniere PartnersCQP has approved all audit and non-audit services to be provided by the independent accountants and the fees for such services during the fiscal years ended December 31, 20192022 and 2018.2021.
