•any other statements that relate to non-historical or future information.information; and
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only
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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
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PART I
General
We are a Delaware limited liability company formed by Cheniere Energy Partners, in June 2010 to own, develop and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”L.P. (“CQP”) at the Sabine Pass LNG terminal adjacent to the pre-existing regasification facilities owned and operated by SPLNG. Our vision is to. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to the world, while responsiblyconduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG in a safe and rewarding work environment. The liquefaction ofto 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 allowsis 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 be shipped economically from areascoal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.
The natural gas liquefaction and export facility at Sabine Pass, Louisiana (the “Sabine Pass LNG terminal”), one of the largest LNG production facilities in the world, where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG. We plan to construct up tohas six operational Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is undergoing commissioning andwith Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to havewhich achieved substantial completion on February 4, 2022, for a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG per Train, and run rate adjusted nominaltotal production capacity of approximately 4.5 to 4.930 mtpa of LNG per Train.(the “Liquefaction Project”). The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, adjacent to the existing regasification facilities owned and operated by Sabine Pass LNG, L.P. (“SPLNG”).
Our customer arrangements provide us with significant, stable and long-term cash flows. As further discussed below, we contract our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, We have contracted approximately 75% of the total production capacity from the Liquefaction Project through long-term SPAs, with approximately 16 years of weighted average remaining life as of December 31, 2021, which includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes. For further discussion of the contracted future cash flows under our revenue arrangements, see Item 7. Management's Discussion and SPLNGAnalysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.
We remain focused on operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG terminal, which provides opportunity for further liquefaction capacity expansion. Further development of the Sabine Pass LNG terminal will require, among other things, acceptable commercial and financing arrangements before we can make a final investment decision (“FID”).
Additionally, we are each indirect wholly owned subsidiariescommitted to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. Cheniere Investments,published its 2020 Corporate Responsibility (“CR”) report, which details our strategy and progress on ESG issues, as well as our efforts on integrating climate considerations into our business strategy and taking a leadership position on increased environmental transparency, including conducting a climate scenario analysis and our plan to provide LNG customers with Cargo Emission Tags. In August 2021, Cheniere also announced a peer-reviewed LNG life cycle assessment study which allows for improved greenhouse gas emissions assessment, which was published in the American Chemical Society Sustainable Chemistry & Engineering Journal. Cheniere’s CR report is a wholly owned subsidiary of Cheniere Partners. Cheniere Partners, a publicly traded limited partnership,available at cheniere.com/IMPACT. Information on our website, including the CR report, is a 48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses.not incorporated by reference into this Annual Report on Form 10-K.
Our Business Strategy
Our primary business strategy is to develop, construct and operate assets supported by long-term, fixed fee contracts. We plan to implement our strategy by:
•procuring natural gas to our facility;
•commencing commercial delivery for our SPA customers;
•maximizing the production of LNG to generateserve our customers and generating steady and reliablestable revenues and operating cash flows;
flows;•maintaining a prudent and cost-effective capital structure; and
•strategically identifying actionable environmental solutions.
Our Business
Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.
Liquefaction Facilities
The Liquefaction Project is one of the largest LNG production facilities in the world. We operate six Trains, including Train 6 which achieved substantial completion on February 4, 2022, and two marine berths, and are developing, constructing a third marine berth. We have a lump sum turnkey contract with Bechtel Oil, Gas and operatingChemicals, Inc. (“Bechtel”) for the EPC of Train 6. The following table summarizes the project completion and construction status of Train 6 of the Liquefaction Project at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We haveas of December 31, 2021:
| Train 6 | |||||||||||
| Overall project completion percentage | 99.5% | ||||||||||
| Completion percentage of: | |||||||||||
| Engineering | 100.0% | ||||||||||
| Procurement | 100.0% | ||||||||||
| Subcontract work | 99.6% | ||||||||||
| Construction | 98.8% | ||||||||||
| Date of substantial completion | February 4, 2022 | ||||||||||
SPLNG has received authorization from the FERC for the construction of the third marine berth.
The following summarizes the volumes of natural gas for which we have received approvals from FERC to site, construct and operate Trains 1 through 6. We have achieved substantial completion of Trains 1, 2, 3 and 4 of the Liquefaction Project and commenced operating activities in May 2016, September 2016, March 2017 and October 2017, respectively. Train 5 of the Liquefaction Project is undergoing commissioning and the following table summarizes the status as of December 31, 2018:
| FERC Approved Volume | DOE Approved Volume | ||||||||||||||||||||||
| (in Bcf/yr) | (in mtpa) | (in Bcf/yr) | (in mtpa) | ||||||||||||||||||||
| FTA countries | 1,661.94 | 33 | 1,661.94 | 33 | |||||||||||||||||||
| Non-FTA countries | 1,661.94 | 33 | 1,509.3 (1) | 30 | |||||||||||||||||||
(1)The authorization for a 30-year term, which commenced on May 15, 2016, and non-FTA countries for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803additional 152.64 Bcf/yr of natural gas).
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Natural Gas Supply, Transportation and 6—FTA countries and non-FTA countries for a 20-year term, in an amount up to a combined total of 503.3 Bcf/yr ofStorage
We have secured natural gas (approximately 10 mtpa).
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 2.0 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, we, Cheniere Investments and SPLNG also entered into a terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use our reserved capacity under the TUA and had the obligation to pay the TUA Fees required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal and its respective percentage of TUA Fees payable was reduced from 100% to zero as each of Trains 1 through 4 reached commercial operations.
Additionally, we have entered into a partial TUA assignment agreement with Total,TotalEnergies Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 3, we gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, we will gain access to substantially all of Total’s capacity. This agreement providesprovide us with additional berthing and storage capacity at the Sabine Pass LNG terminal that mayterminal. Refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for additional discussion of our TUA agreements.
Customers
Information regarding our customer contracts can be usedfound in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.
The following table shows customers with revenues of 10% or greater of total revenues from external customers:
| Percentage of Total Revenues from External Customers | ||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| BG Gulf Coast LNG, LLC | 25% | 25% | 29% | |||||||||||||||||||||||||||||
| GAIL (India) Limited | 18% | 19% | 21% | |||||||||||||||||||||||||||||
| Korea Gas Corporation | 17% | 18% | 21% | |||||||||||||||||||||||||||||
| Naturgy LNG GOM, Limited | 16% | 16% | 19% | |||||||||||||||||||||||||||||
| Total | 10% | * | * | |||||||||||||||||||||||||||||
* Less than 10%
All of the above customers contribute to 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 Trains 5 and 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, 2018 and 2017, we recorded $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. ThisThese rigorous regulatory requirement increasesrequirements 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 operationexpansion of the Liquefaction Project and the export of LNG are highly regulated activities. In orderactivities subject to site, construct and operate the Liquefaction Project, we received and are required to maintain authorizations fromjurisdiction of the FERC under Section 3 ofpursuant to the Natural Gas Act of 1938, as amended (the “NGA”), as well as several other material governmental and regulatory approvals.
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
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application (the “February 2014 Order”). A party to the proceeding requested a rehearing of the February 2014 Order, and in September 2014, the FERC issued an order denying the rehearing request (the “FERC Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the February 2014 Order and the FERC Order Denying Rehearing. The court denied the petition in June 2016. In September 2013, we filed an application with the FERC for authorization to add Trains 5 and 6 to the Liquefaction Project, which was granted by the FERC in an orderOrder issued in April 2015 and an orderOrder denying rehearing issued in June 2015. These ordersOrders are not subject to appellate court review.
In 2002,October of 2018, we applied to the FERC concluded that it would apply light-handed regulation overfor authorization to add a third marine berth to the rates, terms and conditions agreedLiquefaction Project, which FERC approved in February of 2020. FERC issued written approval to by partiescommence site preparation work for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at non-discriminatory rates or maintainthe third berth in June 2020.
On September 27, 2019, we filed a tariff or rate schedule on filerequest with the FERC pursuant to Section 3 of the NGA, requesting authorization to increase the total LNG production capacity of the terminal from currently authorized levels to an amount which reflects more accurately the capacity of the facility based on enhancements during the engineering, design and construction process, as distinguished fromwell as operational experience to date. The requested authorizations do not involve construction of new facilities. Corresponding applications for authorization to export the requirements appliedincremental volumes were also submitted to FERC-regulatedthe DOE. The DOE issued Orders granting authorization to export LNG to FTA countries in April 2020. The DOE authorization for export to non-FTA countries is still pending. In October 2021, the FERC issued its Orders Amending Authorization under Section 3 of the NGA.
On February 18, 2022, FERC updated its 1999 Policy Statement on certification of new interstate natural gas pipelines. The EPAct codifiedfacilities and the framework for FERC’s decision-making process, which would now include, among other things, reasonably foreseeable greenhouse gas emissions that may be attributable to the project and the project’s impact on environmental justice communities. These FERC changes are the first revision in more than 20 years to FERC’s policy but those provisions expiredfor 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 January 1, 2015. Nonetheless,our future projects and expansions is not known at this time, we see no indication thatdo 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, intendswhich may conduct routine or special inspections and issue data requests designed to modify its longstanding policyensure 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 light-handed regulationthe NGA and any rules, regulations or orders of LNG terminals.the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other material governmental and regulatory approvals and permits will be required throughout the life of ourthe Liquefaction Project. In addition, theour FERC orders require us to comply with certain ongoing conditions, reporting obligations and obtain certain additional FERC andmaintain other regulatory agency approvals as construction progresses. To date, we have been able to obtain these approvals as needed andthroughout the need for these approvals has not materially affected our construction progress. Throughout the life
of the Liquefaction Project,Project. For example, throughout the life of our liquefaction facility, we will beare subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities.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“Sabine Pass LNG terminal as discussed in Our Liquefaction Project. Facilities. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.
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Other Governmental Permits, Approvals and Authorizations
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 withinspeculative position limit rules which became effective on March 15, 2021 and have a phased-in compliance date that began on January 1, 2022. Given the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of standardized swaps of certain classes as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authorityrecent enactment of the CFTC andspeculative position limit rules, as well as the SEC regarding the derivatives markets. Mostimpact of the regulations are already in effect, while other rules and regulations includingunder the proposed margin rules, position limits, and commodity clearing requirements, remain to be finalized or effectuated. Therefore,Dodd-Frank Act, the impact of thosesuch rules and regulations on our business continues to be uncertain.
As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators havealso adopted rules to requirerequiring Swap Dealers and Major Swap Participants,(as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules which, as to the collection of initial margin, are being phased in, do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.
Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.
Environmental Regulation
The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations require significant expenditures for compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
Clean Air Act (“CAA”)
The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of the Liquefaction Project, will be materially and adversely affected by any such requirements.
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule for multiple sections of the economy. This rule requires mandatoryrequiring annual reporting of greenhouse gas (“GHG”) emissions from stationary sources including fuel combustion sources.in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would
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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. The Obama AdministrationWhile the EPA subsequently took severala number of additional actions intendedprimarily relating to limit GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules were largely stayed or repealed during the Trump Administration including regulatingby amendments adopted by the EPA on February 23, 2018 and additional amendments to new source performance standards for the oil and gas industry on September 14 and 15, 2020. On November 15, 2021, the EPA proposed new regulations to reduce methane emissions from both new and existing Electricity Generating Unitssources within the Crude Oil and fromNatural Gas source category. The proposed regulations if finalized, would result in more stringent requirements for new and modified oil and gas operations. The timing, extent and impactsources, expand the types of these rulesnew sources covered, and other Obama Administration initiatives remain uncertain as the Trump Administration has undertaken steps to delay their implementation, and to review, repeal and potentially replace them. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan after concluding the October 2015 final rule exceeds EPA’s statutory authority under the CAA. In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement for the Clean Power Plan, which requires states to develop plans to implement certain performance standards within three years after the Final Rule is publishedfirst time, establish emissions guidelines for existing sources in the Federal Register. ManyCrude Oil and Natural Gas source category. We are supportive of the Trump Administration’s efforts to rollback Obama Administration actions have been challenged in court.regulations reducing GHG emissions over time.
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory action to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs, the imposition of taxes or fees related to GHG emissions or additional operating restrictions and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Coastal Zone Management Act (“CZMA”)
The siting and construction of the Liquefaction Project within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.
Clean Water Act (“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)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. In the eventWhen such wastes are generated in connection with the Liquefaction Project,operations of our facilities, we will beare 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, 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.
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Market Factors and Competition
Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sell any quantitiessale of LNG available under the SPAs withby Cheniere Marketing, or developdevelopment of new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas, and economic growth in developing countries.countries and other related factors such as the effects of the COVID-19 pandemic. In addition, Cheniere’s ability to obtain additional funding to execute its business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and Cheniere’s ability to access capital markets.
We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. GlobalPlayers around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Currently, significant amounts of money are being invested across Europe and Asia in natural gas projects under construction, and more continues to be earmarked to planned projects globally. Some examples include India’s commitment to invest over $60 billion to usher a gas-based economy, around $100 billion earmarked for Europe’s gas infrastructure buildout, and China’s hundreds of billions all along the natural gas value chain. We highlight regasification capacity, which will not only expand existing import capacities in rapidly growing markets like China and India, but also add new import markets all over the globe, raising the total number of import markets to approximately 60 by 2030 from 43 in 2020 and just 15 markets as recently as 2005.
As a result of these dynamics, global demand for natural gas is projected by the International Energy Agency to grow by approximately 1920 trillion cubic feet (“Tcf”) between 20172020 and 2025, with2030 and 33 Tcf between 2020 and 2040. LNG’s share is seen growing from about 10%11% in 20172020 to about 15%12% of the global gas market in 2025.2030 and 14% in 2040. Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 60%57%, from approximately 287366.6 mtpa, or 13.817.6 Tcf, in 2017,2020, to approximately 461576.5 mtpa, or 22.127.7 Tcf, in 2025,2030 and thatto 734.5 mtpa or 35.3 Tcf in 2040. WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 413517 mtpa in 2025, resulting2030, declining to 456 mtpa in 2040. This could result in a market need for construction of an additional approximately 4860 mtpa of LNG production.production by 2030 and about 279 mtpa by 2040. As a cleaner burning fuel with far lower emissions than coal or liquid fuels in power generation, we expect gas and LNG to play a central role in balancing grids and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction ProjectProjects 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. We have contracted an aggregate amountapproximately 75% of the total production capacity from the Liquefaction Project, with approximately 16 years of weighted average remaining life as of December 31, 2021, which includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG that is between approximately 80%cargoes.
Competition
When we need to 95%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 expected aggregate adjusted nominal production capacity forworld, including our affiliate Corpus Christi Liquefaction, LLC (“CCL”), which operates three Trains 1 through 5at 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 third-party customers. As of January 31, 2019, U.S. natural gas prices indicate thatwhich 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 exported from the U.S. continues to be competitively priced, supporting the opportunity for U.S. LNG to fill uncontracted future demand through the execution of long-term, medium-term and short-term contracting of LNG from our terminal.markets than us.
Employees
We have no employees. We have contracts with subsidiaries of Cheniere and Cheniere PartnersCQP for operations, maintenance and management services. As of January 31, 2019,2022, Cheniere and its subsidiaries had 1,3721,550 full-time employees, including 483513 employees who directly supported the Liquefaction Project. See Note 12—Related Party Transactions of our Notes to Financial Statements for a discussion of the services agreements pursuant to which general and administrative services are provided to us.
Available Information
Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.
ITEM 1A. RISK FACTORS |
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements.We may encounter risks in addition to those described below.Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
•Risks Relating to the Completion of Our Liquefaction Facilities Operations and the DevelopmentIndustry; and Operation of Our Business.
Risks Relating to Our Financial Matters
Our existing level of cash resources and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
As of December 31, 2018,2021, we had zerono cash and cash equivalents, $756$98 million of current restricted cash and $13.7cash equivalents, $805 million of available commitments under the our $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”) and $13.1 billion of total debt outstanding (before unamortized premium, discount and debt issuance costs), excluding $425 million of outstanding letters of credit.. We incur, and will incur, significant interest expense relating to the assets at the Liquefaction Project, and we anticipate needing to incur additional debt to finance the construction of Train 6 of the Liquefaction Project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.
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Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations for any reason.
Our future results and liquidity are substantially dependent upon performance by our customers to make the payments under long-term contracts. As of December 31, 2018,2021, we had SPAs with seven third-partyterms of 10 or more years with a total of eight 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.
Risks Relating to the Completion of Our Liquefaction FacilitiesOperations and the Development and Operation of Our BusinessIndustry
year ended December 31, 2021, eight TBtu was loaded at affiliate facilities pursuant to this agreement. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of our other facilities and increase our insurance premiums. The U.S. Global Change Research Program has reported that the Liquefaction ProjectU.S.’s energy and related infrastructure. Changestransportation systems are expected to be increasingly disrupted by climate change and extreme weather events. An increase in the global climate may have significant physical effects, such as increased frequency and severity of extreme weather events such as storms, floods, fires and rising sea levels; if any such effects were to occur, theylevels could have an adverse effect on our coastal operations.
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. Any significant disruption to our natural gas supply could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
The construction and operation of the Liquefaction Project is, and will be, subject to the inherent risks associated with this type of operation, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions;conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand. For example, LNG procurement in Japan rose dramatically in 2011 and several years thereafter following a tsunami that caused extensive destruction to its nuclear power infrastructure;
•reduced demand and lower prices for natural gas;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities which may decrease the production of natural gas;gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
•cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•political conditions in natural gas producing regions;
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•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
•adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Project will beare dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign suppliers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or from our competitors’ liquefaction facilities in the United States.
In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.
As a result of these and other factors, LNG may not be a competitive source of energy internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or from the Liquefaction Project on a commercial basis. Any significant impediment to the ability to deliver LNG from the United States generally, or from the Liquefaction Project specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We face competition based upon the international market price for LNG.
•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;
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•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 delaysdata security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.
Outbreaks of infectious diseases, such as the outbreak of COVID-19, at our facilities could adversely affect our operations.
Our facilities at the Liquefaction Project are critical infrastructure and have continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including the Delta and Omicron variants, has had no adverse impact on our on-going operations during this time, the risk of future variants is unknown. While we believe we can continue to mitigate any significant adverse impact to our employees and operations at our critical facilities related to the virus in or cancellationits current form, the outbreak of construction of new LNG facilities, includinga more potent variant in the future at one or more of the Trains, 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 operations.
We are entirely dependent on Cheniere and CQP, including employees of Cheniere and its subsidiaries, for key personnel, and the unavailability of skilled workers or failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our key personnel could affect our business results.
As of January 31, 2022, Cheniere and its subsidiaries had 1,550 full-time employees, including 513 employees who directly supported the Liquefaction Project. We have contracted with subsidiaries of Cheniere and CQP to provide the personnel necessary for the operation, maintenance and management of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing, including theirits liquefaction project at Corpus Christi, Texas, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere face competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.
Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our ability to satisfy their obligationsengage, and Cheniere’s ability to us under our commercial agreements. Instabilityattract and retain, additional qualified personnel.
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A shortage in the financial markets as a resultlabor pool of terrorism, cyber incidentsskilled workers, remoteness of our site locations, or warother general inflationary pressures, changes in applicable laws and regulations or labor disputes could alsomake 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 abilitybusiness, 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 raise capital. The continuationcompensate and to reimburse expenses of affiliates of Cheniere. In addition, we have a TUA with SPLNG under which SPLNG derives economic benefits, we have entered into a transportation agreement with CTPL to transport natural gas to the Liquefaction Project and we have also executed agreements with Cheniere Marketing to sell: (1) at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG and (2) up to 306 cargoes to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub. All of these 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. Failure to comply with such conditions, or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns, could impede the operation and construction of our infrastructure. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources, and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the Sabine Pass LNGconstruction and operation of our terminal, including the Pipeline Hazardous Materials Safety Administration (“PHMSA”),PHMSA, to issue compliance orders, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties or to capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
In October 2015,2009, the EPA promulgated a final rule to implementand finalized the Obama Administration’s Clean Power Plan, which is designed to reduceMandatory Greenhouse Gas Reporting Rule requiring annual reporting of GHG emissions from power plantsstationary sources in a variety of industries. In 2010, the United States. In February 2016, the U.S. Supreme Court stayed the final rule, effectively suspending the duty to comply withEPA expanded the rule until certain legal challenges are resolved.to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules were largely stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and additional amendments to new source performance standards for the oil and gas industry on September 14 and 15, 2020. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan after concluding the October 2015 final rule exceeds EPA’s statutory authority under the CAA. In August 2018,November 15, 2021, the EPA proposed new regulations to reduce methane emissions from both new and existing sources within the Affordable Clean Energy rule as a replacementCrude Oil and Natural Gas source category. The proposed regulations, if finalized, would result in more stringent requirements for new sources, expand the types of new sources covered, and for the Clean Power Plan, which requires states to develop plans to implement certain performance standards within three years after the Final Rule is publishedfirst time, establish emissions guidelines for existing sources in the Federal Register. The Trump Administration announced in June 2017 that the United States would withdraw from the Paris Accord, an international agreement within the United Nations Framework Convention on Climate Change under which the Obama Administration committed the United States to reducing its economy-wide GHG emission by 26-28% below 2005 levels by 2025. OtherCrude Oil and Natural Gas source category. In addition, other federal and state initiatives may be considered in the future to address GHG emissions through, for example, United States treaty commitments, direct regulation, market-based regulations such as a carbon emissions tax or cap-and-trade programs. programs or clean energy standards.Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.We are supportive of regulations reducing GHG emissions over time.
Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Sabine Pass LNG terminal or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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.
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LDEQ Matter
Certain of Cheniere’s subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG terminal and the commissioning of the Liquefaction Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of Cheniere’s subsidiaries received a Consolidated
Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of Cheniere’s subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.
PHMSA Matter
In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to us in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal. These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, we and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to us returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to us alleging violations of federal pipeline safety regulations relating to the 2018 tank incident and proposing civil penalties totaling $2,214,900.On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200.On October 12, 2021, we responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty.PHMSA notified us in a letter dated November 9, 2021 that the case was considered “closed.” We continue to workcoordinate with PHMSA and other appropriate regulatory authoritiesFERC to address the matters identified inrelating to the Consent Order. February 2018 leak, including repair approach and related analysis.We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| Year Ended December 31, | ||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||
| Revenues (including transactions with affiliates) | $ | 6,126 | $ | 4,024 | $ | 833 | $ | — | $ | — | ||||||||||
| Income (loss) from operations | 1,520 | 781 | 50 | (92 | ) | (119 | ) | |||||||||||||
| Interest expense, net of capitalized interest | (589 | ) | (494 | ) | (186 | ) | (36 | ) | (24 | ) | ||||||||||
| Net income (loss) | 944 | 250 | (193 | ) | (266 | ) | (377 | ) | ||||||||||||
| December 31, | ||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||
| Property, plant and equipment, net | $ | 13,209 | $ | 12,920 | $ | 11,875 | $ | 9,841 | $ | 6,962 | ||||||||||
| Total assets | 14,967 | 14,206 | 12,883 | 10,433 | 7,818 | |||||||||||||||
| Current debt | — | — | 224 | 15 | — | |||||||||||||||
| Long-term debt, net | 13,500 | 13,477 | 11,649 | 9,206 | 6,390 | |||||||||||||||
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Discussion of 2019 items and variance drivers between the year ended December 31, 2020 as compared to December 31, 2019 are not included herein, and can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2020.
Our discussion and analysis includes the following subjects:
Overview of Business
We wereare a limited liability company formed by Cheniere Partners to develop, construct and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities owned and operated by SPLNG. Our vision isCQP to provide clean, secure and affordable LNG to integrated energy tocompanies, utilities and energy trading companies around the world, while responsibly deliveringworld. We operate a reliable, competitivenatural gas liquefaction and integrated sourceexport facility at Sabine Pass, Louisiana (the “Sabine Pass LNG terminal”) with six operational natural gas liquefaction Trains (the “Liquefaction Project”). For further discussion of our business, see Items 1. and 2. Business and Properties.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted approximately 75% of the total production capacity from the Liquefaction Project with approximately 16 years of weighted average remaining life as of December 31, 2021. Our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG inplus a safe and rewarding work environment. The liquefactionvariable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas intopurchases and transportation and liquefaction fuel to produce LNG, allows itthus limiting our exposure to be shipped economically from areas of the world wherefluctuations in U.S. natural gas is abundant and inexpensive to produce to other areas whereprices. We believe that continued global demand for natural gas demand and infrastructure exist to economically justifyLNG, as further described in Items 1. and 2. Business and Properties—Market Factors and Competition, will provide a foundation for additional growth in our business in the use of LNG. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is undergoing commissioning and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG per Train, and run rate adjusted nominal production capacity of approximately 4.5 to 4.9 mtpa of LNG per Train.future.
Overview of Significant Events
Our significant accomplishmentsevents since January 1, 20182021 and through the filing date of this Form 10-K include the following:
Strategic
•In December 2018, weFebruary 2022, Cheniere Marketing entered into agreements to novate to us SPAs entered into with ENN LNG (Singapore) Pte Ltd. and a 20-year SPAsubsidiary of Glencore plc, aggregating approximately 21 million tonnes of LNG to be delivered between 2023 and 2035, in connection with PETRONAS LNG Ltd., subjecta prior commitment by Cheniere to conditions precedent including making a final investment decision (“FID”)collateralize financing for Train 6 of the Liquefaction Project, for the sale of approximately 1.1 mtpa of LNG on a free on board basis, with deliveries commencing following date of first commercial delivery for Train 6 of Liquefaction Project.
Operational
•As of February 20, 2019,18, 2022, over 5701,550 cumulative LNG cargoes totaling approximately 110 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project, with more than 270 cargoes in 2018 alone, with deliveries to 31 countries and regions worldwide.Project.
| December 31, | |||||||
| 2018 | 2017 | ||||||
| Cash and cash equivalents | $ | — | $ | — | |||
| Restricted cash designated for the Liquefaction Project | 756 | 544 | |||||
| Available commitments under the $1.2 billion Working Capital Facility (“Working Capital Facility”) | 775 | 470 | |||||
Financial
•In October 2021, we redeemed $318 million of our $1.1 billion outstanding 6.25% Senior Secured Notes due 2022 (the “2022 Senior Notes”) using $318 million of capital contributions from CQP.
•In December 2021, we issued Senior Secured Notes due 2037 on a private placement basis for an aggregate principal amount of approximately $482 million (the “2037 Private Placement Senior Secured Notes”). The 2037 Private Placement Senior Secured Notes are fully amortizing, with a weighted average life of over 10 years and commenced operating activities in May 2016, September 2016, March 2017 and October 2017, respectively. Train 5a weighted average interest rate of 3.07%. The proceeds of the 2037 Private Placement Senior Secured Notes, net of related fees, costs and expenses, along with cash on hand were used to redeem the remaining portion of the 2022 Senior Notes.
•In February 2021, Fitch Ratings (“Fitch”) changed the outlook of our senior secured notes rating to positive from stable.
Market Environment
The LNG market in 2021 saw unprecedented price increases across all natural gas and LNG benchmarks. Colder than normal temperatures early in the year, concerns over low natural gas and LNG inventories, low additional LNG supply availability and forecasts of a cold 2021/2022 winter in Europe and Asia increased price volatility and supported a run-up in natural gas and LNG prices. These conditions were exacerbated by rising coal and carbon prices in Europe, persistent under-performance from some non-US LNG supply projects and reduced Russian pipe exports to Europe, precipitating the early stages of a price-based energy crisis in Europe.
High demand for LNG during the recovery from the initial stages of the COVID-19 pandemic resulted in intense competition for supplies between the Atlantic and Pacific basins. Global LNG demand grew by about approximately 5% from the comparable 2020 period, adding an additional 18 mtpa to the overall market. A robust economic recovery in China powered an 8% increase in Asia’s LNG demand of approximately 19.5 million tonnes from the comparable 2020 period. This led to competition for supplies between Asia, Europe and Latin America, exposing the supply constraints that the industry has had while emerging from the pandemic. In turn, this drove international natural gas and LNG prices higher and widened the price spreads between the U.S. and other parts of the world. As an example, the Dutch Title Transfer Facility (“TTF”) monthly settlement prices averaged $14.4/MMBtu in 2021, approximately 375% higher than the $3.0/MMBtu average in 2020, and the TTF monthly settlement prices averaged $28.9/MMBtu in the fourth quarter of 2021, approximately 512% higher than the $4.72/MMBtu average in the fourth quarter of 2020. Similarly, the 2021 average settlement price for the Japan Korea Marker (“JKM”) increased 292% year-over-year to an average of $15.0/MMBtu in 2021, and the fourth quarter of 2021 average settlement price for the JKM increased over 412% year-over-year to an average of $27.9/MMBtu. This extreme price increase triggered a strong supply response from the U.S., which played a significant role in balancing the global LNG market. The U.S. exported 70 million tonnes of LNG, a gain of approximately 49% from the comparable 2020 period, as the market continued to pull on supplies from our facilities and those of our competitors. Exports from our Liquefaction Project is undergoingreached 25 million tonnes, representing over 35% of the gain in the U.S. total over the same period.
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Results of Operations
The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Project (including both operational and commissioning andvolumes) during the following table summarizes the status as ofyears ended December 31, 2018:2021 and 2020:
| (1) | ||||||||||||||||||||
Our net income was $1.5 billion for the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:
We have enteredenter into lump sum turnkey contracts with Bechtelderivative instruments to manage our exposure to commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Financial Statements. In some cases, the underlying transactions being economically hedged are accounted for under the engineering, procurementaccrual method of accounting, whereby revenues and construction of Trains 1 through 5expenses are recognized only upon delivery, receipt or realization of the Liquefaction Project, under which Bechtel charges a lump sumunderlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for all work performedcertain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and generally bears project costother relevant factors, notwithstanding the operational intent to mitigate risk unless certain specified events occur, in which case Bechtel may cause us to enter into a change order, or we agree with Bechtel to a change order.exposure over time.
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| Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions, except volumes) | 2021 | 2020 | Variance ($) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| LNG revenues | $ | 7,639 | $ | 5,195 | $ | 2,444 | |||||||||||||||||||||||||||||||||||||||||||||||
| LNG revenues—affiliate | 1,472 | 662 | 810 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| LNG revenues—related party | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 9,112 | $ | 5,857 | $ | 3,255 | |||||||||||||||||||||||||||||||||||||||||||||||
| LNG volumes recognized as revenues (in TBtu) (1) | 1,288 | 991 | 297 | ||||||||||||||||||||||||||||||||||||||||||||||||||
(1)Excludes volume associated with cargoes for the commencement of certain engineering, procurement and site works for Train 6 of the Liquefaction Project and a schedule for completion has been established. FID and full notice to proceed for Train 6 of the Liquefaction Project will be contingent upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct Train 6.
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| Senior notes (1) | $ | 13,650 | $ | 13,650 | ||||
| Working Capital Facility outstanding balance | — | — | ||||||
| Letters of credit issued under Working Capital Facility | 425 | 730 | ||||||
| Available commitments under Working Capital Facility | 775 | 470 | ||||||
| Total capital resources from borrowings and available commitments | $ | 14,850 | $ | 14,850 | ||||
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
| Operating cash flows | $ | 1,423 | $ | 657 | $ | (130 | ) | |||||
| Investing cash flows | (771 | ) | (1,279 | ) | (2,338 | ) | ||||||
| Financing cash flows | (440 | ) | 808 | 2,637 | ||||||||
| Net increase in cash, cash equivalents and restricted cash | 212 | 186 | 169 | |||||||||
| Cash, cash equivalents and restricted cash—beginning of period | 544 | 358 | 189 | |||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 756 | $ | 544 | $ | 358 | ||||||
| Payments Due By Period (1) | ||||||||||||||||||||
| Total | 2019 | 2020 - 2021 | 2022 - 2023 | Thereafter | ||||||||||||||||
| Debt (2) | $ | 13,650 | $ | — | $ | 2,000 | $ | 2,500 | $ | 9,150 | ||||||||||
| Interest payments (2) | 4,480 | 760 | 1,404 | 1,097 | 1,219 | |||||||||||||||
| Construction obligations (3) | 87 | 87 | — | — | — | |||||||||||||||
| Purchase obligations (4) | 7,931 | 2,495 | 2,388 | 1,396 | 1,652 | |||||||||||||||
| Operating lease obligations | 9 | — | 1 | 1 | 7 | |||||||||||||||
| Obligations to affiliates (5) | 6,546 | 372 | 743 | 743 | 4,688 | |||||||||||||||
| Other obligations (6) | 6 | 3 | 3 | — | — | |||||||||||||||
| Total | $ | 32,709 | $ | 3,717 | $ | 6,539 | $ | 5,737 | $ | 16,716 | ||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| (in millions, except volumes) | 2018 | 2017 | Change | 2016 | Change | |||||||||||||||
| LNG revenues | $ | 4,827 | $ | 2,635 | $ | 2,192 | $ | 539 | $ | 2,096 | ||||||||||
| LNG revenues—affiliate | 1,299 | 1,389 | (90 | ) | 294 | 1,095 | ||||||||||||||
| Total revenues | $ | 6,126 | $ | 4,024 | $ | 2,102 | $ | 833 | $ | 3,191 | ||||||||||
| LNG volumes recognized as revenues (in TBtu) | 955 | 684 | 271 | 151 | 533 | |||||||||||||||
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 yearsyear ended December 31, 2018, 2017 and 2016,2021, we realized offsets to LNG terminal costs of $94$105 million, corresponding to 1312 TBtu of LNG, $301 million corresponding to 51 TBtu of LNG and $201 million corresponding to 45 TBtu of LNG, respectively, that were related to the sale of commissioning cargoes.cargoes from the Liquefaction Project. We did not realize any offsets to LNG terminal costs during the year ended December 31, 2020.
Also included in LNG revenues are sales of certain unutilized natural gas procured for the liquefaction process and gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized revenues of $173 million and $255 million during the years ended December 31, 2021 and 2020, respectively, related to these transactions.
Operating costs and expenses
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | 2021 | 2020 | Variance ($) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cost of sales | $ | 5,289 | $ | 2,504 | $ | 2,785 | |||||||||||||||||||||||||||||||||||||||||||||||
| Cost of sales—affiliate | 128 | 110 | 18 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cost of sales—related party | 17 | — | 17 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating and maintenance expense | 548 | 547 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | 457 | 466 | (9) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating and maintenance expense—related party | 46 | 13 | 33 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| General and administrative expense | 4 | 9 | (5) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| General and administrative expense—affiliate | 61 | 71 | (10) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization expense | 468 | 465 | 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment expense and loss on disposal of assets | 6 | 1 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Total operating costs and expenses | $ | 7,024 | $ | 4,186 | $ | 2,838 | |||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| (in millions) | 2018 | 2017 | Change | 2016 | Change | |||||||||||||||
| Cost of sales | $ | 3,403 | $ | 2,317 | $ | 1,086 | $ | 416 | $ | 1,901 | ||||||||||
| Cost of sales—affiliate | 32 | 23 | 9 | 7 | 16 | |||||||||||||||
| Operating and maintenance expense | 342 | 243 | 99 | 72 | 171 | |||||||||||||||
| Operating and maintenance expense—affiliate | 423 | 329 | 94 | 129 | 200 | |||||||||||||||
| Development expense | 2 | 2 | — | — | 2 | |||||||||||||||
| Development expense—affiliate | — | — | — | 1 | (1 | ) | ||||||||||||||
| General and administrative expense | 5 | 7 | (2 | ) | 7 | — | ||||||||||||||
| General and administrative expense—affiliate | 50 | 58 | (8 | ) | 68 | (10 | ) | |||||||||||||
| Depreciation and amortization expense | 349 | 264 | 85 | 83 | 181 | |||||||||||||||
| Total operating costs and expenses | $ | 4,606 | $ | 3,243 | $ | 1,363 | $ | 783 | $ | 2,460 | ||||||||||
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increases were partially offset by a decrease in net costs associated with economic hedgesthe sale of certain unutilized natural gas procured for the liquefaction process and the increased fair value of commodity derivatives to secure natural gas feedstock for the Liquefaction Project due to favorable shifts in long-term forward prices relative to our hedged position. Cost of sales also includes variable transportation and storage costs and other costs to convert natural gas into LNG.
Other expense (income)
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | 2021 | 2020 | Variance ($) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | $ | 622 | $ | 685 | $ | (63) | |||||||||||||||||||||||||||||||||||||||||||||||
| Loss on modification or extinguishment of debt | 5 | 43 | (38) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Total other expense | $ | 627 | $ | 728 | $ | (101) | |||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| (in millions) | 2018 | 2017 | Change | 2016 | Change | |||||||||||||||
| Interest expense, net of capitalized interest | $ | 589 | $ | 494 | $ | 95 | $ | 186 | $ | 308 | ||||||||||
| Loss on modification or extinguishment of debt | — | 42 | (42 | ) | 52 | (10 | ) | |||||||||||||
| Derivative loss, net | — | 2 | (2 | ) | 6 | (4 | ) | |||||||||||||
| Other income | (13 | ) | (7 | ) | (6 | ) | (1 | ) | (6 | ) | ||||||||||
| Total other expense | $ | 576 | $ | 531 | $ | 45 | $ | 243 | $ | 288 | ||||||||||
Interest expense, net of capitalized interest, increaseddecreased during the year ended December 31, 2018 compared to2021 from the year ended December 31, 2017comparable period in 2020 primarily as a result of a decreasean increase in the portion of total interest costs that could be capitalized as additional Trainsis eligible for capitalization due to the continued construction of the remaining assets of the Liquefaction Project, completed construction betweenand to a lesser extent due to the periods. Forreduction of outstanding debt during the year. During the years ended December 31, 20182021 and 2017,2020, we incurred $791$754 million and $779 million of total interest cost, respectively, of which we capitalized $202$132 million and $285$94 million, respectively, which was primarily related to the construction of the Liquefaction Project.respectively.
Loss on modification or extinguishment of debt decreased during the year ended December 31, 2018, as compared to2021 from the year ended December 31, 2017. Losscomparable period in 2020. The loss on modification or extinguishment of debt recognized in each of the years included the incurrence of fees paid to lenders, third party fees and write off of unamortized debt issuance costs recognized upon the early redemption of our senior notes, as further discussed in Liquidity and Capital Resources—Sources and Uses of Cash—Financing Cash Flows.
Liquidity and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity as of December 31, 2021 (in millions). Future material sources of liquidity are discussed below.
| December 31, 2021 | |||||||||||
| Restricted cash and cash equivalents designated for the Liquefaction Project | $ | 98 | |||||||||
| Available commitments under our $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”) (1) | 805 | ||||||||||
| Total available liquidity | $ | 903 | |||||||||
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under the 2020 Working Capital Facility as of December 31, 2021. See Note 10—Debt of our Notes to Financial Statements for additional information on the 2020 Working Capital Facility and other debt instruments.
Our liquidity position subsequent to December 31, 2021 is driven by future sources of liquidity and future cash requirements. Future sources of liquidity are expected to be composed of (1) cash receipts from executed contracts, under which we are contractually entitled to future revenues, and (2) additional sources of liquidity, from which we expect to receive cash although the cash is not underpinned by executed contracts. Future cash requirements are expected to be composed of (1) cash payments under executed contracts, under which we are contractually obligated to make payments, and (2) additional cash requirements, under which we expect to make payments although we are not contractually obligated to make the payments under executed contracts. Future sources of liquidity and future cash requirements are estimates based on management’s assumptions and currently known market conditions and other factors as of December 31, 2021.
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Future Sources and Uses of Liquidity
Future Sources of Liquidity under Executed Contracts
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs which has not yet been recognized as revenue. This future consideration is in most cases not yet legally due to us and was not reflected on our Balance Sheets as of December 31, 2021. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed contracts as of December 31, 2021 (in billions):
| Estimated Revenues Under Executed Contracts by Period (1) | ||||||||||||||||||||||||||
| 2022 | 2023 - 2026 | Thereafter | Total | |||||||||||||||||||||||
| LNG revenues (fixed fees) (2) | $ | 3.4 | $ | 13.8 | $ | 34.2 | $ | 51.4 | ||||||||||||||||||
| LNG revenues (variable fees) (2) (3) | 5.4 | 19.1 | 50.5 | 75.0 | ||||||||||||||||||||||
| Total | $ | 8.8 | $ | 32.9 | $ | 84.7 | $ | 126.4 | ||||||||||||||||||
(1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2021. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)LNG revenues (including $2.1 billion and $4.0 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2021. The pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt.
LNG Revenues
We have contracted approximately 75% of the total production capacity from the Liquefaction Project through long-term SPAs, with approximately 16 years of weighted average remaining life as of December 31, 2021. The majority of this contracted capacity is comprised of fixed-price, long-term SPAs that we have executed with third parties to sell LNG from Trains 1 through 6 of the Liquefaction Project. Under the SPAs, the customers purchase LNG on a free on board (“FOB”) basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. The variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases and variable transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion for Trains 1 through 5 of the Liquefaction Project.After giving effect to an SPA that Cheniere has committed to provide to us and upon the date of first commercial delivery of Train 6, the annual fixed fee portion to be paid by the third-party SPA customers is expected to increase to at least $3.3 billion. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A, A2 and A by S&P Global Ratings, Moody’s Corporation and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 11—Revenues from Contracts with Customers of our Notes to Financial Statements.
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In addition to the third party SPAs discussed above, we have also executed agreements with Cheniere Marketing to sell: (1) at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG and (2) up to 306 cargoes to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub (included in the table above).
In August 2020, we entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event certain conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2021, we had $805 million in available commitments under the 2020 Working Capital Facility, subject to compliance with the applicable covenants, to potentially meet liquidity needs. The 2020 Working Capital Facility matures in 2025.
Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts
We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures under executed contracts as of December 31, 2021 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | ||||||||||||||||||||||||||
| 2022 | 2023 - 2026 | Thereafter | Total | |||||||||||||||||||||||
| Purchase obligations (2): | ||||||||||||||||||||||||||
| Natural gas supply agreements (3) | $ | 5.0 | $ | 7.9 | $ | 3.2 | $ | 16.1 | ||||||||||||||||||
| Natural gas transportation and storage service agreements (4) | 0.3 | 1.2 | 2.5 | 4.0 | ||||||||||||||||||||||
| Capital expenditures (5) | 0.2 | — | — | 0.2 | ||||||||||||||||||||||
| Other purchase obligations (6) | 0.5 | 1.8 | 3.5 | 5.8 | ||||||||||||||||||||||
| Total | $ | 6.0 | $ | 10.9 | $ | 9.2 | $ | 26.1 | ||||||||||||||||||
(1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2021. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly. We include contracts for which we have an early termination option if the option is not currently expected to be exercised.
(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2021.
(4)Includes $1.2 billion of purchase obligations to affiliates and $0.3 billion of purchase obligations to related parties under transportation and storage services agreements.
(5)Capital expenditures primarily consist of costs incurred through our EPC contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction.
(6)Other purchase obligations include $3.8 billion of purchase obligations to affiliates under the TUA and $0.8 billion of purchase obligations to affiliates under services agreements, as well as payments under our partial TUA assignment agreement with TotalEnergies Gas & Power North America, Inc. (“Total”), as discussed in Note 11—Revenues from Contracts with Customers of our Notes to Financial Statements.
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Natural Gas Supply, Transportation and Storage Service Agreements
We have secured natural gas feedstock for the Sabine Pass LNG terminal through long-term natural gas supply agreements. As of December 31, 2021, we have secured 86% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2022. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2022. Natural gas supply is generally secured on an indexed pricing basis, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied conditions precedent as of December 31, 2021, we have secured up to 5,102 TBtu of natural gas feedstock through agreements with remaining terms that range up to 10 years. A discussion of our natural gas supply agreements can be found in Note 7—Derivative Instruments of our Notes to Financial Statements.
To ensure that we are able to transport natural gas feedstock to the Sabine Pass LNG terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from CTPL, a wholly owned subsidiary of CQP, and third party pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project.
Capital Expenditures
We enter into lump sum turnkey contracts with third party contractors for the engineering, procurement and construction (“EPC”) of our Liquefaction Project. The historical contracts have been executed with Bechtel, who has charged a lump sum for all work performed and generally bore project cost, schedule and performance risks unless certain specified events occurred, in which case Bechtel caused us to enter into a change order, or we agreed with Bechtel to a change order. The future capital expenditures included in the table above primarily consist of costs incurred under the Bechtel EPC contract for Train 6 of the of the Liquefaction Project. The total contract price of the EPC contract for Train 6, which achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction is approximately $2.5 billion.
Terminal Use Agreements
We have entered into a TUA with SPLNG to provide berthing for LNG vessels and for unloading, loading, storage and regasification of LNG. Full discussion of our TUA agreement can be found in Note 12—Related Party Transactions of our Notes to Financial Statements.
Additionally, we have entered into a partial TUA assignment agreement with Total, another TUA customer, whereby upon substantial completion of Train 5 of the Liquefaction Project, we gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity. Full discussion of our partial TUA assignment with Total can be found in Note 11—Revenues from Contracts with Customers of our Notes to Financial Statements.
Additional Future Cash Requirements for Operations and Capital Expenditures
Corporate Activities
We have contracts with subsidiaries of Cheniere and CQP for operations, maintenance and management services. Cheniere and its subsidiaries’ full-time employee headcount was 1,550, including 513 employees who directly supported the Liquefaction Project operations, as of January 31, 2022. Full discussion of our operations, maintenance and management agreements can be found in Note 12—Related Party Transactions of our Notes to Financial Statements.
Financially Disciplined Growth
Our significant land position at the Sabine Pass LNG terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. We expect that any potential future expansion at the Sabine Pass LNG terminal would increase
26
cash requirements to support expanded operations, although expansion could be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2021 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | ||||||||||||||||||||||||||
| 2022 | 2023 - 2026 | Thereafter | Total | |||||||||||||||||||||||
| Debt (2) | $ | — | $ | 7.1 | $ | 6.0 | $ | 13.1 | ||||||||||||||||||
| Interest payments (2) | 0.7 | 1.9 | 0.7 | 3.3 | ||||||||||||||||||||||
| Total | $ | 0.7 | $ | 9.0 | $ | 6.7 | $ | 16.4 | ||||||||||||||||||
(1)The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2021. Debt and interest payments do not contemplate repurchases, repayments and retirements that we expect to make prior to contractual maturity. See further discussion in Note 10—Debt of our Notes to Financial Statements.
Debt
As of December 31, 2021, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $13.1 billionand the 2020 Working Capital Facility with an outstanding balance of zero. As of December 31, 2021, we were in compliance with all covenants related to our debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Financial Statements.
Interest
As of December 31, 2021, our senior notes had a weighted average interest rate of 5.15%. Borrowings under the 2020 Working Capital Facility are indexed to LIBOR, which is expected to be phased out by 2023. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue working with our lenders and counterparties to pursue amendments to our debt agreements that are currently indexed to LIBOR. Undrawn commitments under the 2020 Working Capital Facility are subject to commitment fees of 0.20%. Issued letters of credit under the 2020 Working Capital Facility are subject to letter of credit fees of 1.50%. There were $395 million issued letters of credit under the 2020 Working Capital Facility as of December 31, 2021.
Sources and Uses of Cash
The following table summarizes the sources and uses of our restricted cash and cash equivalents for the years ended December 31, 2021 and 2020 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||
| Net cash provided by operating activities | $ | 1,937 | $ | 1,424 | ||||||||||||||||
| Net cash used in investing activities | (612) | (916) | ||||||||||||||||||
| Net cash used in financing activities | (1,324) | (592) | ||||||||||||||||||
| Net increase (decrease) in restricted cash and cash equivalents | $ | 1 | $ | (84) | ||||||||||||||||
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Operating Cash Flows
Our operating cash net inflows during the years ended December 31, 2021 and 2020 were $1,937 million and $1,424 million, respectively. The $513 million increase in operating cash inflows in 2021 compared to 2020 was primarily related to cash provided by working capital primarily from payment timing differences and timing of cash receipts from the sale of LNG cargoes.
Investing Cash Flows
Cash outflows for property, plant and equipment were primarily for the construction costs for Train 6 of the Liquefaction Project, which was nearing completion in the fourth quarter of 2021. These costs are capitalized as construction-in-process until achievement of substantial completion.
Financing Cash Flows
During the year ended December 31, 2017 was attributable to the $422021, we issued approximately $482 million write-off of debt issuance costs in March 2017 upon termination of the remaining available balance of $1.6 billion under the Credit Facilities in connection with the issuance2037 Private Placement Senior Secured Notes. The proceeds of the 20282037 Private Placement Senior Secured Notes, along with capital contributions and cash on hand were used to redeem all of the 2037outstanding 2022 Senior Notes.
Debt Issuances and Related Financing Costs
The following table shows the issuances of debt during the years ended December 31, 2016 primarily as a result2021 and 2020, including intra-quarter borrowings (in millions):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||
| 2030 Senior Notes | $ | — | $ | 1,995 | ||||||||||||||||
| 2037 SPL Private Placement Senior Secured Notes | 482 | — | ||||||||||||||||||
| Total issuances | $ | 482 | $ | 1,995 | ||||||||||||||||
We incurred $5 million and $35 million of a decrease in the portion of total interest costs that could be capitalized as Trains 1 through 4 of the Liquefaction Project completed construction and an increase in our indebtedness outstanding (before unamortized premium, discount and debt issuance costs), from $12.0 billion as of December 31, 2016 to $13.7 billion as of December 31, 2017. Forand other financing costs during the yearyears ended December 31, 2016, we incurred $649 million of total interest cost, of which we capitalized $463 million, which was primarily2021 and 2020, respectively, related to the construction ofdebt transactions described above.
Debt Redemptions and Repayments and Related Extinguishment Costs
The following table shows the Liquefaction Project.
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||
| 2021 Senior Notes | $ | — | $ | (2,000) | ||||||||||||||||
| 2022 Senior Notes | (1,000) | — | ||||||||||||||||||
| Total redemption and repayments | $ | (1,000) | $ | (2,000) | ||||||||||||||||
We incurred $3 million and $39 million of debt extinguishment costs during the yearyears ended December 31, 2016. Loss on modification or extinguishment of2021 and 2020, respectively, related to the debt recognized duringtransactions described above.
Capital Contributions and Distributions
During the yearyears ended December 31, 2016 was due2021 and 2020, we received $821 million and $488 million, respectively of capital contributions from CQP and we made distributions of $1,619 million and $1,001 million, respectively, to the $26 million write-off of debt issuance costs related to the prepayment of approximately $1.3 billion of outstanding borrowings under the Credit Facilities in June 2016 in connection with the issuance of the 2026 Senior Notes, in addition to the $26 million write-off of debt issuance costs related to the prepayment of outstanding borrowings and termination of commitments under the Credit Facilities of approximately $1.4 billion in September 2016 in connection with the issuance of the 2027 Senior Notes.CQP.
28
Summary of Critical Accounting Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments and properties, plant and equipment.instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.
Fair Value of Derivative Instruments
All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes in the fair value of our derivative positions through earnings based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the
quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market.market as discussed below.
Our derivative instruments consist of financial commodity derivative contracts transacted in an over-the-counter market and index-based physical commodity contracts. Valuation of our financial commodity derivative contracts is determined using observable commodity price curves and other relevant data.
Valuation of our index-based physical commodity derivative contracts, consisting primarily of natural gas supply contracts for the operation of our liquified natural gas facilities is often developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and volatility.
Provided below is the change in unrealized valuation gain (loss) of instruments valued through the use of internal models which incorporate significant unobservable inputs, inclusive of certain LNG term deals, for the years ended December 31, 2021 and 2020 (in millions). The changes shown are impacted by inputs that may be unobservable inlimited to instruments held at the marketplace, market transactions and other relevant data.end of each respective period.
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||||||||||
| Change in unrealized gain (loss) relating to instruments still held at end of period | $ | 74 | $ | (43) | ||||||||||||||||||||||||||||
The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as interest rates andit relates to commodity prices change.given the level of volatility in the current year. See Item 7A. Quantitative and Qualitative DisclosuresAbout Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.
Recent Accounting Standards
For descriptionsa summary of recently issued accounting standards, see Note 17—Recent2—Summary of Significant Accounting StandardsPolicies of our Notes to Financial Statements.
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):
| December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||
| Fair Value | Change in Fair Value | Fair Value | Change in Fair Value | ||||||||||||||||||||
| Liquefaction Supply Derivatives | $ | 27 | $ | 1 | $ | (21) | $ | 4 | |||||||||||||||
| December 31, 2018 | December 31, 2017 | ||||||||||||||
| Fair Value | Change in Fair Value | Fair Value | Change in Fair Value | ||||||||||||
| Liquefaction Supply Derivatives | $ | (43 | ) | $ | 7 | $ | 55 | $ | 5 | ||||||
See Note 7—7—Derivative Instruments of our Notes to Financial Statements for additional details about our derivative instruments.
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
SABINE PASS LIQUEFACTION, LLC
31
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, 2018,2021, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.
This annual report does not include an attestation report of Sabine Pass Liquefaction’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Sabine Pass Liquefaction’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Management’s Certifications
The certifications of Sabine Pass Liquefaction’s Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Sabine Pass Liquefaction’s Form 10-K.
| By: | /s/ Jack A. Fusco | By: | /s/ | |||||||||||
| Jack A. Fusco | ||||||||||||||
| Chief Executive Officer (Principal Executive Officer) | Manager and Chief Financial Officer (Principal Financial Officer) | |||||||||||||
32
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, 20182021 and 2017,2020, the related statements of operations,income, member’s equity, (deficit), and cash flows for each of the years in the three-year period ended December 31, 2018,2021, and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018,2021, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company���sCompany’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Fair value of the level 3 physical liquefaction supply derivatives
As discussed in Notes 2 and 7 to the financial statements, the Company recorded fair value of level 3 physical liquefaction supply derivatives of $38 million, as of December 31, 2021. The physical liquefaction supply derivatives consist of natural gas supply contracts for the operation of the liquefied natural gas facility. The fair value of the level 3 physical liquefaction supply derivatives is developed using internal models that incorporate significant unobservable inputs.
We identified the evaluation of the fair value of the level 3 physical liquefaction supply derivatives as a critical audit matter. Specifically, there is subjectivity in certain assumptions used to estimate the fair value, including assumptions for future prices of energy units for unobservable periods and liquidity.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of the level 3 physical liquefaction supply derivatives. This included controls related to the assumptions for significant unobservable inputs. For a sample of level 3 liquefaction supply derivatives, we involved valuation professionals with specialized skills and knowledge who assisted in:
33
•evaluating the future prices of energy units for observable periods by comparing to market data, including quoted or published forward prices
•developing independent fair value estimates and comparing the independently developed estimates to the Company’s fair value estimates.
In addition, we evaluated the Company’s assumptions for future prices of energy units for unobservable periods and liquidity by comparing them to market or third-party data, including adjustments for third party quoted transportation prices.
| /s/ KPMG LLP | ||
| KPMG LLP | ||
We have served as the Company’s auditor since 2014.
Houston, Texas
February 25, 201923, 2022
34
SABINE PASS LIQUEFACTION, LLC
(in millions)
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | — | $ | — | ||||
| Restricted cash | 756 | 544 | ||||||
| Accounts and other receivables | 346 | 189 | ||||||
| Accounts receivable—affiliate | 113 | 163 | ||||||
| Advances to affiliate | 210 | 26 | ||||||
| Inventory | 87 | 85 | ||||||
| Other current assets | 24 | 54 | ||||||
| Other current assets—affiliate | 21 | 21 | ||||||
| Total current assets | 1,557 | 1,082 | ||||||
| Property, plant and equipment, net | 13,209 | 12,920 | ||||||
| Debt issuance costs, net | 12 | 18 | ||||||
| Non-current derivative assets | 31 | 17 | ||||||
| Other non-current assets, net | 158 | 169 | ||||||
| Total assets | $ | 14,967 | $ | 14,206 | ||||
| LIABILITIES AND MEMBER’S EQUITY | ||||||||
| Current liabilities | ||||||||
| Accounts payable | $ | 11 | $ | 8 | ||||
| Accrued liabilities | 768 | 606 | ||||||
| Due to affiliates | 48 | 66 | ||||||
| Deferred revenue | 91 | 84 | ||||||
| Derivative liabilities | 66 | — | ||||||
| Total current liabilities | 984 | 764 | ||||||
| Long-term debt, net | 13,500 | 13,477 | ||||||
| Non-current derivative liabilities | 14 | 3 | ||||||
| Other non-current liabilities | 3 | — | ||||||
| Commitments and contingencies (see Note 14) | ||||||||
| Member’s equity (deficit) | 466 | (38 | ) | |||||
| Total liabilities and member’s equity (deficit) | $ | 14,967 | $ | 14,206 | ||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| Revenues | ||||||||||||||||||||||||||||||||
| LNG revenues | $ | 7,639 | $ | 5,195 | $ | 5,211 | ||||||||||||||||||||||||||
| LNG revenues—affiliate | 1,472 | 662 | 1,312 | |||||||||||||||||||||||||||||
| LNG revenues—related party | 1 | — | — | |||||||||||||||||||||||||||||
| Total revenues | 9,112 | 5,857 | 6,523 | |||||||||||||||||||||||||||||
| Operating costs and expenses | ||||||||||||||||||||||||||||||||
| Cost of sales (excluding items shown separately below) | 5,289 | 2,504 | 3,373 | |||||||||||||||||||||||||||||
| Cost of sales—affiliate | 128 | 110 | 47 | |||||||||||||||||||||||||||||
| Cost of sales—related party | 17 | — | — | |||||||||||||||||||||||||||||
| Operating and maintenance expense | 548 | 547 | 547 | |||||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | 457 | 466 | 450 | |||||||||||||||||||||||||||||
| Operating and maintenance expense—related party | 46 | 13 | — | |||||||||||||||||||||||||||||
| General and administrative expense | 4 | 9 | 6 | |||||||||||||||||||||||||||||
| General and administrative expense—affiliate | 61 | 71 | 79 | |||||||||||||||||||||||||||||
| Depreciation and amortization expense | 468 | 465 | 447 | |||||||||||||||||||||||||||||
| Impairment expense and loss on disposal of assets | 6 | 1 | 6 | |||||||||||||||||||||||||||||
| Total operating costs and expenses | 7,024 | 4,186 | 4,955 | |||||||||||||||||||||||||||||
| Income from operations | 2,088 | 1,671 | 1,568 | |||||||||||||||||||||||||||||
| Other income (expense) | ||||||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (622) | (685) | (705) | |||||||||||||||||||||||||||||
| Loss on modification or extinguishment of debt | (5) | (43) | — | |||||||||||||||||||||||||||||
| Other income, net | — | — | 10 | |||||||||||||||||||||||||||||
| Total other expense | (627) | (728) | (695) | |||||||||||||||||||||||||||||
| Net income | $ | 1,461 | $ | 943 | $ | 873 | ||||||||||||||||||||||||||
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
(in millions)
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| ASSETS | ||||||||||||||
| Current assets | ||||||||||||||
| Restricted cash and cash equivalents | $ | 98 | $ | 97 | ||||||||||
| Accounts and other receivables, net of current expected credit losses | 571 | 309 | ||||||||||||
| Accounts receivable—affiliate | 232 | 185 | ||||||||||||
| Accounts receivable—related party | 1 | — | ||||||||||||
| Advances to affiliate | 127 | 122 | ||||||||||||
| Inventory | 159 | 93 | ||||||||||||
| Current derivative assets | 21 | 14 | ||||||||||||
| Other current assets | 60 | 41 | ||||||||||||
| Other current assets—affiliate | 21 | 21 | ||||||||||||
| Total current assets | 1,290 | 882 | ||||||||||||
| Property, plant and equipment, net of accumulated depreciation | 14,433 | 14,255 | ||||||||||||
| Debt issuance costs, net of accumulated amortization | 7 | 10 | ||||||||||||
| Derivative assets | 33 | 11 | ||||||||||||
| Other non-current assets, net | 171 | 165 | ||||||||||||
| Total assets | $ | 15,934 | $ | 15,323 | ||||||||||
| LIABILITIES AND MEMBER’S EQUITY | ||||||||||||||
| Current liabilities | ||||||||||||||
| Accounts payable | $ | 18 | $ | 8 | ||||||||||
| Accrued liabilities | 1,012 | 591 | ||||||||||||
| Accrued liabilities—related party | 4 | 4 | ||||||||||||
| Due to affiliates | 73 | 59 | ||||||||||||
| Deferred revenue | 132 | 114 | ||||||||||||
| Current derivative liabilities | 16 | 11 | ||||||||||||
| Total current liabilities | 1,255 | 787 | ||||||||||||
| Long-term debt, net of premium, discount and debt issuance costs | 13,023 | 13,520 | ||||||||||||
| Derivative liabilities | 11 | 35 | ||||||||||||
| Other non-current liabilities | 7 | 8 | ||||||||||||
| Other non-current liabilities—affiliate | 17 | 15 | ||||||||||||
| Commitments and contingencies (see Note 13) | 0 | 0 | ||||||||||||
| Member’s equity | 1,621 | 958 | ||||||||||||
| Total liabilities and member’s equity | $ | 15,934 | $ | 15,323 | ||||||||||
| Year Ended December 31, | |||||||||||
| 2018 | 2017 | 2016 | |||||||||
| Revenues | |||||||||||
| LNG revenues | $ | 4,827 | $ | 2,635 | $ | 539 | |||||
| LNG revenues—affiliate | 1,299 | 1,389 | 294 | ||||||||
| Total revenues | 6,126 | 4,024 | 833 | ||||||||
| Operating costs and expenses | |||||||||||
| Cost of sales (excluding depreciation and amortization expense shown separately below) | 3,403 | 2,317 | 416 | ||||||||
| Cost of sales—affiliate | 32 | 23 | 7 | ||||||||
| Operating and maintenance expense | 342 | 243 | 72 | ||||||||
| Operating and maintenance expense—affiliate | 423 | 329 | 129 | ||||||||
| Development expense | 2 | 2 | — | ||||||||
| Development expense—affiliate | — | — | 1 | ||||||||
| General and administrative expense | 5 | 7 | 7 | ||||||||
| General and administrative expense—affiliate | 50 | 58 | 68 | ||||||||
| Depreciation and amortization expense | 349 | 264 | 83 | ||||||||
| Total operating costs and expenses | 4,606 | 3,243 | 783 | ||||||||
| Income from operations | 1,520 | 781 | 50 | ||||||||
| Other income (expense) | |||||||||||
| Interest expense, net of capitalized interest | (589 | ) | (494 | ) | (186 | ) | |||||
| Loss on modification or extinguishment of debt | — | (42 | ) | (52 | ) | ||||||
| Derivative loss, net | — | (2 | ) | (6 | ) | ||||||
| Other income | 13 | 7 | 1 | ||||||||
| Total other expense | (576 | ) | (531 | ) | (243 | ) | |||||
| Net income (loss) | $ | 944 | $ | 250 | $ | (193 | ) | ||||
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF MEMBER’S EQUITY (DEFICIT)
(in millions)
| Sabine Pass LNG-LP, LLC | Total Member’s Equity | ||||||||||||||||
| Balance at December 31, 2018 | $ | 466 | $ | 466 | |||||||||||||
| Capital contributions | 1,046 | 1,046 | |||||||||||||||
| Distributions | (1,851) | (1,851) | |||||||||||||||
| Net income | 873 | 873 | |||||||||||||||
| Balance at December 31, 2019 | 534 | 534 | |||||||||||||||
| Capital contributions | 488 | 488 | |||||||||||||||
| Distributions | (1,007) | (1,007) | |||||||||||||||
| Net income | 943 | 943 | |||||||||||||||
| Balance at December 31, 2020 | 958 | 958 | |||||||||||||||
| Capital contributions | 821 | 821 | |||||||||||||||
| Distributions | (1,619) | (1,619) | |||||||||||||||
| Net income | 1,461 | 1,461 | |||||||||||||||
| Balance at December 31, 2021 | $ | 1,621 | $ | 1,621 | |||||||||||||
| Sabine Pass LNG-LP, LLC | Total Member’s Equity (Deficit) | ||||||
| Balance at December 31, 2015 | $ | 931 | $ | 931 | |||
| Capital contributions | 1 | 1 | |||||
| Distributions | (253 | ) | (253 | ) | |||
| Net loss | (193 | ) | (193 | ) | |||
| 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 | |||
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
STATEMENTS OF CASH FLOWS
(in millions)
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
| Net income | $ | 1,461 | $ | 943 | $ | 873 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization expense | 468 | 465 | 447 | ||||||||||||||
| Amortization of debt issuance costs, premium and discount | 22 | 24 | 27 | ||||||||||||||
| Loss on modification of debt | 5 | 43 | — | ||||||||||||||
| Total losses (gains) on derivatives, net | (29) | 49 | (72) | ||||||||||||||
| Total gains on derivatives, net—related party | (2) | — | — | ||||||||||||||
| Net cash provided by (used for) settlement of derivative instruments | (17) | (4) | 5 | ||||||||||||||
| Impairment expense and loss on disposal of assets | 6 | 1 | 6 | ||||||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||||
| Accounts and other receivables, net of current expected credit losses | (203) | (17) | 19 | ||||||||||||||
| Accounts receivable—affiliate | (32) | (80) | 9 | ||||||||||||||
| Accounts receivable—related party | (1) | — | — | ||||||||||||||
| Advances to affiliate | (5) | 5 | (34) | ||||||||||||||
| Inventory | (66) | 9 | (16) | ||||||||||||||
| Accounts payable and accrued liabilities | 326 | 2 | (138) | ||||||||||||||
| Accrued liabilities—related party | (1) | 4 | — | ||||||||||||||
| Due to affiliates | (1) | 9 | 8 | ||||||||||||||
| Deferred revenue | 18 | (18) | 40 | ||||||||||||||
| Deferred revenue—affiliate | — | (10) | (13) | ||||||||||||||
| Other, net | (14) | (1) | — | ||||||||||||||
| Other, net—affiliate | 2 | — | — | ||||||||||||||
| Net cash provided by operating activities | 1,937 | 1,424 | 1,161 | ||||||||||||||
| Cash flows from investing activities | |||||||||||||||||
| Property, plant and equipment | (612) | (916) | (1,282) | ||||||||||||||
| Other | — | — | (1) | ||||||||||||||
| Net cash used in investing activities | (612) | (916) | (1,283) | ||||||||||||||
| Cash flows from financing activities | |||||||||||||||||
| Proceeds from issuances of debt | 482 | 1,995 | — | ||||||||||||||
| Redemptions and repayments of debt | (1,000) | (2,000) | — | ||||||||||||||
| Debt issuance and other financing costs | (5) | (35) | — | ||||||||||||||
| Debt extinguishment costs | (3) | (39) | — | ||||||||||||||
| Capital contributions | 821 | 488 | 1,046 | ||||||||||||||
| Distributions | (1,619) | (1,001) | (1,499) | ||||||||||||||
| Net cash used in financing activities | (1,324) | (592) | (453) | ||||||||||||||
| Net increase (decrease) in restricted cash and cash equivalents | 1 | (84) | (575) | ||||||||||||||
| Restricted cash and cash equivalents—beginning of period | 97 | 181 | 756 | ||||||||||||||
| Restricted cash and cash equivalents—end of period | $ | 98 | $ | 97 | $ | 181 | |||||||||||
| Year Ended December 31, | |||||||||||
| 2018 | 2017 | 2016 | |||||||||
| Cash flows from operating activities | |||||||||||
| Net income (loss) | $ | 944 | $ | 250 | $ | (193 | ) | ||||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||||||||||
| Depreciation and amortization expense | 349 | 264 | 83 | ||||||||
| Amortization of debt issuance costs, deferred commitment fees, premium and discount | 22 | 19 | 12 | ||||||||
| Loss on modification or extinguishment of debt | — | 42 | 52 | ||||||||
| Total losses (gains) on derivatives, net | 101 | 26 | (36 | ) | |||||||
| Net cash used for settlement of derivative instruments | (3 | ) | (14 | ) | (7 | ) | |||||
| Changes in operating assets and liabilities: | |||||||||||
| Accounts and other receivables | (122 | ) | (99 | ) | (90 | ) | |||||
| Accounts receivable—affiliate | 49 | (63 | ) | (99 | ) | ||||||
| Advances to affiliate | (76 | ) | (13 | ) | 1 | ||||||
| Inventory | (3 | ) | 11 | (60 | ) | ||||||
| Accounts payable and accrued liabilities | 165 | 190 | 179 | ||||||||
| Due to affiliates | (6 | ) | 22 | 1 | |||||||
| Deferred revenue | 7 | 38 | 46 | ||||||||
| Other, net | (4 | ) | (4 | ) | (10 | ) | |||||
| Other, net—affiliate | — | (12 | ) | (9 | ) | ||||||
| Net cash provided by (used in) operating activities | 1,423 | 657 | (130 | ) | |||||||
| Cash flows from investing activities | |||||||||||
| Property, plant and equipment, net | (771 | ) | (1,279 | ) | (2,306 | ) | |||||
| Other | — | — | (32 | ) | |||||||
| Net cash used in investing activities | (771 | ) | (1,279 | ) | (2,338 | ) | |||||
| Cash flows from financing activities | |||||||||||
| Proceeds from issuances of debt | — | 2,314 | 5,443 | ||||||||
| Repayments of debt | — | (703 | ) | (2,765 | ) | ||||||
| Debt issuance and deferred financing costs | — | (29 | ) | (42 | ) | ||||||
| Capital contributions | 129 | 7 | 1 | ||||||||
| Distributions | (569 | ) | (781 | ) | — | ||||||
| Net cash provided by (used in) financing activities | (440 | ) | 808 | 2,637 | |||||||
| Net increase in cash, cash equivalents and restricted cash | 212 | 186 | 169 | ||||||||
| Cash, cash equivalents and restricted cash—beginning of period | 544 | 358 | 189 | ||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 756 | $ | 544 | $ | 358 | |||||
| December 31, | |||||||
| 2018 | 2017 | ||||||
| Cash and cash equivalents | $ | — | $ | — | |||
| Restricted cash | 756 | 544 | |||||
| Total cash, cash equivalents and restricted cash | $ | 756 | $ | 544 | |||
The accompanying notes are an integral part of these financial statements.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
We are a Delaware limited liability company formed by Cheniere Partners to develop, construct and operate natural gas liquefaction facilities in Cameron Parish, Louisiana (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities owned and operated by SPLNG.CQP. We are a Houston-based company with one1 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 CQP through ownership in Cheniere Energy Partners GP, LLC.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Financial Statements have been prepared in accordance with GAAP. CertainWhen necessary, reclassifications have beenthat are not material to our Financial Statements are made to conform prior period financial information to conform to the current year presentation. The reclassifications did not have a material effect on our financial position, results of operations or cash flows.
Use of Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the recoverabilityfair value measurements of derivatives and other instruments, useful lives of property, plant and equipment derivative instruments,and asset retirement obligations (“AROs”) and fair value measurements.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 other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability.liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments.
The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.
39
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Revenue Recognition
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. 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.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents
Restricted cash 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.
Accounts Receivableand Other Receivables
Accounts receivable isand other receivables are reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated forany current expected credit losses. TheCurrent expected credit losses consider the risk of loss on impaired receivables is primarily determined based on the debtor’spast events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and the estimated valueother risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Statements of any collateral. We did not recognize any impairment expense related to accounts receivable during the years endedIncome. As of both December 31, 2018, 20172021 and 2016.2020, we had current expected credit losses on our accounts and other receivables of $5 million.
Inventory
LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequentlyvalue. Inventory is charged to expense when issued.sold, or capitalized to property, plant and equipment when issued, primarily using the weighted average method.
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 and lease optionacquisition costs, that are capitalized as property, plant and equipmentdetailed 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.
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
40
SABINE PASS LIQUEFACTION, LLC
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 recorded $5 million of impairments related to property, plant and equipment during the year ended December 31, 2021. We did not recognizerecord any impairment expenseimpairments related to property, plant and equipment during the years ended December 31, 2018, 20172020 and 2016, respectively.2019.
Interest Capitalization
We capitalize interest and other related debt costs during the construction period of our LNG terminalsterminal and related pipelinesassets as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception.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.
Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation.criteria. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2018, 20172021, 2020 and 2016.2019. See Note 7—Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cashderivative instruments and cash equivalents and restricted cash. Weaccounts receivable related to our long-term SPAs, as discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.
We have entered into fixed price long-term SPAs generally with terms of at least 20 years with seven unaffiliated8 third parties.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.
41
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.
Debt
Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Debt is recorded on our Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest
method. Gains and losses on the extinguishment or modification of debt are recorded in gain (loss)loss on modification or extinguishment of debt on our Statements of Operations.Income.
•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 amortized to interest expense or property, plantissued based on facts and equipment over the termcircumstances existing as of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on modification or extinguishment of debt.balance sheet date.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the liquefaction facilities at the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.
Income Taxes
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss which may vary substantially from the net income or loss reported on our Statements of Operations, 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, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.
At December 31, 2018,2021, the tax basis of our assets and liabilities was $2.6$7.2 billion less than the reported amounts of our assets and liabilities.
42
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Business Segment
Our liquefaction operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of SPL in total when evaluating financial performance and for purposes of allocating resources.
Recent Accounting Standards
In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.
NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS
Restricted cash 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. As of December 31, 20182021 and 2017,2020, we had $98 million and $97 million of restricted cash consisted of the following (in millions):and cash equivalents, respectively.
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| Current restricted cash | ||||||||
| Liquefaction Project | $ | 756 | $ | 544 | ||||
Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.
NOTE 4—ACCOUNTS AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES
As of December 31, 20182021 and 2017,2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Trade receivable | $ | 546 | $ | 300 | ||||||||||
| Other accounts receivable | 25 | 9 | ||||||||||||
| Total accounts and other receivables, net of current expected credit losses | $ | 571 | $ | 309 | ||||||||||
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| Trade receivable | $ | 330 | $ | 185 | ||||
| Other accounts receivable | 16 | 4 | ||||||
| Total accounts and other receivables | $ | 346 | $ | 189 | ||||
NOTE 5—INVENTORY
As of December 31, 20182021 and 2017,2020, inventory consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Materials | $ | 71 | $ | 68 | ||||||||||
| LNG | 44 | 8 | ||||||||||||
| Natural gas | 43 | 17 | ||||||||||||
| Other | 1 | — | ||||||||||||
| Total inventory | $ | 159 | $ | 93 | ||||||||||
43
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| Natural gas | $ | 28 | $ | 17 | ||||
| LNG | 6 | 26 | ||||||
| Materials and other | 53 | 42 | ||||||
| Total inventory | $ | 87 | $ | 85 | ||||
NOTE 6—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION
As of December 31, 20182021 and 2017,2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| LNG terminal | ||||||||||||||
| LNG terminal | $ | 13,751 | $ | 13,711 | ||||||||||
| LNG terminal construction-in-process | 2,699 | 2,100 | ||||||||||||
| Accumulated depreciation | (2,021) | (1,561) | ||||||||||||
| Total LNG terminal, net of accumulated depreciation | 14,429 | 14,250 | ||||||||||||
| Fixed assets | ||||||||||||||
| Fixed assets | 19 | 19 | ||||||||||||
| Accumulated depreciation | (15) | (14) | ||||||||||||
| Total fixed assets, net of accumulated depreciation | 4 | 5 | ||||||||||||
| Property, plant and equipment, net of accumulated depreciation | $ | 14,433 | $ | 14,255 | ||||||||||
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| LNG terminal costs | ||||||||
| LNG terminal | $ | 10,004 | $ | 9,963 | ||||
| LNG terminal construction-in-process | 3,866 | 3,283 | ||||||
| Accumulated depreciation | (667 | ) | (330 | ) | ||||
| Total LNG terminal costs, net | 13,203 | 12,916 | ||||||
| Fixed assets | ||||||||
| Fixed assets | 14 | 10 | ||||||
| Accumulated depreciation | (8 | ) | (6 | ) | ||||
| Total fixed assets, net | 6 | 4 | ||||||
| Property, plant and equipment, net | $ | 13,209 | $ | 12,920 | ||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| Depreciation expense | $ | 463 | $ | 460 | $ | 442 | ||||||||||||||||||||||||||
| Offsets to LNG terminal costs (1) | 105 | — | 48 | |||||||||||||||||||||||||||||
(1)We realizedrecognize offsets to LNG terminal costs of $94 million, $301 million and $201 million in the years ended December 31, 2018, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or
loaded prior to the start of commercial operations of the respective TrainTrains 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 with similar estimated usefulhave depreciable lives have a depreciable range between 6 and 50 years, as follows:
| Components | Useful life | |||||||
| Water pipelines | 30 | |||||||
| Liquefaction processing equipment | 6-50 | |||||||
| Other | ||||||||
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 for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”). We 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 Operations to the extent not utilized for the commissioning process.process, in which case it is capitalized.
44
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 20182021 and 2017, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Balance Sheets2020 (in millions).:
| Fair Value Measurements as of | |||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||
| Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||||||||||||||||||||||||||||||
| Liquefaction Supply Derivatives asset (liability) | $ | 2 | $ | (13) | $ | 38 | $ | 27 | $ | 1 | $ | (1) | $ | (21) | $ | (21) | |||||||||||||||||||||||||||||||
| Fair Value Measurements as of | |||||||||||||||||||||||||||||||
| December 31, 2018 | December 31, 2017 | ||||||||||||||||||||||||||||||
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) | $ | 5 | $ | (23 | ) | $ | (25 | ) | $ | (43 | ) | $ | 2 | $ | 10 | $ | 43 | $ | 55 | ||||||||||||
We value our Liquefaction Supply Derivatives using a market basedmarket-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 basis prices and, as applicable to our natural gas supply contracts, our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on theevents deriving fair value of the respective natural gas supply contracts.value.
We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputsincorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that aremarket participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments appliedperiods, liquidity, volatility and contract duration.
The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio.prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2018:
2021:
Net Fair Value Asset (in millions) | Valuation Approach | Significant Unobservable Input | Range of Significant Unobservable Inputs | |||||||||||||||||||||||
| Physical Liquefaction Supply Derivatives | $ | Market approach incorporating present value techniques | $ | |||||||||||||||||||||||
(1)Unobservable inputs were weighted by the relative fair value of the instruments.
Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.
The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2018, 20172021, 2020 and 20162019 (in millions):
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| Balance, beginning of period | $ | (21) | $ | 24 | $ | (25) | ||||||||||||||||||||||||||
| Realized and mark-to-market gains (losses): | ||||||||||||||||||||||||||||||||
| Included in cost of sales | 74 | (43) | 6 | |||||||||||||||||||||||||||||
| Purchases and settlements: | ||||||||||||||||||||||||||||||||
| Purchases | (10) | 5 | — | |||||||||||||||||||||||||||||
| Settlements | (5) | (7) | 42 | |||||||||||||||||||||||||||||
| Transfers out of Level 3, net (1) | — | — | 1 | |||||||||||||||||||||||||||||
| Balance, end of period | $ | 38 | $ | (21) | $ | 24 | ||||||||||||||||||||||||||
| Change in unrealized gain (loss) relating to instruments still held at end of period | $ | 74 | $ | (43) | $ | 6 | ||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
| Balance, beginning of period | $ | 43 | $ | 79 | $ | 32 | ||||||
| Realized and mark-to-market gains (losses): | ||||||||||||
| Included in cost of sales (1) | (3 | ) | (37 | ) | 48 | |||||||
| Purchases and settlements: | ||||||||||||
| Purchases | (37 | ) | 14 | 1 | ||||||||
| Settlements (1) | (29 | ) | (12 | ) | (2 | ) | ||||||
| Transfers out of Level 3 (2) | 1 | (1 | ) | — | ||||||||
| Balance, end of period | $ | (25 | ) | $ | 43 | $ | 79 | |||||
| Change in unrealized gains (losses) relating to instruments still held at end of period | $ | (3 | ) | $ | (37 | ) | $ | 49 | ||||
(1)Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
45
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement.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 evaluate our own abilitywill be unable to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide forWe incorporate both our own nonperformance risk and the unconditional right of set-off for all derivative assets and liabilities with a given counterpartyrespective counterparty’s nonperformance risk in the event of default.
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
| Interest Rate Derivatives loss | $ | — | $ | (2 | ) | $ | (6 | ) | ||||
Liquefaction Supply Derivatives
We have entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to six10 years, some of which commence upon the satisfaction of certain conditions precedent.
The notional natural gas position of our Liquefaction Supply Derivatives was approximately 2,9785,194 TBtu and 1,5204,970 TBtu as of December 31, 20182021 and 2017,2020, respectively.
Fair Value and Location of Derivative Assets and Liabilities on the Balance Sheets
The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Balance Sheets (in millions):
| Fair Value Measurements as of (1) | ||||||||
| Balance Sheet Location | December 31, 2018 | December 31, 2017 | ||||||
| Other current assets | $ | 6 | $ | 41 | ||||
| Non-current derivative assets | 31 | 17 | ||||||
| Total derivative assets | 37 | 58 | ||||||
| Derivative liabilities | (66 | ) | — | |||||
| Non-current derivative liabilities | (14 | ) | (3 | ) | ||||
| Total derivative liabilities | (80 | ) | (3 | ) | ||||
| Derivative asset (liability), net | $ | (43 | ) | $ | 55 | |||
| Fair Value Measurements as of (1) | ||||||||||||||||||||||||||||||||||||||
| Balance Sheets Location | December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||||||||||||||||
| Current derivative assets | $ | 21 | $ | 14 | ||||||||||||||||||||||||||||||||||
| Derivative assets | 33 | 11 | ||||||||||||||||||||||||||||||||||||
| Total derivative assets | 54 | 25 | ||||||||||||||||||||||||||||||||||||
| Current derivative liabilities | (16) | (11) | ||||||||||||||||||||||||||||||||||||
| Derivative liabilities | (11) | (35) | ||||||||||||||||||||||||||||||||||||
| Total derivative liabilities | (27) | (46) | ||||||||||||||||||||||||||||||||||||
| Derivative asset (liability), net | $ | 27 | $ | (21) | ||||||||||||||||||||||||||||||||||
(1)Does not include collateral posted with counterparties by us of $7 million and $4 million, which are included in other current assets in our Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract that we had with a related party, which had a fair value of zero as of December 31, 2020. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12—Related Party Transactions.
The following table shows the changes in the fair value, settlementseffect and location of our Liquefaction Supply Derivatives recorded on our Statements of Operations during the years ended December 31, 2018, 20172021, 2020 and 20162019 (in millions):
| Year Ended December 31, | |||||||||||||
| Statement of Operations Location (1) | 2018 | 2017 | 2016 | ||||||||||
| Liquefaction Supply Derivatives loss | LNG revenues | $ | (1 | ) | $ | — | $ | — | |||||
| Liquefaction Supply Derivatives gain (loss) | Cost of sales | (100 | ) | (24 | ) | 42 | |||||||
| Gain (Loss) Recognized in Statements of Operations | |||||||||||||||||||||||||||||||||||
| Statements of Operations Location (1) | Year Ended December 31, | ||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| LNG revenues | $ | (1) | $ | — | $ | 1 | |||||||||||||||||||||||||||||
| Cost of sales | 30 | (49) | 71 | ||||||||||||||||||||||||||||||||
| Cost of sales—related party (2) | 2 | — | — | ||||||||||||||||||||||||||||||||
(1)Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(2)Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12—Related Party Transactions.
46
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
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):
| Liquefaction Supply Derivatives | ||||||||
| As of December 31, 2021 | ||||||||
| Gross assets | $ | 79 | ||||||
| Offsetting amounts | (25) | |||||||
| Net assets | $ | 54 | ||||||
| Gross liabilities | $ | (33) | ||||||
| Offsetting amounts | 6 | |||||||
| Net liabilities | $ | (27) | ||||||
| As of December 31, 2020 | ||||||||
| Gross assets | $ | 69 | ||||||
| Offsetting amounts | (44) | |||||||
| Net assets | $ | 25 | ||||||
| Gross liabilities | $ | (48) | ||||||
| Offsetting amounts | 2 | |||||||
| Net liabilities | $ | (46) | ||||||
| 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, 2018 | ||||||||||||
| Liquefaction Supply Derivatives | $ | 63 | $ | (26 | ) | $ | 37 | |||||
| Liquefaction Supply Derivatives | (92 | ) | 12 | (80 | ) | |||||||
| As of December 31, 2017 | ||||||||||||
| Liquefaction Supply Derivatives | $ | 64 | $ | (6 | ) | $ | 58 | |||||
| Liquefaction Supply Derivatives | (3 | ) | — | (3 | ) | |||||||
NOTE 8—OTHER NON-CURRENT ASSETS, NET
As of December 31, 20182021 and 2017,2020, other non-current assets, net consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Advances made to municipalities for water system enhancements | $ | 81 | $ | 84 | ||||||||||
| Advances and other asset conveyances to third parties to support LNG terminal | 37 | 33 | ||||||||||||
| Operating lease assets | 23 | 23 | ||||||||||||
| Advances made under EPC and non-EPC contracts | 5 | 9 | ||||||||||||
| Information technology service prepayments | 4 | 5 | ||||||||||||
| Other | 21 | 11 | ||||||||||||
| Total other non-current assets, net | $ | 171 | $ | 165 | ||||||||||
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| Advances made under EPC and non-EPC contracts | $ | 14 | $ | 26 | ||||
| Advances made to municipalities for water system enhancements | 90 | 93 | ||||||
| Advances and other asset conveyances to third parties to support LNG terminals | 36 | 30 | ||||||
| Tax-related payments and receivables | — | 1 | ||||||
| Information technology service assets | 16 | 19 | ||||||
| Other | 2 | — | ||||||
| Total other non-current assets, net | $ | 158 | $ | 169 | ||||
NOTE 9—ACCRUED LIABILITIES
As of December 31, 20182021 and 2017,2020, accrued liabilities consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Accrued natural gas purchases | $ | 786 | $ | 374 | ||||||||||
| Interest costs and related debt fees | 133 | 150 | ||||||||||||
| Liquefaction Project costs | 89 | 64 | ||||||||||||
| Other accrued liabilities | 4 | 3 | ||||||||||||
| Total accrued liabilities | $ | 1,012 | $ | 591 | ||||||||||
47
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| Interest costs and related debt fees | $ | 186 | $ | 230 | ||||
| Accrued natural gas purchases | 518 | 298 | ||||||
| Liquefaction Project costs | 64 | 78 | ||||||
| Total accrued liabilities | $ | 768 | $ | 606 | ||||
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 10—DEBT
As of December 31, 20182021 and 2017,2020, our debt consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Senior Secured Notes: | ||||||||||||||
| 6.25% due 2022 | $ | — | $ | 1,000 | ||||||||||
| 5.625% due 2023 | 1,500 | 1,500 | ||||||||||||
| 5.75% due 2024 | 2,000 | 2,000 | ||||||||||||
| 5.625% due 2025 | 2,000 | 2,000 | ||||||||||||
| 5.875% due 2026 | 1,500 | 1,500 | ||||||||||||
| 5.00% due 2027 | 1,500 | 1,500 | ||||||||||||
| 4.200% due 2028 | 1,350 | 1,350 | ||||||||||||
| 4.500% due 2030 | 2,000 | 2,000 | ||||||||||||
| 4.27% weighted average rate due 2037 | 1,282 | 800 | ||||||||||||
| Total Senior Secured Notes | 13,132 | 13,650 | ||||||||||||
| $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 Working Capital Facility”) | — | — | ||||||||||||
| Total debt | 13,132 | 13,650 | ||||||||||||
| Unamortized premium, discount and debt issuance costs, net | (109) | (130) | ||||||||||||
| Total debt, net of premium, discount and debt issuance costs | $ | 13,023 | $ | 13,520 | ||||||||||
| December 31, | ||||||||
| 2018 | 2017 | |||||||
| 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 | (150 | ) | (173 | ) | ||||
| Total long-term debt, net | 13,500 | 13,477 | ||||||
| Current debt | ||||||||
| $1.2 billion Working Capital Facility (“Working Capital Facility”) | — | — | ||||||
| Total debt, net | $ | 13,500 | $ | 13,477 | ||||
| Years Ending December 31, | Principal Payments | |||
| 2019 | $ | — | ||
| 2020 | — | |||
| 2021 | 2,000 | |||
| 2022 | 1,000 | |||
| 2023 | 1,500 | |||
| Thereafter | 9,150 | |||
| Total | $ | 13,650 | ||
Senior Secured 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. As of December 31, 2018, we were in compliance with all covenants related to the Senior Notes. Interest on the Senior Notes is payable semi-annually in arrears.
Below is a summaryschedule of future principal payments that we are obligated to make on our Working Capital Facility as ofoutstanding debt at December 31, 20182021 (in millions):
| Years Ending December 31, | Principal Payments | |||||||
| 2022 | $ | — | ||||||
| 2023 | 1,500 | |||||||
| 2024 | 2,000 | |||||||
| 2025 | 2,037 | |||||||
| 2026 | 1,579 | |||||||
| Thereafter | 6,016 | |||||||
| Total | $ | 13,132 | ||||||
48
| Working Capital Facility | ||||
| Original facility size | $ | 1,200 | ||
| Less: | ||||
| Outstanding balance | — | |||
| Letters of credit issued | 425 | |||
| Available commitment | $ | 775 | ||
| Interest rate | LIBOR plus 1.75% or base rate plus 0.75% | |||
| Maturity date | December 31, 2020, with various terms for underlying loans | |||
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Below is a summary of credit,our 2020 Working Capital Facility as well as customary affirmative and negative covenants. As of December 31, 2018, we were in compliance with all covenants related to the Working Capital Facility. 2021 (in millions):
| 2020 Working Capital Facility (1) | ||||||||||||||
| Original facility size | $ | 1,200 | ||||||||||||
| Less: | ||||||||||||||
| Outstanding balance | — | |||||||||||||
| Letters of credit issued | 395 | |||||||||||||
| Available commitment | $ | 805 | ||||||||||||
| Priority ranking | Senior secured | |||||||||||||
| Interest rate on available balance | LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750% | |||||||||||||
| Weighted average interest rate of outstanding balance | n/a | |||||||||||||
| Commitment fees on undrawn balance | 0.20% | |||||||||||||
| Maturity date | March 19, 2025 | |||||||||||||
(1)Our obligations under the 2020 Working Capital Facility are secured by substantially all of our assets as well as a pledge of all of the membership interests in us and certain of our future subsidiaries on a pari passu basis by a first priority lien with the Senior Secured Notes.
Restrictive Debt Covenants
The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit our ability to make certain investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, deposits are made into any required debt service reserve accounts and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.
As of December 31, 2021, we were in compliance with all covenants related to our debt agreements.
Interest Expense
Total interest expense, net of capitalized interest consisted of the following (in millions):
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| Total interest cost | $ | 754 | $ | 779 | $ | 790 | ||||||||||||||||||||||||||
| Capitalized interest | (132) | (94) | (85) | |||||||||||||||||||||||||||||
| Total interest expense, net of capitalized interest | $ | 622 | $ | 685 | $ | 705 | ||||||||||||||||||||||||||
49
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
| Total interest cost | $ | 791 | $ | 779 | $ | 649 | ||||||
| Capitalized interest | (202 | ) | (285 | ) | (463 | ) | ||||||
| Total interest expense, net | $ | 589 | $ | 494 | $ | 186 | ||||||
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Fair Value Disclosures
The following table shows the carrying amount which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in millions):
| December 31, 2018 | December 31, 2017 | |||||||||||||||
Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||
| Senior notes (1) | $ | 12,709 | $ | 13,235 | $ | 12,687 | $ | 13,955 | ||||||||
| 2037 Senior Notes (2) | 791 | 817 | 790 | 871 | ||||||||||||
| December 31, 2021 | December 31, 2020 | |||||||||||||||||||||||||
| Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||||||||||||
| Senior notes — Level 2 (1) | $ | 11,850 | $ | 13,128 | $ | 12,850 | $ | 14,834 | ||||||||||||||||||
| Senior notes — Level 3 (2) | 1,282 | 1,466 | 800 | 1,036 | ||||||||||||||||||||||
| Working capital facility — Level 3 (3) | — | — | — | — | ||||||||||||||||||||||
(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS
The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2018, 20172021, 2020 and 20162019 (in millions):
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
| LNG revenues | $ | 4,687 | $ | 2,615 | $ | 535 | ||||||
| LNG revenues—affiliate | 1,299 | 1,389 | 294 | |||||||||
| Total revenues from customers | 5,986 | 4,004 | 829 | |||||||||
| Gains from derivative instruments (1) | 140 | 20 | 4 | |||||||||
| Total revenues | $ | 6,126 | $ | 4,024 | $ | 833 | ||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| LNG revenues (1) | $ | 7,640 | $ | 5,195 | $ | 5,210 | ||||||||||||||||||||||||||
| LNG revenues—affiliate | 1,472 | 662 | 1,312 | |||||||||||||||||||||||||||||
| LNG revenues—related party | 1 | — | — | |||||||||||||||||||||||||||||
| Total revenues from customers | 9,113 | 5,857 | 6,522 | |||||||||||||||||||||||||||||
| Net derivative gain (loss) (2) | (1) | — | 1 | |||||||||||||||||||||||||||||
| Total revenues | $ | 9,112 | $ | 5,857 | $ | 6,523 | ||||||||||||||||||||||||||
(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $553 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery. We did 0t have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2021 and 2019. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.
LNG Revenues
We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made
available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 12—Related Party Transactions for additional information regarding these agreements.
50
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the salecontract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price.
Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.
The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Balance Sheets (in millions):
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Contract assets, net of current expected credit losses | $ | 1 | $ | — | ||||||||||
Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the year ended December 31, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.
The following table reflects the changes in our contract liabilities, which we classify as deferred revenuesrevenue on our Balance Sheets (in millions):
| Year Ended December 31, 2021 | ||||||||
| Deferred revenue, beginning of period | $ | 114 | ||||||
| Cash received but not yet recognized in revenue | 132 | |||||||
| Revenue recognized from prior period deferral | (114) | |||||||
| Deferred revenue, end of period | $ | 132 | ||||||
The following table reflects the changes in our contract liabilities, which we classify as other non-current liabilities—affiliate on our Balance Sheets (in millions):
| Year Ended December 31, 2021 | ||||||||
| Deferred revenue—affiliate, beginning of period | $ | — | ||||||
| Cash received but not yet recognized in revenue | 2 | |||||||
| Deferred revenue—affiliate, end of period | $ | 2 | ||||||
51
| Year Ended December 31, | ||||||||
| 2018 | 2017 | |||||||
| Deferred revenues, beginning of period | $ | 84 | $ | 46 | ||||
| Cash received but not yet recognized | 91 | 84 | ||||||
| Revenue recognized from prior period deferral | (84 | ) | (46 | ) | ||||
| Deferred revenues, end of period | $ | 91 | $ | 84 | ||||
SABINE PASS LIQUEFACTION, LLC
Transaction Price Allocated to Future Performance Obligations
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 20182021 and 2017:2020:
| December 31, 2021 | December 31, 2020 | |||||||||||||||||||||||||
| Unsatisfied Transaction Price (in billions) | Weighted Average Recognition Timing (years) (1) | Unsatisfied Transaction Price (in billions) | Weighted Average Recognition Timing (years) (1) | |||||||||||||||||||||||
| LNG revenues | $ | 49.3 | 9 | $ | 52.1 | 9 | ||||||||||||||||||||
| LNG revenues—affiliate | 2.1 | 3 | 0.1 | 1 | ||||||||||||||||||||||
| Total revenues | $ | 51.4 | $ | 52.2 | ||||||||||||||||||||||
| December 31, 2018 | December 31, 2017 | |||||||||||
Unsatisfied Transaction Price (in billions) | Weighted Average Recognition Timing (years) (1) | Unsatisfied Transaction Price (in billions) | Weighted Average Recognition Timing (years) (1) | |||||||||
| LNG revenues | $ | 53.6 | 10 | $ | 55.7 | 10 | ||||||
(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 57%61% and 58%42% of our LNG revenues from contracts included in the table above during the years ended December 31, 2021 and 2020, respectively, were related to variable consideration received from customerscustomers. Approximately 96% and 100% of our LNG revenues—affiliate from contracts included in the table above during the years ended December 31, 20182021 and 2017, respectively. All of our LNG revenues—affiliate2020, respectively, were related to variable consideration received from customers during each of the years ended December 31, 2018 and 2017.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 of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 12—RELATED PARTY TRANSACTIONS
Below is a summary of our related party transactions as reported on our Statements of Operations forduring the years ended December 31, 2018, 20172021, 2020 and 20162019 (in millions):
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| LNG revenues—affiliate | ||||||||||||||||||||||||||||||||
| Cheniere Marketing Agreements | $ | 1,453 | $ | 632 | $ | 1,309 | ||||||||||||||||||||||||||
| Contracts for Sale and Purchase of Natural Gas and LNG | 19 | 30 | 3 | |||||||||||||||||||||||||||||
| Total LNG revenues—affiliate | 1,472 | 662 | 1,312 | |||||||||||||||||||||||||||||
| LNG revenues—related party | ||||||||||||||||||||||||||||||||
| Natural Gas Transportation and Storage Agreements | 1 | — | — | |||||||||||||||||||||||||||||
| Cost of sales—affiliate | ||||||||||||||||||||||||||||||||
| Cheniere Marketing Agreements | 34 | 61 | — | |||||||||||||||||||||||||||||
| Cargo loading fees under TUA | 43 | 33 | 40 | |||||||||||||||||||||||||||||
| Contracts for Sale and Purchase of Natural Gas and LNG | 51 | 16 | 7 | |||||||||||||||||||||||||||||
| Total cost of sales—affiliate | 128 | 110 | 47 | |||||||||||||||||||||||||||||
| Cost of sales—related party | ||||||||||||||||||||||||||||||||
| Natural Gas Transportation and Storage Agreements | 1 | — | — | |||||||||||||||||||||||||||||
| Natural Gas Supply Agreements (1) | 16 | — | — | |||||||||||||||||||||||||||||
| Total cost of sales—related party | 17 | — | — | |||||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | ||||||||||||||||||||||||||||||||
| TUA | 266 | 265 | 261 | |||||||||||||||||||||||||||||
| Natural Gas Transportation Agreement | 81 | 82 | 81 | |||||||||||||||||||||||||||||
| Services Agreements | 109 | 118 | 107 | |||||||||||||||||||||||||||||
| LNG Site Sublease Agreement | 1 | 1 | 1 | |||||||||||||||||||||||||||||
| Total operating and maintenance expense—affiliate | 457 | 466 | 450 | |||||||||||||||||||||||||||||
| Operating and maintenance expense—related party | ||||||||||||||||||||||||||||||||
| Natural Gas Transportation and Storage Agreements | 46 | 13 | — | |||||||||||||||||||||||||||||
| General and administrative expense—affiliate | ||||||||||||||||||||||||||||||||
| Services Agreements | 61 | 71 | 79 | |||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
| LNG revenues—affiliate | ||||||||||||
| Cheniere Marketing SPA and Cheniere Marketing Master SPA | $ | 1,299 | $ | 1,389 | $ | 294 | ||||||
| Cost of sales—affiliate | ||||||||||||
| Cargo loading fees under TUA | 32 | 23 | 5 | |||||||||
| Fees under the Pre-commercial LNG Marketing Agreement | — | — | 2 | |||||||||
| Total cost of sales—affiliate | 32 | 23 | 7 | |||||||||
| Operating and maintenance expense—affiliate | ||||||||||||
| TUA | 256 | 190 | 61 | |||||||||
| Natural Gas Transportation Agreement | 80 | 73 | 45 | |||||||||
| Services Agreements | 87 | 65 | 22 | |||||||||
| LNG Site Sublease Agreement | — | 1 | 1 | |||||||||
| Total operating and maintenance expense—affiliate | 423 | 329 | 129 | |||||||||
| Development expense—affiliate | ||||||||||||
| Services Agreements | — | — | 1 | |||||||||
| General and administrative expense—affiliate | ||||||||||||
| Services Agreements | 50 | 58 | 68 | |||||||||
(1)Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed below.
As of December 31, 20182021 and 2017,2020, we had $113$232 million and $163$185 million, respectively, of accounts receivable—affiliate respectively, under the agreements described below.
LNG Terminal-Related Agreements
Terminal Use Agreements
We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately 2.02 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, we, Cheniere Investments and SPLNG also entered into a terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use our reserved capacity under the TUA and had the obligation to pay the TUA Fees required by the TUA to SPLNG. Cheniere Investments’ right to use our capacity at the Sabine Pass LNG terminal and its respective percentage of TUA Fees payable was reduced from 100% to zero as each of Trains 1 through 4 reached commercial operations.
53
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Cheniere Marketing SPA
Cheniere Marketing has an SPA (“Base SPA”) with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.
In May 2019, we and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by us to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo.
Cheniere Marketing Master SPA
We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement. We executed a confirmation with
Cheniere Marketing that obligates Letter Agreements
Cheniere Marketing has letter agreements with us to purchase up to 306 cargoes to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub.
In December 2020, we and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes that were delivered in certain2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu.
In December 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes that were delivered in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.
In May 2019, we and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu that were delivered between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu.
Facility Swap Agreement
In August 2020, we entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to buypotentially 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 produced during the period while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) has control of, and is commissioning, Train 5would be (i) 115% of the Liquefaction Project.applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Natural Gas Transportation and Storage Agreements
To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, we have a transportation precedent 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 agreements with CTPL have a primary term ofthat continues until 20 years from commercial operation of Train 2May 2016 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to two2 consecutive ten-year terms.terms of 10 years. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise. As of both December 31, 2021 and 2020, we recorded due to affiliates of $8 million and $6 million, respectively, related to this agreement.
54
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
We are also party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by the investment management company that indirectly acquired a portion of CQP’s limited partner interests in September 2020. In addition to the amounts recorded on our Statements of Operations in the table above, we recorded accrued liabilities—related party of $4 million as of both December 31, 2021 and 2020 with this related party.
Services Agreements
As of December 31, 20182021 and 2017,2020, we had $210$127 million and $26$122 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.
Cheniere Investments Information Technology Services Agreement
Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.
Liquefaction O&M Agreement
We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of Cheniere Partners,CQP, pursuant to which we receive all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on our behalf, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train.
Liquefaction MSA
We have a management services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our behalf and providing contract administration services for all
contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, we pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.
55
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
LNG Site Sublease Agreement
We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG terminal site for the Liquefaction Project. The aggregate annual sublease payment is $1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple 10-year extensionsperiods of 10 years with similar terms as the initial terms. The annual sublease payments will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreements.
Cooperation Agreement
We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. UnderWe conveyed $6 million in assets to SPLNG under this agreement we conveyed to SPLNG $253 million of assets forduring the year ended December 31, 2016 which were recorded as non-cash distributions to affiliates.2020. We did not convey any assets to SPLNG under this agreement during the yearsyear ended December 31, 2018 and 2017.2021.
Contracts for Sale and Purchase of Natural Gas and LNG
We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with SPLNG.each party. Natural gas and LNG purchased under these agreements areis initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under these agreements is recorded as LNG revenues—affiliate.
State Tax Sharing Agreement
We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from us under this agreement; therefore,and Cheniere has not demanded any such payments from us.us under the agreement. The agreement is effective for tax returns due on or after August 2012.
NOTE 13—LEASES
| Years ending December 31, | Operating Leases (1) | ||
| 2019 through 2023 | $ | 2 | |
| Thereafter | 7 | ||
| Total | $ | 9 | |
We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain unconditional purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2018,2021, are not recognized as liabilities but require disclosures in our Financial Statements.
LNG Terminal Commitments and Contingencies
We have a lump sum turnkey contractscontract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and constructionEPC of Train 5 and Train 6 of the Liquefaction Project. The total contract price of the EPC contract prices for Train 5 of the Liquefaction Project and Train 6 of the Liquefaction Project, arewhich achieved substantial completion on February 4, 2022, and the third marine berth that is currently under construction is approximately $3.1 billion and $2.5 billion, respectively, reflecting amounts incurred under change orders through December 31, 2018, including estimated costs for an optional third marine berth. We have the right to terminate the EPC contracts for our convenience, in which case Bechtel will be paid (1) the portion2021. As 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.December 31, 2021, we had approximately $0.2 billion remaining under this contract.
We have index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to six years, some of which commence upon the satisfaction of certain conditions precedent. As of December 31, 2018, we have secured up to approximately 3,464 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent are met.10 years.
56
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
Additionally, we have natural gas transportation and storage service agreements for the Liquefaction Project. The initial term of the natural gas transportation agreements 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 ten10 years.
As of December 31, 2018,2021, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions)billions):
| Years Ending December 31, | Payments Due (1) | ||
| 2019 | $ | 2,465 | |
| 2020 | 1,377 | ||
| 2021 | 1,010 | ||
| 2022 | 756 | ||
| 2023 | 641 | ||
| Thereafter | 1,652 | ||
| Total | $ | 7,901 | |
| Years Ending December 31, | Payments Due (1) | ||||
| 2022 | $ | 5.3 | |||
| 2023 | 3.7 | ||||
| 2024 | 2.6 | ||||
| 2025 | 1.7 | ||||
| 2026 | 1.1 | ||||
| Thereafter | 5.7 | ||||
| Total | $ | 20.1 | |||
(1)Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2021. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.
LNG TUAs
We have a TUA with SPLNG pursuant to which we have reserved approximately 2.02 Bcf/d of regasification capacity. See Note 12—Related Party Transactions for additional information regarding this TUA.
Additionally, we have a partial TUA assignment agreement with TotalTotalEnergies Gas & Power North America, Inc. (“Total”), another TUA customer, whereby upon substantial completion of Train 3,5, we gained access to a portionsubstantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, we will gain access to substantially all of Total’s capacity. This agreement provides us with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit us to more flexibly manage our LNG storage capacity and accommodate the development of Trains 5 and 6.capacity. Notwithstanding any arrangements between Total and us, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.
Services Agreements
We have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements.
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 state tax sharing agreement with Cheniere. See Note 12—Related Party Transactions for additional information regarding this agreement.
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, 2018,2021, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.
57
SABINE PASS LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED
NOTE 15—14—CUSTOMER CONCENTRATION
The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivable, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivable, net of current expected credit losses from external customers:customers and contract assets, net of current expected credit losses from external customers, respectively:
| Percentage of Total Revenues from External Customers | Percentage of Accounts Receivable from External Customers | |||||||||
| Year Ended December 31, | December 31, | |||||||||
| 2018 | 2017 | 2016 | 2018 | 2017 | ||||||
| Customer A | 30% | 43% | 77% | 35% | 39% | |||||
| Customer B | 23% | 30% | * | 23% | 32% | |||||
| Customer C | 24% | 25% | —% | 30% | 27% | |||||
| Customer D | 20% | —% | —% | * | —% | |||||
| Percentage of Total Revenues from External Customers | Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers | |||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, | December 31, | |||||||||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | ||||||||||||||||||||||||||||||||||||||||
| Customer A | 25% | 25% | 29% | 29% | 32% | |||||||||||||||||||||||||||||||||||||||
| Customer B | 18% | 19% | 21% | 17% | 22% | |||||||||||||||||||||||||||||||||||||||
| Customer C | 17% | 18% | 21% | * | * | |||||||||||||||||||||||||||||||||||||||
| Customer D | 16% | 16% | 19% | 14% | 21% | |||||||||||||||||||||||||||||||||||||||
| Customer E | 10% | * | * | 13% | * | |||||||||||||||||||||||||||||||||||||||
| Customer F | * | * | * | 12% | * | |||||||||||||||||||||||||||||||||||||||
* Less than 10%
The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.
| Revenues from External Customers | |||||||||||||||||
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| United States | $ | 2,550 | $ | 1,975 | $ | 1,854 | |||||||||||
| India | 1,342 | 970 | 1,113 | ||||||||||||||
| South Korea | 1,336 | 924 | 1,071 | ||||||||||||||
| Ireland | 1,237 | 842 | 989 | ||||||||||||||
| United Kingdom | 966 | 456 | 184 | ||||||||||||||
| Other countries | 208 | 28 | — | ||||||||||||||
| Total | $ | 7,639 | $ | 5,195 | $ | 5,211 | |||||||||||
| Revenues from External Customers | |||||||||||
| Year Ended December 31, | |||||||||||
| 2018 | 2017 | 2016 | |||||||||
| United States | $ | 1,580 | $ | 1,161 | $ | 414 | |||||
| South Korea | 1,168 | 666 | — | ||||||||
| Ireland | 1,098 | 787 | 63 | ||||||||
| India | 981 | — | 23 | ||||||||
| Other countries | — | 21 | 39 | ||||||||
| Total | $ | 4,827 | $ | 2,635 | $ | 539 | |||||
NOTE 16—15—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in millions):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Cash paid during the period for interest, net of amounts capitalized | $ | 615 | $ | 692 | $ | 678 | ||||||||||||||
| Non-cash distributions to affiliates for conveyance of assets | — | 6 | 351 | |||||||||||||||||
| Right-of-use assets obtained in exchange for new operating lease liabilities | — | 3 | — | |||||||||||||||||
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
| Cash paid during the period for interest, net of amounts capitalized | $ | 604 | $ | 438 | $ | 75 | ||||||
| Non-cash distributions to affiliates for conveyance of assets | — | — | 253 | |||||||||
The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $256$322 million, $268$207 million and $263$276 million as of December 31, 2018, 20172021, 2020 and 2016,2019, respectively.
58
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| Year ended December 31, 2018: | ||||||||||||||||
| Revenues | $ | 1,518 | $ | 1,333 | $ | 1,454 | $ | 1,821 | ||||||||
| Income from operations | 391 | 339 | 384 | 406 | ||||||||||||
| Net income | 242 | 193 | 243 | 266 | ||||||||||||
| Year ended December 31, 2017: | ||||||||||||||||
| Revenues | $ | 823 | $ | 925 | $ | 834 | $ | 1,442 | ||||||||
| Income from operations | 145 | 105 | 109 | 422 | ||||||||||||
| Net income (loss) | (4 | ) | (20 | ) | (12 | ) | 286 | |||||||||
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 31, 2018,2021, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included in our Financial Statements on page 34and is incorporated herein by reference.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
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PART III
ITEM 10. MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE
Omitted pursuant to Instruction I of Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to Instruction I of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS
Omitted pursuant to Instruction I of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE
Omitted pursuant to Instruction I of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG LLP, served as our independent auditor for the fiscal years ended December 31, 2018 and 2017.Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 20182021 and 20172020 (in millions):
| Fiscal 2018 | Fiscal 2017 | |||||||
| Audit Fees | $ | 2 | $ | 2 | ||||
| Fiscal 2021 | Fiscal 2020 | |||||||||||||
| Audit Fees | $ | 2 | $ | 2 | ||||||||||
Audit Fees—Audit fees for 20182021 and 20172020 include fees associated with the audit of our annual Financial Statements, reviews of our interim Financial Statements and services performed in connection with registration statements and debt offerings, including comfort letters and consents.
Audit-Related Fees—There were no audit-related fees in 20182021 and 2017.2020.
Tax Fees—There were no tax fees in 20182021 and 2017.2020.
Other Fees—There were no other fees in 20182021 and 2017.2020.
Auditor Pre-Approval Policy and Procedures
We are not a public company and we are not listed on any stock exchange. As a result, we are not required to, and do not, have an independent audit committee, a financial expert or a majority of independent directors. The audit committee of the general partner of 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, 20182021 and 2017.2020.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)Financial Statements and Exhibits
(1)Financial Statements—Sabine Pass Liquefaction, LLC:
(2)Financial Statement Schedules:
All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.
(3)Exhibits:
Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:
•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
•may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;
•may apply standards of materiality that differ from those of a reasonable investor; and
•were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 3.1 | SPL | S-4 | 3.1 | 11/15/2013 | ||||||||||||||||||||||||||||
| 3.2 | SPL | S-4 | 3.2 | 11/15/2013 | ||||||||||||||||||||||||||||
| 4.1 | CQP | 8-K | 4.1 | 2/4/2013 | ||||||||||||||||||||||||||||
| 4.2 | CQP | 8-K | 4.1.1 | 4/16/2013 | ||||||||||||||||||||||||||||
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| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 4.3 | CQP | 8-K | 4.1.2 | 4/16/2013 | ||||||||||||||||||||||||||||
| 4.4 | CQP | 8-K | 4.1.2 | 4/16/2013 | ||||||||||||||||||||||||||||
| 4.5 | CQP | 8-K | 4.1 | 11/25/2013 | ||||||||||||||||||||||||||||
| 4.6 | CQP | 8-K | 4.1 | 5/22/2014 | ||||||||||||||||||||||||||||
| 4.7 | CQP | 8-K | 4.1 | 5/22/2014 | ||||||||||||||||||||||||||||
| 4.8 | CQP | 8-K | 4.2 | 5/22/2014 | ||||||||||||||||||||||||||||
| 4.9 | CQP | 8-K | 4.2 | 5/22/2014 | ||||||||||||||||||||||||||||
| 4.10 | CQP | 8-K | 4.1 | 3/3/2015 | ||||||||||||||||||||||||||||
| 4.11 | CQP | 8-K | 4.1 | 3/3/2015 | ||||||||||||||||||||||||||||
| 4.12 | CQP | 8-K | 4.1 | 6/14/2016 | ||||||||||||||||||||||||||||
| 4.13 | CQP | 8-K | 4.1 | 6/14/2016 | ||||||||||||||||||||||||||||
| 4.14 | CQP | 8-K | 4.1 | 9/23/2016 | ||||||||||||||||||||||||||||
| 4.15 | CQP | 8-K | 4.2 | 9/23/2016 | ||||||||||||||||||||||||||||
| 4.16 | CQP | 8-K | 4.2 | 9/23/2016 | ||||||||||||||||||||||||||||
| 4.17 | CQP | 8-K | 4.1 | 3/6/2017 | ||||||||||||||||||||||||||||
| 4.18 | CQP | 8-K | 4.1 | 3/6/2017 | ||||||||||||||||||||||||||||
| 4.19 | SPL | 8-K | 4.1 | 5/8/2020 | ||||||||||||||||||||||||||||
| 4.20 | SPL | 8-K | 4.1 | 5/8/2020 | ||||||||||||||||||||||||||||
| 4.21 | CQP | 8-K | 4.1 | 2/27/2017 | ||||||||||||||||||||||||||||
| 4.22 | CQP | 8-K | 4.1 | 2/27/2017 | ||||||||||||||||||||||||||||
| 4.23* | ||||||||||||||||||||||||||||||||
| 4.24* | ||||||||||||||||||||||||||||||||
62
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 4.25* | ||||||||||||||||||||||||||||||||
| 4.26* | ||||||||||||||||||||||||||||||||
| 4.27* | ||||||||||||||||||||||||||||||||
| 4.28* | ||||||||||||||||||||||||||||||||
| 4.29* | ||||||||||||||||||||||||||||||||
| 4.30* | ||||||||||||||||||||||||||||||||
| 4.31* | ||||||||||||||||||||||||||||||||
| 4.32* | ||||||||||||||||||||||||||||||||
| 10.1 | CQP | 8-K | 10.1 | 11/21/2011 | ||||||||||||||||||||||||||||
| 10.2 | CQP | 10-Q | 10.1 | 5/3/2013 | ||||||||||||||||||||||||||||
| 10.3 | SPL (SEC File No. 333-215882) | S-4 | 10.3 | 2/3/2017 | ||||||||||||||||||||||||||||
| 10.4 | CQP | 8-K | 10.1 | 12/12/2011 | ||||||||||||||||||||||||||||
| 10.5 | CQP | 10-K | 10.18 | 2/22/2013 | ||||||||||||||||||||||||||||
| 10.6 | CQP | 8-K | 10.1 | 1/26/2012 | ||||||||||||||||||||||||||||
| 10.7 | CQP | 8-K | 10.1 | 1/30/2012 | ||||||||||||||||||||||||||||
| 10.8 | CQP | 10-K | 10.19 | 2/22/2013 | ||||||||||||||||||||||||||||
| 10.9 | SPL | 8-K | 10.1 | 8/11/2014 | ||||||||||||||||||||||||||||
| 10.10 | SPL | 10-K | 10.14 | 2/24/2017 | ||||||||||||||||||||||||||||
| 10.11 | SPL | 10-Q | 10.1 | 5/9/2019 | ||||||||||||||||||||||||||||
63
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.12 | SPL | 8-K | 10.1 | 12/9/2020 | ||||||||||||||||||||||||||||
| 10.13 | SPL | 10-Q | 10.2 | 8/5/2021 | ||||||||||||||||||||||||||||
| 10.14 | SPL | 10-Q | 10.3 | 8/5/2021 | ||||||||||||||||||||||||||||
| 10.15 | SPL | 10-Q | 10.3 | 11/4/2021 | ||||||||||||||||||||||||||||
| 10.16 | SPL | 8-K | 10.1 | 11/26/2021 | ||||||||||||||||||||||||||||
| 10.17 | CQP | 8-K | 10.6 | 5/15/2012 | ||||||||||||||||||||||||||||
| 10.18 | SPL | 10-Q/A | 10.8 | 11/9/2015 | ||||||||||||||||||||||||||||
| 10.19 | CQP | 8-K | 10.5 | 5/15/2012 | ||||||||||||||||||||||||||||
| 10.20 | Cheniere Holdings | S-1/A | 10.76 | 12/2/2013 | ||||||||||||||||||||||||||||
| 10.21 | SPL | 10-Q/A | 10.7 | 11/9/2015 | ||||||||||||||||||||||||||||
| 10.22 | SPL | 8-K | 10.1 | 11/9/2018 | ||||||||||||||||||||||||||||
| 10.23 | SPL | 10-Q | 10.3 | 8/8/2019 | ||||||||||||||||||||||||||||
64
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.24 | SPL | 10-Q | 10.1 | 11/1/2019 | ||||||||||||||||||||||||||||
| 10.25 | SPL | 10-K | 10.23 | 2/24/2020 | ||||||||||||||||||||||||||||
| 10.26 | SPL | 10-Q | 10.4 | 4/30/2020 | ||||||||||||||||||||||||||||
| 10.27 | SPL | 10-Q | 10.2 | 8/6/2020 | ||||||||||||||||||||||||||||
65
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.28 | SPL | 10-Q | 10.1 | 11/6/2020 | ||||||||||||||||||||||||||||
| 10.29 | SPL | 10-K | 10.26 | 2/24/2021 | ||||||||||||||||||||||||||||
| 10.30 | SPL | 10-Q | 10.1 | 5/4/2021 | ||||||||||||||||||||||||||||
66
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.31 | SPL | 10-Q | 10.1 | 8/5/2021 | ||||||||||||||||||||||||||||
| 10.32 | SPL | 10-Q | 10.1 | 11/4/2021 | ||||||||||||||||||||||||||||
| 10.33* | Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the Company and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00054 80 Acres Bridge Credit, dated November 30, 2021, (ii) CO-00055 Change in Law LPDES Permit - Water Treatment Filter Washing, dated December15, 2021, (iii) CO-00056 Impacts from Hurricane Ida, dated December 15, 2021 and (iv) CO-00057 Impacts from Hurricane Nicholas, dated December 15, 2021 | |||||||||||||||||||||||||||||||
| 10.34 | SPLNG | 8-K | 10.1 | 8/6/2012 | ||||||||||||||||||||||||||||
| 10.35 | SPLNG | 10-Q | 10.1 | 8/2/2013 | ||||||||||||||||||||||||||||
| 10.36 | SPL | 8-K | 10.2 | 3/23/2020 | ||||||||||||||||||||||||||||
| 10.37 | SPL | 10-Q | 10.2 | 11/4/2021 | ||||||||||||||||||||||||||||
| 10.38 | SPL | 8-K | 10.1 | 3/23/2020 | ||||||||||||||||||||||||||||
67
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.39 | SPL | 8-K | 10.3 | 3/23/2020 | ||||||||||||||||||||||||||||
| 10.40 | SPL | S-4 | 10.30 | 11/15/2013 | ||||||||||||||||||||||||||||
| 31.1* | ||||||||||||||||||||||||||||||||
| 31.2* | ||||||||||||||||||||||||||||||||
| 32.1** | ||||||||||||||||||||||||||||||||
| 32.2** | ||||||||||||||||||||||||||||||||
| 101.INS* | XBRL Instance Document | |||||||||||||||||||||||||||||||
| 101.SCH* | XBRL Taxonomy Extension Schema Document | |||||||||||||||||||||||||||||||
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document | |||||||||||||||||||||||||||||||
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document | |||||||||||||||||||||||||||||||
| 101.LAB* | XBRL Taxonomy Extension Labels Linkbase Document | |||||||||||||||||||||||||||||||
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document | |||||||||||||||||||||||||||||||
| 104* | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |||||||||||||||||||||||||||||||
| (1) | Exhibits are incorporated by reference to reports of Cheniere (SEC File No. 001-16383), CQP (SEC File No. 001-33366), Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (SEC File No. 333-191298), SPL (SEC File No. 333-192373) and SPLNG (SEC File No. 333-138916), as applicable, unless otherwise indicated. | ||||
| * | Filed herewith. | ||||
| ** | Furnished herewith. | ||||
ITEM 16. FORM 10-K SUMMARY
None.
68
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| SABINE PASS LIQUEFACTION, LLC | |||||||||||
| By: | /s/ Jack A. Fusco | ||||||||||
| Jack A. Fusco | |||||||||||
| Chief Executive Officer (Principal Executive Officer) | |||||||||||
| Date: | February | ||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | ||||||
| /s/ Aaron Stephenson | Manager and President | February 23, 2022 | ||||||
| Aaron Stephenson | ||||||||
| /s/ | ||||||||
| Manager and Chief Financial Officer (Principal Financial Officer) | February | |||||||
| /s/ Leonard E. Travis | Chief Accounting Officer (Principal Accounting Officer) | February | ||||||
| Leonard E. Travis | ||||||||
| /s/ Scott Peak | Manager | February 23, 2022 | ||||||
| Scott Peak | ||||||||
69