EDGAR 10-K Filing

Company CIK: 1693317
Filing Year: 2024
Filename: 1693317_10-K_2024_0001693317-24-000004.json

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ITEM 1. BUSINESS
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
We are a Delaware limited liability company formed by Cheniere. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.
LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking, other industrial uses and back up for intermittent energy sources. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.
We own and operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through CCL, which has natural gas liquefaction facilities consisting of three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. We are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. We also own and operate through CCP a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, storage tanks, and marine berths at the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “Liquefaction Project”).
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted most of our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and IPM agreements, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project with approximately 17 years of weighted average remaining life as of December 31, 2023, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.
We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold a significant land position at the Corpus Christi LNG Terminal, which provides opportunity for further liquefaction capacity expansion. In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the Natural Gas Act (the “NGA”) for an expansion adjacent to the Liquefaction Project consisting of two midscale Trains with an expected total production capacity of approximately 3 mtpa of LNG (the “Midscale Trains 8 & 9 Project”). The development of the Midscale Trains 8 & 9 Project or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.
Our Business Strategy
Our primary business strategy is to develop, construct and operate assets to meet our long-term customers’ energy demands. We plan to implement our strategy by:
•safely, efficiently and reliably operating and maintaining our assets, including our Trains;
•procuring natural gas and pipeline transport capacity to our facility;
•commencing commercial delivery for our long-term SPA customers, of which we have initiated for 14 of 15 third party long-term SPA customers as of December 31, 2023;
•completing our construction projects safely, on-time and on-budget;
•maximizing the production of LNG to serve our customers and generating steady and stable revenues and operating cash flows;
•further expanding and/or optimizing the Liquefaction Project by leveraging existing infrastructure;
•maintaining a prudent and cost-effective capital structure; and
•strategically identifying actionable and economic environmental solutions.
Our Business
Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Liquefaction Project and Expansion Projects
The Liquefaction Project, as described above under the caption General, includes three Trains, three storage tanks, two marine berths and the construction of the Corpus Christi Stage 3 Project with seven midscale Trains. Additionally, in March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for the Midscale Trains 8 & 9 Project.
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:
Overall project completion percentage 51.4%
Completion percentage of:
Engineering 83.7%
Procurement 72.2%
Subcontract work 66.9%
Construction 11.1%
Date of expected substantial completion 2Q/3Q 2025 - 2H 2026
The following summarizes the volumes of natural gas for which we have received approvals from FERC to site, construct and operate the Trains at the Liquefaction Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG Terminal through December 31, 2050:
FERC Approved Volume DOE Approved Volume
(in Bcf/yr) (in mtpa) (in Bcf/yr) (in mtpa)
Trains 1 through 3 of the Liquefaction Project:
FTA countries 875.16 17 875.16 17
Non-FTA countries 875.16 17 875.16 17
Corpus Christi Stage 3 Project:
FTA countries 582.14 11.45 582.14 11.45
Non-FTA countries 582.14 11.45 582.14 11.45
Natural Gas Supply, Transportation and Storage
CCL has secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including IPM agreements. Additionally, to ensure that CCL is able to transport and manage the natural gas feedstock to the Liquefaction Project, it has entered into agreements to secure firm pipeline transportation and storage capacity from third parties and CCP.
Customers
The concentration of our customer credit risk in excess of 10% of total revenues was as follows:
Percentage of Total Revenues from External Customers
Year Ended December 31,
2023 2022 2021
Endesa Generación, S.A. (which subsequently assigned its SPA to Endesa S.A.) and Endesa S.A.
22% 21% 21%
PT Pertamina (Persero)
15% 14% 16%
Naturgy LNG GOM, Limited
14% 14% 15%
Trafigura Pte Ltd and affiliates
* 10% *
* Less than 10%
All of the above customers contribute to our LNG revenues through SPA contracts.
Additional information regarding our customer contracts can be found in Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 15-Customer Concentration of our Notes to Consolidated Financial Statements.
Governmental Regulation
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.
Federal Energy Regulatory Commission
The design, construction, operation, maintenance and expansion of the Liquefaction Project, the export of LNG and the purchase and transportation of natural gas in interstate commerce through the Corpus Christi Pipeline are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.
The FERC’s authority to regulate interstate natural gas pipelines and the services that they provide generally includes regulation of:
•rates and charges, and terms and conditions for natural gas transportation, storage and related services;
•the certification and construction of new facilities and modification of existing facilities;
•the extension and abandonment of services and facilities;
•the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;
•the acquisition and disposition of facilities;
•the initiation and discontinuation of services; and
•various other matters.
Under the NGA, our pipeline is not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including its own marketing affiliate. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified the FERC’s policy in this area expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area. On February 18, 2022, the FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for the FERC’s decision-making process, modifying the standards that the FERC uses to evaluate applications to include, among other things, reasonably foreseeable greenhouse gas (“GHG”) emissions that may be attributable to the project and the project’s impact on environmental justice communities. On March 24, 2022, the FERC rescinded the Policy Statement, re-issued it as a draft and it remains pending. At this time, we do not expect it to have a material adverse effect on our operations.
We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate granted by the FERC with the issuance of our Certificate of Public Convenience and Necessity to our marketing affiliates. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.
In order to site, construct and operate the Liquefaction Project, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law.
In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for Midscale Trains 8 & 9 Project.
The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. The general principles of the FERC Standards of Conduct are: (1) independent functioning, which requires transmission function employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue preference due to the improper disclosure of non-public transmission function information. We have established the required policies, procedures and training to comply with the FERC’s Standards of Conduct.
All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other governmental and regulatory approvals and permits are required throughout the life of the Liquefaction Project. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of the Liquefaction Project. For example, throughout the life of the Liquefaction Project, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations has not materially affected our construction or operations.
DOE Export Licenses
The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG Terminal, as discussed in Liquefaction Project and Expansion Projects. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.
Under Section 3 of the NGA, applications for exports of natural gas to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. The Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. See Liquefaction Project and Expansion Projects section above for FERC and DOE approved volumes on our existing Liquefaction Project.
Pipeline and Hazardous Materials Safety Administration
The Liquefaction Project is subject to regulation by PHMSA, who is authorized by the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation, maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.
PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $266,000 per day per violation, with a maximum administrative civil penalty of approximately $2.7 million for any related series of violations.
Other Governmental Permits, Approvals and Authorizations
Construction and operation of the Liquefaction Project requires additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security, the Texas Commission on Environmental Quality (“TCEQ”) and the Railroad Commission of Texas.
The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10). The EPA administers the Clean Air Act (“CAA”) and has delegated authority to the TCEQ to issue the Title V Operating Permit and the Prevention of Significant Deterioration Permit. These two permits are issued by the TCEQ.
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 those markets. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, including the speculative position limit rules. Given the enactment of the speculative position limit rules, as well as the impact of other rules and regulations under the Dodd-Frank Act, the impact of such rules and regulations on our business continues to be uncertain, but is not expected to be material.
As required by the Dodd-Frank Act, the CFTC and federal banking regulators also adopted rules requiring swap dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation
margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We qualify as 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 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 can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
Clean Air Act
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. However, we do not believe any such requirements will have a material adverse effect on our operations or the construction of our Liquefaction Project.
On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that the construction and operations of our Liquefaction Project will be materially and adversely affected by such regulatory actions.
We are supportive of regulations reducing GHG emissions over time. Since 2009, the EPA has promulgated and finalized multiple GHG emissions regulations related to reporting and reductions of GHG emissions from our facilities. On December 2, 2023, the EPA issued final rules to reduce methane and volatile organic compounds (“VOC”) emissions from new, existing and modified emissions sources in the oil and gas sector. These regulations will require monitoring of methane and VOC emissions at our compressor stations. We do not believe such regulations will have a material adverse effect on our operations, financial condition, or results of operations.
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. On August 16, 2022, President Biden signed H.R. 5376(P.L. 117-169), the Inflation Reduction Act of 2022 (“IRA”) which includes a charge on methane emissions above a certain methane intensity threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program Part 98 regulations. The charge starts at $900 per metric ton of methane in 2024, $1,200 per metric ton in 2025, and increasing to $1,500 per metric ton in 2026 and beyond. In January 2024, the EPA issued a proposed rule to impose and collect the methane emissions charge authorized under the IRA. We do not believe the methane charge to have a material adverse effect on our operations, financial condition or results of operations.
Coastal Zone Management Act (“CZMA”)
The siting and construction of the Liquefaction Project within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in 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
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 Texas, by the TCEQ). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.
Resource Conservation and Recovery Act (“RCRA”)
The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.
Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act, the 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 our Liquefaction Project adversely affects a protected species or its habitat, we may be required to develop and follow a plan to avoid those impacts. In that case, siting, construction or operation may be delayed or restricted and cause us to incur increased costs.
It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe such regulatory actions will have a material adverse effect on our operations or the construction of our Liquefaction Project.
Market Factors and Competition
Market Factors
Our ability to enter into additional long-term SPAs to underpin the development of additional Trains or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the extent of energy security needs in the European Union and elsewhere, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and other overarching factors such as global economic growth and the pace of any transition from fossil-based systems of energy production and consumption to alternative energy sources. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.
We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Market participants 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, Asia and Latin America in natural gas projects under construction, and more continues to be earmarked to planned projects globally. In Europe, there are various plans to install more than 85 mtpa of import capacity over the near-term to secure access to LNG and displace Russian gas imports. In India, there are more than 11,000 kilometers of gas pipelines under construction to expand the gas distribution network and increase access to natural gas. And in China, billions of U.S. dollars have already been invested and hundreds of
billions of U.S. dollars are expected to be further invested all along the natural gas value chain to enable growth and decrease harmful emissions. Furthermore, some of the existing integrated liquefaction facilities outside of the U.S. have been experiencing issues related to reduced feed gas as a result of depleting upstream resources. Global supply contributions from these plants have been decreasing and LNG supply growth is expected to help support these shortages.
As a result of these dynamics, we expect natural gas and LNG to continue to play an important role in satisfying energy demand going forward. In its forecast published in the third quarter of 2023, Wood Mackenzie Limited (“WoodMac”) forecasted that global demand for LNG would increase by approximately 60%, from approximately 411 mtpa, or 19.7 Tcf, in 2022, to 657 mtpa, or 31.5 Tcf, in 2040 and to 709 mtpa or 34 Tcf in 2050. In its forecast published in the third quarter of 2023, WoodMac also forecasted LNG production from existing operational facilities and new facilities already under construction would be able to supply the market with approximately 544 mtpa in 2040, declining to 477 mtpa in 2050. This could result in a market need for construction of an additional approximately 113 mtpa of LNG production by 2040 and about 231 mtpa by 2050. As a cleaner burning fuel with lower emissions than coal or liquid fuels in power generation, we expect natural gas and LNG to play a central role in balancing grids, serving as back up for intermittent energy sources and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project, as well as our proposed expansion is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.
We have limited exposure to oil price movements as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements indexed to Henry Hub. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes. Through our SPAs and IPM agreements, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project, with approximately 17 years of weighted average remaining life as of December 31, 2023. Customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes.
Competition
Despite the long term nature of our SPAs, when CCL needs to replace or amend any existing SPA or enter into new SPAs, CCL will compete on the basis of price per contracted volume of LNG with other natural gas liquefaction projects throughout the world, including our affiliate Sabine Pass Liquefaction, LLC (“SPL”), which operates six Trains at a natural gas liquefaction facility in Cameron Parish, Louisiana (the “SPL Project”). Revenues associated with any incremental volumes of the Liquefaction Project, including those made available to Cheniere Marketing, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to LNG markets than us.
Corporate Responsibility
As described in Market Factors and Competition, we expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Our vision is to provide clean, secure and affordable energy to the world. This vision underpins our focus on responding to the world’s shared energy challenges-expanding the global supply of clean, secure and affordable energy, improving air quality, reducing emissions and supporting the transition to a lower-carbon future. Our approach to corporate responsibility is guided by our Climate and Sustainability Principles: Transparency, Science, Supply Chain and Operational Excellence. In August 2023, Cheniere published The Power of Connection, its fourth Corporate Responsibility (“CR”) report, which details Cheniere’s approach and progress on ESG matters. Cheniere’s CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information on Cheniere’s website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K.
Cheniere’s climate strategy is to measure and mitigate emissions - to better position our LNG supplies to remain competitive in a lower carbon future, providing energy, economic and environmental security to our customers across the world. To maximize the environmental benefits of our LNG, we believe it is important to develop future climate goals and strategies based on an accurate and holistic assessment of the emissions profile of our LNG, accounting for all steps in the supply chain.
Consequently, Cheniere has collaborated with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, quantification, monitoring, reporting and verification (“QMRV”) of GHG emissions and other research and development projects. Cheniere also co-founded and sponsored the Energy Emissions Modeling and Data Lab (“EEMDL”), a multidisciplinary research and education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition, Cheniere commenced providing Cargo Emissions Tags (“CE Tags”) to its long-term customers in June 2022, and in October 2022 joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative.
Our total incremental expenditures related to climate initiatives, including capital expenditures, were not material to our Consolidated Financial Statements during the years ended December 31, 2023, 2022 and 2021. However, as governments consider and implement actions to reduce GHG emissions and the transition to a lower-carbon economy continues to evolve, as described in Market Factors and Competition, we expect the scope and extent of our future climate and sustainability initiatives to evolve accordingly. While we have not incurred material direct expenditures related to climate change, we are proactive in our management of climate risks and opportunities, including compliance with existing and future government regulations. We face certain business and operational risks associated with physical impacts from climate change, such as exposure to severe weather events or changes in weather patterns, in addition to transition risks. Please see Item 1A. Risk Factors for additional discussion.
Subsidiaries
Substantially all of our assets are held by our subsidiaries. We conduct most of our business through these subsidiaries, including the operation of our Liquefaction Project.
Employees
We have no employees. We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. See Note 13-Related Party Transactions of our Notes to Consolidated Financial Statements for a discussion of such services agreements with our affiliate entities. As of December 31, 2023, Cheniere and its subsidiaries had 1,605 full-time employees, including 412 employees who directly supported the Liquefaction Project.
Available Information
Our principal executive offices are located at 845 Texas Avenue, Suite 1250, 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”). These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
The following are some of the important risk factors that could adversely affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
•Risks Relating to Our Financial Matters;
•Risks Relating to Our Operations and Industry; and
•Risks Relating to Regulations.
Risks Relating to Our Financial Matters
An inability to source capital to supplement our available cash resources and existing credit facilities 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, 2023, we had $175 million of restricted cash and cash equivalents, $4.6 billion of available commitments under our credit facilities and $6.4 billion of total debt outstanding on a consolidated basis (before unamortized discount and debt issuance costs). We incur significant interest expense relating to financing the assets at the Corpus Christi LNG Terminal and we anticipate incurring additional debt and debt related interest expense to finance the construction of the Corpus Christi Stage 3 Project as well as the Midscale Trains 8 & 9 Project if a positive FID is made. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing and the debt 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, lending institutions’ evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.
Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations for any reason.
Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2023, we had SPAs with a total of 15 different third party customers.
While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk 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 fail 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 history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.
Our efforts to manage commodity and financial risks through derivative instruments, including our IPM agreements, could adversely affect our earnings reported under GAAP and our liquidity.
We use derivative instruments to manage commodity, currency and financial market risks. The extent of our derivative position at any given time depends on our assessments of the markets for these commodities and related exposures. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, as described in Note 2-Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net loss for the years ended December 31, 2022 and 2021 included $4.9 billion and $4.2 billion, respectively, of losses resulting from changes in the fair values of our derivatives, of which substantially all of such losses were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements.
These transactions and other derivative transactions have and may continue to result in substantial volatility in results of operations reported under GAAP, particularly in periods of significant commodity, currency or financial market variability. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
In addition, our liquidity may be adversely impacted by the cash margin requirements of the commodities exchanges or the failure of a counterparty to perform in accordance with a contract. As of December 31, 2023 and 2022, we had collateral posted with counterparties by us of $3 million and $76 million, respectively, which are included in margin deposits in our Consolidated Balance Sheets.
Risks Relating to Our Operations and Industry
Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us.
Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our Liquefaction Project. In August 2020, we entered into an arrangement with our affiliate to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers from the other facility in the event operational conditions impact operations at the Corpus Christi LNG Terminal or at our affiliate’s terminal. During the year ended December 31, 2021, four TBtu was loaded at our facilities for our affiliate pursuant to this agreement. Our risk of loss related to weather events or other disasters is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our Consolidated Financial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. However, future adverse weather events and collateral effects or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or interruption of operations at our terminal or related infrastructure, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of the Liquefaction Project or our other facilities. Our LNG terminal infrastructure and LNG facility located in or near Corpus Christi, Texas are designed in accordance with requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.
Disruptions to the third party supply of natural gas to our pipeline and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We depend upon third party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted. Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the risk factor Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of natural gas to our pipeline and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our ability to complete development and/or construction of additional Trains, including the Midscale Trains 8 & 9 Project, will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.
We continuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. As described further in Items 1. and 2. Business and Properties, we are currently developing the Midscale Trains 8 & 9 Project. The commercial development of an LNG facility takes a number of years and requires a substantial capital investment that is dependent on sufficient funding and commercial interest, among other factors.
We will require significant additional funding to be able to commence construction of the Midscale Trains 8 & 9 Project, or any additional expansion projects, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development or construction of the Midscale Trains 8 & 9 Project, any additional Trains or any additional expansion projects, and we may not be able to complete our business plan, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Cost overruns and delays in the completion of our expansion projects, including the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our investment decision on the Corpus Christi Stage 3 Project and any potential future expansion of LNG facilities relies on cost estimates developed initially through front end engineering and design studies. However, due to the size and duration of construction of an LNG facility, the actual construction costs may be significantly higher than our current estimates as a result of many factors, including but not limited to changes in scope, the ability of Bechtel Energy Inc. (“Bechtel”) and our other contractors to execute successfully under their agreements, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules or comply with existing or future environmental or other regulations. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations. Additionally, our SPAs generally provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Significant increases in the cost of a liquefaction project beyond the amounts that we estimate could impact the commercial viability of the project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects. While historically we have not experienced cost overruns or construction delays
that have had a significant adverse impact on our operations, factors giving rise to such events in the future may be outside of our control and could have a material adverse effect on our current or future 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 are, and will be, subject to the inherent risks associated with these types of operations as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. Although losses incurred as a result of self insured risk have not been material historically, the occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are dependent on our EPC partners and other contractors for the successful completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project.
Timely and cost-effective completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our EPC partners, including Bechtel, and our other contractors under their agreements. The ability of our EPC partners and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
•design and engineer each Train to operate in accordance with specifications;
•engage and retain third party subcontractors and procure equipment and supplies;
•respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
•attract, develop and retain skilled personnel, including engineers;
•post required construction bonds and comply with the terms thereof;
•manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
•maintain their own financial condition, including adequate working capital.
Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of EPC partners and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.
Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project, or result in a contractor’s unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a
substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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 flow, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;
•reduced demand and lower prices for natural gas;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
•cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources, 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 customer regions;
•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
•adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect our business and the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Failure of exported LNG to be a long term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Project are dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from the United States 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 or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to
import LNG from the United States. Furthermore, some foreign purchasers or 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.
As described in Market Factors and Competition, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to alternative fossil fuel energy sources such as oil and coal. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy as such alternative sources emerge. Additionally, LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.
As described in Market Factors and Competition, we have contracted through our SPAs and IPM agreements approximately 90% of the total anticipated production from the Liquefaction Project with approximately 17 years of weighted average remaining life as of December 31, 2023, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. However, as a result of the factors described above and other factors, the LNG we produce may not remain a long term competitive source of energy internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG from the United States 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.
Our Liquefaction Project is subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our Liquefaction Project are diverse and include, among others:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to our Liquefaction Project;
•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
•increases in capacity and utilization of nuclear power and related facilities; and
•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Project, could negatively impact our 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 pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our pipeline and liquefaction 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 cyber attack involving our business or operational control systems or related infrastructure, or that of third party pipelines with which we do business, could negatively impact our 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.
Outbreaks of infectious diseases, such as COVID-19, at our facilities could adversely affect our operations.
Our facilities at the Corpus Christi LNG Terminal are critical infrastructure and 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 subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases 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 its current form, the outbreak of a more potent variant or another infectious disease in the future at one or more of our facilities could adversely affect our operations.
We are entirely dependent on Cheniere for key personnel, and the unavailability of skilled workers or Cheniere’s failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.
As of December 31, 2023, Cheniere and its subsidiaries had 1,605 full-time employees, including 412 employees who directly supported the Liquefaction Project. We have contracted with subsidiaries of Cheniere to provide the personnel necessary for the construction and operation of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is operating, including the SPL Project, for the time and expertise of Cheniere’s personnel. Further, Cheniere faces competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.
Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our ability to engage, and Cheniere’s ability to attract and retain, additional qualified personnel.
A shortage in the labor pool of skilled workers, remoteness of our site locations, general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of Cheniere’s affiliates. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, SPL is currently operating the SPL Project and its affiliates are developing an expansion project adjacent to the SPL Project. Cheniere and its affiliates have entered into fixed price SPAs with third parties for the sale of LNG from the SPL Project and the adjacent expansion project, and may continue to enter into commercial arrangements with respect to this liquefaction facility that might otherwise have been entered into with respect to any of our future Trains.
We have or will have numerous contracts and commercial arrangements with Cheniere and 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.
Risks Relating to Regulations
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, and operation of our pipeline and the export of LNG could impede operations and construction and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The design, construction and operation of interstate natural gas pipelines, our LNG terminal, including the Liquefaction Project, the Midscale Trains 8 & 9 Project and other facilities, as well as the export of LNG are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.
To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the three Trains and related facilities of the Liquefaction Project, as well as the seven midscale Trains and related facilities for the Corpus Christi Stage 3 Project. Additionally, the FERC has issued orders under Section 7 of the NGA authorizing the construction and operation of the Corpus Christi Pipeline. In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for Midscale Trains 8 & 9 Project. To date, the DOE has also issued orders under Section 4 of the NGA authorizing CCL to export domestically produced LNG. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. The Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipeline on land owned by third parties. If we were to lose these rights or be required to relocate our pipeline, our business could be materially and adversely affected.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with or our inability to obtain and maintain existing or newly imposed approvals, permits and filings that 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 our operations could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our Corpus Christi Pipeline and its FERC gas tariff are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.
The Corpus Christi Pipeline is subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and the abandonment of facilities. Under the NGA, the rates charged by our Corpus Christi Pipeline must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any potential shipper with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our Corpus Christi Pipeline could be subject to substantial penalties and fines.
In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.5 million per day for each violation.
Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.
Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources, and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our terminal, marine berths and pipeline, including FERC, PHMSA, EPA and the United States Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, difficulty obtaining and maintaining permits from regulatory agencies or increased 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.
The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. On December 2, 2023, the EPA issued final rules to reduce methane and VOC emissions from new, existing and modified emission sources in the oil and gas sector. These regulations will require monitoring of methane and VOC emissions at our compressor stations. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that will apply to our facilities beginning in calendar year 2024. In January 2024, the EPA issued a proposed rule to impose and collect methane emissions charges authorized under the IRA. In addition, other international, federal and state initiatives may be considered in the future to address GHG emissions through treaty commitments, direct regulation, market-based regulations such as a GHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.
Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.
On February 28, 2022, the EPA removed a stay of formaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.
Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Corpus Christi 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.
Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Consolidated Financial Statements for the years ended December 31, 2023, 2022 and 2021. Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction
costs or restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.
The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
•perform ongoing assessments of pipeline safety and compliance;
•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventative and mitigating actions.
We are required to utilize management programs that are intended to maintain pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines, which for certain violations can aggregate up to as high as $2.7 million.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
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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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Consolidated 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 2021 items and variance drivers between the year ended December 31, 2022 as compared to December 31, 2021 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, 2022.
Our discussion and analysis includes the following subjects:
•Overview
•Overview of Significant Events
•Market Environment
•Results of Operations
•Liquidity and Capital Resources
•Summary of Critical Accounting Estimates
•Recent Accounting Standards
Overview
We are a limited liability company formed by Cheniere to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We own the natural gas liquefaction and export facility located near Corpus Christi, Texas. 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. Through our SPAs and IPM agreements, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project with approximately 17 years of weighted average remaining life as of December 31, 2023. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. We believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our business in the future.
Overview of Significant Events
Our significant events since January 1, 2023 and through the filing date of this Form 10-K include the following:
Strategic
•In April 2023, CCL and certain subsidiaries of Cheniere filed an application with the DOE with respect to the Midscale Trains 8 & 9 Project, requesting authorization to export LNG to FTA countries and non-FTA countries. In July 2023, we received authorization from the DOE to export LNG to FTA countries.
•In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for the Midscale Trains 8 & 9 Project.
Operational
•As of February 16, 2024, approximately 870 cumulative LNG cargoes totaling approximately 60 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
Financial
•We received the following upgrades from credit rating agencies, including S&P Global Ratings (“S&P”), Moody’s Investor Service (“Moody’s”) and Fitch Ratings (“Fitch”), each with a stable outlook:
Date Previous Rating Upgraded Rating Rating Agency
October 2023 BBB- BBB S&P
August 2023 Baa3 Baa2 Moody’s
July 2023 BBB- BBB Fitch
•In January 2023, we prepaid with cash on hand the remaining $498 million outstanding principal amount of our 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”).
Market Environment
In 2023, the LNG market continued to rebalance with robust LNG flows to Europe maintaining the region’s underground storage inventories at high levels, and weak demand in Japan and Korea largely offsetting a modest rebound in China and other emerging economies in Asia. Price levels started moving towards pre-Russia-Ukraine war levels in the second quarter of 2023 and have for the most part normalized versus pre-war levels, as concerns about physical market tightness dissipated. However, extensive upstream maintenance in Norway and concerns about tight supply capacity amid strike threats in Australia elevated prices during the third quarter of 2023 and brought some volatility back to the market, albeit not at much lower levels than those seen in 2022. These conditions were quickly resolved, and winter prices remained within a more normal level, despite the eruption of military conflict in the Middle East in October.
The Dutch Title Transfer Facility (“TTF”) monthly settlement prices averaged $13.73/MMBtu in 2023, over 66% lower year-over-year and 4.6% lower than 2021. Similarly, the 2023 average settlement price for the Japan Korea Marker (“JKM”) decreased 53% year-over-year to an average of $16.13/MMBtu in 2023. Prices in the fourth quarter of 2023 also decreased, with TTF averaging $13.66/MMBtu and JKM $14.97/MMBtu - both significantly below levels seen in the previous two years. The Henry Hub benchmark also witnessed a similar year-over-year drop albeit from a much lower base. The Henry Hub average settlement price in 2023 was $2.74, down approximately 59% from $6.64/MMBtu in 2022 during the height of the energy crisis in Europe.
The U.S. played a significant role in balancing the global market in 2023, exporting approximately 86 million tonnes of LNG, a gain of approximately 13% from 2022, due in part to the return of Freeport LNG to operations. Exports from our Liquefaction Project reached 15 million tonnes in aggregate, representing over 17% of total U.S. exports for the year, according to Kpler data.
Global LNG demand grew by approximately 3% from 2022, adding 10.5 million tonnes to the overall market. Although overall Asian demand has increased from 2022, weakness in Japan, mainly due to improved nuclear availability, along with continued gas demand destruction in Europe, especially in the residential sector, exerted downward pressure on the market and
kept LNG and gas prices from increasing. Despite the decrease in Japanese demand, which was down approximately 8% or 6 mtpa year-over-year, Asia’s LNG imports increased roughly 4% year-over-year in 2023 to approximately 263 mtpa. This uptick was largely due to an approximately 8.4 mtpa year-over-year growth in South and Southeast Asia’s demand and a modest rebound in China’s economy, which resulted in approximately 12% or 7.5 mtpa increase in LNG imports into the country. In Europe, despite continued declines in gas demand, LNG imports were flat year-over-year as pipeline flows from Russia to the EU remained low at 27 billion cubic meters (“Bcm”), down 36 Bcm or 57% year-over-year.
The market dynamics brought on by the need to displace and replace Russian gas into Europe in 2023 resulted in a notable uptick in long-term LNG contracting and a push for LNG project FIDs. Commercial activity in 2023 continued to build on last year’s momentum with executed long-term SPAs in the U.S. reaching approximately 23 mtpa for the year, of which Cheniere’s SPAs and IPM agreements totaled approximately 6.5 mtpa. This contractual momentum over the past two years led to the positive FID of nearly 40 mtpa of U.S. LNG capacity in 2023.
Despite the global impacts of the Russia-Ukraine war, we do not believe we have significant exposure to adverse direct or indirect impacts of the war, as we do not conduct business in Russia and refrain from business dealings with Russian entities. Additionally, we are not aware of any specific adverse direct or indirect effects of the Russia-Ukraine war or the Israel-Hamas war on our supply chain. Consequently, we believe we are well positioned to help meet the increased demand of our international LNG customers to overcome their supply shortages.
Results of Operations
Year Ended December 31,
(in millions) 2023 2022 Variance
Revenues
LNG revenues $ 3,845 $ 6,336 $ (2,491)
LNG revenues-affiliate 1,620 3,027 (1,407)
Total revenues 5,465 9,363 (3,898)
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below) (3,178) 9,656 (12,834)
Cost of sales-affiliate 171 103 68
Operating and maintenance expense 479 458 21
Operating and maintenance expense-affiliate 116 121 (5)
Operating and maintenance expense-related party 9 9 -
General and administrative expense 6 8 (2)
General and administrative expense-affiliate 45 38 7
Depreciation and amortization expense 449 445 4
Other 2 6 (4)
Total operating costs and expenses (recoveries) (1,901) 10,844 (12,745)
Income (loss) from operations 7,366 (1,481) 8,847
Other income (expense)
Interest expense, net of capitalized interest (217) (432) 215
Loss on modification or extinguishment of debt (10) (37) 27
Other income, net 11 8 3
Total other expense (216) (461) 245
Net income (loss) $ 7,150 $ (1,942) $ 9,092
Volumes loaded and recognized from the Liquefaction Project
Year Ended December 31,
(in TBtu) 2023 2022 Variance
Volumes loaded during the current period 763 775 (12)
Volumes loaded during the prior period but recognized during the current period 3 - 3
Volumes loaded at our affiliate’s facility 5 - 5
Less: volumes loaded during the current period and in transit at the end of the period - (3) 3
Total volumes recognized in the current period 771 772 (1)
Net income (loss)
Substantially all of the favorable variance of $9.1 billion between the years ended December 31, 2023 and 2022 was attributable to favorable changes in fair value and settlements of derivatives of $9.1 billion between the periods, of which $7.7 billion related to non-cash favorable changes in fair value of our IPM agreements where we procure natural gas at a price indexed to international gas prices as a result of lower volatility in international gas prices and declines in international forward commodity curves.
The following is an additional discussion of the significant drivers of the variance in net income (loss) by line item:
Revenues
Substantially all of the $3.9 billion decrease between the years ended December 31, 2023 and 2022 was attributable to a $3.8 billion decrease from lower pricing per MMBtu as a result of decreased Henry Hub pricing.
Operating costs and expenses (recoveries)
The $12.7 billion favorable variance between the years ended December 31, 2023 and 2022, was primarily attributable to:
•$9.1 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from a $3.2 billion of loss in the year ended December 31, 2022 to a $5.8 billion of gain in the year ended December 31, 2023 primarily due to decreased international gas prices resulting in non-cash favorable changes in fair value of our commodity derivatives indexed to such prices and, to a lesser extent, an increase in forward notional amount of derivatives due to agreements contributed to us upon the merger of CCL Stage III with and into CCL in June 2022; and
•$3.7 billion decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of a $3.4 billion in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.
Other income (expense)
The $245 million decrease between the years ended December 31, 2023 and 2022 was primarily attributable to a $215 million decrease in interest expense, net of capitalized interest, between the years ended December 31, 2023 and 2022, as a result of lower debt balances due to repayment of debt, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources. Additionally, the decrease in interest expense, net of capitalized interest, between the years ended December 31, 2023 and 2022 was due to a higher portion of total interest costs eligible for capitalization following the issuance of full notice to proceed to Bechtel on the Corpus Christi Stage 3 Project in June 2022.
Significant factors affecting our results of operations
Below are significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risks and are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM
agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described Note 8-Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of our Liquefaction Supply Derivatives incorporates market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.
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. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
December 31, 2023
Restricted cash and cash equivalents designated for the Liquefaction Project
$ 175
Available commitments under our credit facilities (1):
Term loan facility agreement (the “CCH Credit Facility”)
3,260
Working capital facility agreement (the “CCH Working Capital Facility”)
1,345
Total available commitments under our credit facilities 4,605
Total available liquidity $ 4,780
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2023. See Note 11-Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.
Our liquidity position subsequent to December 31, 2023 will be driven by future sources of liquidity and future cash requirements as further discussed under the caption Future Sources and Uses of Liquidity.
Supplemental Guarantor Information
The 5.875% Senior Secured Notes due 2025, 5.125% Senior Secured Notes due 2027, 3.700% Senior Secured Notes due 2029 and the series of Senior Secured Notes due 2039 with weighted average rate of 3.788% (collectively, the “Senior Secured Notes”) are jointly and severally guaranteed by each of our consolidated subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “Guarantor” and collectively, the “Guarantors”).
The Guarantors’ guarantees are full and unconditional, subject to certain release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of all or substantially all of the capital stock or the assets of the Guarantors, (2) the designation of the Guarantor as an “unrestricted subsidiary” in accordance with the indentures governing the Senior Secured Notes (the “CCH Indentures”), (3) upon the legal defeasance or covenant defeasance or discharge of obligations under the CCH Indentures and (4) the release and discharge of the Guarantors pursuant to the Common Security and Account Agreement. In the event of a default in payment of the principal or interest by us, whether at maturity of the Senior Secured Notes or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the Guarantors to enforce the guarantee.
The rights of holders of the Senior Secured Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or federal or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a
fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
Summarized financial information about us and the Guarantors as a group is omitted herein because such information would not be materially different from our Consolidated Financial Statements.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:
Overall project completion percentage 51.4%
Completion percentage of:
Engineering 83.7%
Procurement 72.2%
Subcontract work 66.9%
Construction 11.1%
Date of expected substantial completion 2Q/3Q 2025 - 2H 2026
Future Sources and Uses of Liquidity
The following discussion of our future sources and uses of liquidity includes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2023. 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.
Future Sources of Liquidity under Executed SPAs
As described in 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. Substantially all of our future revenues are contracted under SPAs and because many of these contracts have long-term durations, we are contractually entitled to significant future consideration under these contracts 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 Consolidated Balance Sheets as of December 31, 2023. 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 SPAs as of December 31, 2023 (in billions):
Estimated Revenues Under Executed SPAs by Period (1) (2)
2024 2025 - 2028
Thereafter Total
LNG revenues (fixed fees) $ 2.1 $ 11.0 $ 37.4 $ 50.5
LNG revenues (variable fees) (2) 2.9 20.4 80.9 104.2
Total $ 5.0 $ 31.4 $ 118.3 $ 154.7
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the revenues above when the conditions are considered probable of being met.
(2)LNG revenues (including $1.0 billion and $28.7 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, in certain instances, 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, 2023. The pricing structure of many 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.
Through our SPAs and IPM agreements, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project, with approximately 17 years of weighted average remaining life as of December 31, 2023. The majority of the contracted capacity is comprised of fixed-price, long-term SPAs we have executed with third parties to sell LNG from the Liquefaction Project. Under the SPAs, the customers purchase LNG on either an FOB basis (delivered to the customer at the Corpus Christi LNG Terminal) or a DAT basis (delivered to the customer at their specified LNG receiving terminal) generally 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, transportation and liquefaction fuel consumed 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 $2.7 billion for the Liquefaction Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of BBB+, Baa1 and BBB+ by S&P, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 12-Revenues of our Notes to Consolidated Financial Statements.
In addition to the third party SPAs discussed above, CCL has executed agreements with Cheniere Marketing under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2023, we had $4.6 billion in available commitments under our credit facilities, subject to compliance with the covenants, to potentially meet liquidity needs. Our credit facilities mature between 2027 and 2029.
Financially Disciplined Growth
Our significant land position at the Corpus Christi LNG Terminal provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for Midscale Trains 8 & 9 Project. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.
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 related to our core operations under executed contracts as of December 31, 2023 (in billions):
Estimated Payments Due Under Executed Contracts by Period (1)
2024 2025 - 2028
Thereafter Total
Purchase obligations (2):
Natural gas supply agreements (3) $ 2.2 $ 10.2 $ 20.2 $ 32.6
Natural gas transportation and storage service agreements (4) 0.2 1.0 2.8 4.0
Capital expenditures 1.2 1.7 - 2.9
Other purchase obligations (5) 0.1 1.0 6.8 7.9
Total $ 3.7 $ 13.9 $ 29.8 $ 47.4
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023.
(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. We include contracts for which we have an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.
(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us.
(4)Includes $1.0 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements with unsatisfied contractual conditions.
(5)Includes $7.6 billion of purchase obligations to affiliates under services agreements, $6.4 billion of which relates to shipping and transportation-related services agreements with Cheniere Marketing.
Natural Gas Supply, Transportation and Storage Service Agreements
We have secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including IPM agreements. Under our IPM agreements, we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While our IPM agreements are not revenue contracts for accounting purposes, the payment structure for the purchase of natural gas under the IPM agreements generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global gas market price paid for the natural gas feedstock purchase.
As of December 31, 2023, we have secured approximately 92% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024. Natural gas supply is generally secured on an indexed pricing basis plus a fixed fee, 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 often 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. Inclusive of amounts under contracts with unsatisfied contractual conditions that are currently considered probable of being met and exclusive of extension options that were uncertain to be taken as of December 31, 2023, we have secured up to 7,625 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately 15 years. A discussion of our natural gas supply and IPM agreements can be found in Note 8-Derivative Instruments of our Notes to Consolidated Financial Statements.
To ensure that we are able to transport natural gas feedstock to the Corpus Christi LNG Terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from CCP and third party
interstate and intrastate 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 EPC of our Liquefaction Project. The future capital expenditures included in the table above primarily consist of fixed costs under the Bechtel EPC contract for the Corpus Christi Stage 3 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occurred, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity. See Financially Disciplined Growth section for further discussion.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:
Overall project completion percentage 51.4%
Completion percentage of:
Engineering 83.7%
Procurement 72.2%
Subcontract work 66.9%
Construction 11.1%
Date of expected substantial completion 2Q/3Q 2025 - 2H 2026
Additional Future Cash Requirements for Operations and Capital Expenditures
Operational Services
We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. As of December 31, 2023, Cheniere and its subsidiaries had 1,605 full-time employees, including 412 employees who directly supported the Liquefaction Project. Full discussion of our operations, maintenance and management agreements can be found in Note 13-Related Party Transactions of our Notes to Consolidated Financial Statements.
Financially Disciplined Growth
The FID of any expansion projects will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above. However, in connection with reaching FID, we may be required to secure financing to meet the cash needs that such project will initially require, in support of commercializing the project.
Beyond the Corpus Christi Stage 3 Project, our affiliates hold significant land positions at the Corpus Christi LNG Terminal, which provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources, including Midscale Trains 8 & 9 Project. We expect that any future expansion at the Corpus Christi LNG Terminal would increase cash requirements to support expanded operations, although expansion may 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, 2023 (in billions):
Estimated Payments Due Under Executed Contracts by Period (1)
2024 2025 - 2028
Thereafter Total
Debt $ - $ 2.9 $ 3.5 $ 6.4
Interest payments 0.4 0.8 0.6 1.8
Total $ 0.4 $ 3.7 $ 4.1 $ 8.2
(1)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, 2023. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.
Debt
As of December 31, 2023, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $6.4 billion and credit facilities with no outstanding loan balances. As of December 31, 2023, 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 11-Debt of our Notes to Consolidated Financial Statements.
Interest
As of December 31, 2023, our senior notes had a weighted average contractual interest rate of 4.52%. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.10% and 0.525%, subject to change based on our credit rating. Issued letters of credit under the CCH Working Capital Facility are subject to letter of credit fees of 1.125%. We had $155 million aggregate amount of issued letters of credit under the CCH Working Capital Facility as of December 31, 2023.
Additional Future Cash Requirements for Financing
Capital Allocation Plan
In September 2022, the board of directors of Cheniere approved a revised long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including our senior notes.
Sources and Uses of Cash
The following table summarizes the sources and uses of our restricted cash and cash equivalents (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,
2023 2022
Net cash provided by operating activities $ 1,765 $ 1,734
Net cash used in investing activities (1,722) (980)
Net cash used in financing activities (606) (60)
Net increase (decrease) in restricted cash and cash equivalents $ (563) $ 694
Operating Cash Flows
Operating cash flows between the years ended December 31, 2023 and 2022 remained relatively flat due to lower cash receipts from the sale of LNG cargoes from lower pricing per MMBtu as a result of decreased Henry Hub pricing, which was largely offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.
Investing Cash Flows
Our investing net cash outflows in both years primarily were for the construction costs for the Liquefaction Project. The $742 million increase in 2023 compared to 2022 was primarily due to $1.5 billion of cash outflows during the year ended December 31, 2023 related to construction of the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 2022 compared to $880 million in the comparable period of 2022. We expect to incur a similar level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project.
Financing Cash Flows
The following table summarizes our financing activities (in millions):
Year Ended December 31,
2023 2022
Proceeds from issuances of debt $ - $ 440
Repayments of debt (498) (2,419)
Contributions 180 2,182
Distributions (280) (200)
Other (8) (63)
Net cash used in financing activities $ (606) $ (60)
Debt Issuances and Related Financing Costs
During the year ended December 31, 2022, we had $440 million of debt issuances from the CCH Credit Facility. We did not have any debt issuances during the year ended December 31, 2023.
Repayments and Related Extinguishment Costs
The following table shows the repayments of debt, including intra-year repayments (in millions):
Year Ended December 31,
2023 2022
CCH Credit Facility
$ - $ (2,169)
CCH Working Capital Facility
- (250)
2024 CCH Senior Notes (498) -
Total repayments of debt $ (498) $ (2,419)
Capital Contributions and Distributions
During the years ended December 31, 2023 and 2022, we received cash capital contributions of $180 million and $2.2 billion, respectively, from Cheniere, used to fund working capital and in 2022 to primarily pay down our outstanding debt, and during the years ended December 31, 2023 and 2022, we made cash distributions of $280 million and $200 million, respectively, to Cheniere.
Summary of Critical Accounting Estimates
The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.
Fair Value of Level 3 Physical Liquefaction Supply Derivatives
All of our derivative instruments are recorded at fair value, as described in Note 2-Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. 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. Valuation of our physical liquefaction supply derivative contracts is often developed through the use of internal models which includes significant unobservable inputs representing Level 3 fair value measurements as further described in Note 2-Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.
Our fair value estimates incorporate market participant-based assumptions pertaining to applicable contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.
Additionally, the valuation of certain physical liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2023 and 2022 (in millions), which entirely consisted of physical liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.
Year Ended December 31,
2023 2022
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period
$ 4,382 $ (3,664)
The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our IPM agreements during the years ended December 31, 2023 and 2022.
The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2023 and 2022 amounted to a liability of $0.5 billion and $6.2 billion, respectively, consisting entirely of physical liquefaction supply derivatives.
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 it relates to commodity prices given the level of volatility in the current year. See Item 7A. Quantitative and Qualitative Disclosures About 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 a summary of recently issued accounting standards, see Note 2-Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
CCL has commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (the “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, 2023 December 31, 2022
Fair Value Change in Fair Value Fair Value Change in Fair Value
Liquefaction Supply Derivatives
$ (460) $ 1,165 $ (6,278) $ 1,684
See Note 8-Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
Management’s Report to the Member of Cheniere Corpus Christi Holdings, LLC
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Balance Sheets
Consolidated Statements of Member’s Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Note 1-Organization and Nature of Operations
Note 2-Summary of Significant Accounting Policies
Note 3-CCL Stage III Contribution and Merger
Note 4-Restricted Cash and Cash Equivalents
Note 5-Trade and Other Receivables, Net of Current Expected Credit Losses
Note 6-Inventory
Note 7-Property, Plant and Equipment, Net of Accumulated Depreciation
Note 8-Derivative Instruments
Note 9-Other Non-current Assets, Net
Note 10-Accrued Liabilities
Note 11-Debt
Note 12-Revenues
Note 13-Related Party Transactions
Note 14-Commitments and Contingencies
Note 15-Customer Concentration
Note 16-Supplemental Cash Flow Information
MANAGEMENT’S REPORT TO THE MEMBER OF CHENIERE CORPUS CHRISTI HOLDINGS, 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 Cheniere Corpus Christi Holdings, LLC (“Corpus Christi Holdings”). 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”). Corpus Christi Holdings’ 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 Corpus Christi Holdings maintained effective internal control over financial reporting as of December 31, 2023, based on criteria in Internal Control-Integrated Framework (2013) issued by the COSO.
This annual report does not include an attestation report of Corpus Christi Holdings’ registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Corpus Christi Holdings’ 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 Corpus Christi Holdings’ Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere Corpus Christi Holdings’ Form 10-K.
By: /s/ Zach Davis
Zach Davis
President and Chief Financial Officer
(Principal Executive and Financial Officer)
Report of Independent Registered Public Accounting Firm
To the Member and Managers of Cheniere Corpus Christi Holdings, LLC
Cheniere Corpus Christi Holdings, LLC:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Cheniere Corpus Christi Holdings, LLC and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated 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 liquefaction supply derivatives
As discussed in Notes 2 and 8 to the consolidated financial statements, the Company recorded fair value of level 3 liquefaction supply derivatives of $(502) million as of December 31, 2023, which included the fair value of IPM agreements. The IPM agreements are natural gas supply contracts for the operation of the liquefied natural gas facilities. The fair value of the IPM agreements is developed using internal models, including option pricing models. The models incorporate significant unobservable inputs, including future prices of energy units in unobservable periods and volatility.
We identified the evaluation of the fair value of the level 3 liquefaction supply derivatives for certain IPM agreements as a critical audit matter. Specifically, complex auditor judgment and specialized skills and knowledge were required to evaluate the appropriateness and application of the option pricing model as well as the assumptions for future prices of energy units in unobservable periods and volatility.
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 liquefaction supply derivatives,
including those under certain IPM agreements. This included controls related to the appropriateness and application of the option pricing model and the evaluation of assumptions for future prices of energy units in unobservable periods and volatility. We involved valuation professionals with specialized skills and knowledge who assisted in testing management’s process for developing the fair value of certain IPM agreements by:
•evaluating the design and testing the operating effectiveness of certain internal controls related to the appropriateness and application of the option pricing model
•evaluating the appropriateness and application of the option pricing model by inspecting the contractual agreements and model documentation to determine whether the model is suitable for its intended use
•evaluating the reasonableness of management’s assumptions for future prices of energy units in unobservable periods and volatility by comparing to market data.
/s/ KPMG LLP
KPMG LLP
We have served as the Company’s auditor since 2015.
Houston, Texas
February 21, 2024
CHENIERE CORPUS CHRISTI HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
Year Ended December 31,
2023 2022 2021
Revenues
LNG revenues $ 3,845 $ 6,336 $ 3,907
LNG revenues-affiliate 1,620 3,027 1,887
Total revenues 5,465 9,363 5,794
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below) (3,178) 9,656 4,326
Cost of sales-affiliate 171 103 50
Cost of sales-related party - - 146
Operating and maintenance expense 479 458 423
Operating and maintenance expense-affiliate 116 121 106
Operating and maintenance expense-related party 9 9 9
General and administrative expense 6 8 7
General and administrative expense-affiliate 45 38 28
Depreciation and amortization expense 449 445 420
Other 2 6 2
Total operating costs and expenses (recoveries) (1,901) 10,844 5,517
Income (loss) from operations 7,366 (1,481) 277
Other income (expense)
Interest expense, net of capitalized interest (217) (432) (447)
Loss on modification or extinguishment of debt (10) (37) (9)
Other income (expense), net 11 8 (1)
Total other expense (216) (461) (457)
Net income (loss) $ 7,150 $ (1,942) $ (180)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions)
December 31,
2023 2022
ASSETS
Current assets
Restricted cash and cash equivalents $ 175 $ 738
Trade and other receivables, net of current expected credit losses 180 348
Trade receivables-affiliate 213 240
Advances to affiliate 116 132
Inventory 124 178
Current derivative assets 19 12
Margin deposits 3 76
Other current assets, net 15 18
Total current assets 845 1,742
Property, plant and equipment, net of accumulated depreciation 14,992 13,673
Debt issuance costs, net of accumulated amortization 33 40
Derivative assets 823 7
Other non-current assets, net 283 225
Total assets $ 16,976 $ 15,687
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable $ 105 $ 85
Accrued liabilities 595 901
Accrued liabilities-related party 1 1
Current debt, net of discount and debt issuance costs - 495
Due to affiliates 49 43
Current derivative liabilities 455 1,374
Other current liabilities 20 1
Total current liabilities 1,225 2,900
Long-term debt, net of discount and debt issuance costs 6,311 6,698
Derivative liabilities 847 4,923
Other non-current liabilities 58 78
Other non-current liabilities-affiliate 3 4
Commitments and contingencies (see Note 14)
Member’s equity
8,532 1,084
Total liabilities and member’s equity
$ 16,976 $ 15,687
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(in millions)
Cheniere CCH HoldCo I, LLC Total Member’s Equity
Balance at December 31, 2020 $ 2,624 $ 2,624
Distributions (1,163) (1,163)
Net loss (180) (180)
Balance at December 31, 2021 1,281 1,281
Contributions (excluding items shown separately below)
2,182 2,182
Non-cash contribution of CCL Stage III entity from affiliate (see Note 3)
(1,482) (1,482)
Other non-cash contribution from affiliate (see Note 11)
1,245 1,245
Distributions (200) (200)
Net loss (1,942) (1,942)
Balance at December 31, 2022 1,084 1,084
Contributions (excluding item shown separately below)
180 180
Non-cash contribution from affiliate (see Note 11)
398 398
Distributions (280) (280)
Net income 7,150 7,150
Balance at December 31, 2023 $ 8,532 $ 8,532
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Year Ended December 31,
2023 2022 2021
Cash flows from operating activities
Net income (loss) $ 7,150 $ (1,942) $ (180)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 449 445 420
Amortization of discount and debt issuance costs 11 20 24
Loss on modification or extinguishment of debt 10 37 9
Total losses (gains) on derivative instruments, net
(5,825) 3,243 1,241
Total gains on derivatives, net-related party - - (11)
Net cash provided by (used for) settlement of derivative instruments
7 (155) (107)
Other 6 33 3
Changes in operating assets and liabilities:
Trade and other receivables 168 (68) (84)
Trade receivables-affiliate 26 76 (273)
Advances to affiliate 26 (58) 14
Inventory 50 (22) (62)
Margin deposits 73 (63) (8)
Accounts payable and accrued liabilities (347) 184 468
Accrued liabilities-related party - - (14)
Due to affiliates 3 7 9
Total deferred revenue (1) 42 35
Other, net (40) (44) (60)
Other, net-affiliate (1) (1) -
Net cash provided by operating activities
1,765 1,734 1,424
Cash flows from investing activities
Property, plant and equipment, net (1,711) (981) (238)
Other (11) 1 (2)
Net cash used in investing activities
(1,722) (980) (240)
Cash flows from financing activities
Proceeds from issuances of debt - 440 1,150
Repayments of debt (498) (2,419) (1,188)
Contributions 180 2,182 -
Distributions (280) (200) (1,163)
Other (8) (63) (9)
Net cash used in financing activities
(606) (60) (1,210)
Net increase (decrease) in restricted cash and cash equivalents
(563) 694 (26)
Restricted cash and cash equivalents-beginning of period 738 44 70
Restricted cash and cash equivalents-end of period $ 175 $ 738 $ 44
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1-ORGANIZATION AND NATURE OF OPERATIONS
We operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through CCL, which has three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks and two marine berths. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG.
Through our subsidiary CCP, we also own a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, storage tanks, and marine berths at the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “Liquefaction Project”).
We are pursuing a certain expansion project to provide additional liquefaction capacity, and we have commenced commercialization to support the additional liquefaction capacity associated with this expansion project.
We do not have employees and thus we have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. See Note 13-Related Party Transactions for additional details of the activity under these services agreements during the years ended December 31, 2023, 2022 and 2021.
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 Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Consolidated Financial Statements have been prepared in accordance with GAAP. Our Consolidated Financial Statements include the accounts of CCH and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Estimates
The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments useful lives of property, plant and equipment and certain valuations including asset retirement obligations (“AROs”), each as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
participants would take into account in measuring fair value. We attempt to maximize our 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 8-Derivative Instruments.
The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, contract assets, margin deposits, accounts payable and accrued liabilities reported on the Consolidated 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. Refer to Note 11-Debt for our debt fair value estimates, including our estimation methods.
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. See Note 12-Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition.
Restricted Cash and Cash Equivalents
Restricted cash and 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 Consolidated Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Current Expected Credit Losses
Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status and other risks or available financial assurances. We record charges and reversals of current expected credit losses in general and administrative in our Consolidated Statements of Operations.
The following table reflects the changes in our current expected credit losses (in millions):
Year Ended December 31,
2023 2022 2021
Current expected credit losses, beginning of period
$ 4 $ 3 $ 2
Charges (reversals) (1) 1 1
Current expected credit losses, end of period
$ 3 $ 4 $ 3
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. Inventory is charged to expense when sold, or, for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Generally, we begin capitalizing the costs of our LNG terminal once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with preliminary review and selection of equipment alternatives, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminal.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets.
We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.
We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives, except land which is not depreciated. Refer to Note 7-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 depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.
We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2023, 2022 and 2021.
Advances of Cash and Conveyed Assets to Service Providers
We may convey cash or physical assets to service providers in support of infrastructure maintained by them, which is necessary to support our own operations. Such conveyances are recognized within other non-current assets on our Consolidated Balance Sheets and amortized within depreciation and amortization expense on our Consolidated Statements of Operations over the shorter of the contractual term of the arrangement with the service provider or the useful life of the physical asset. The weighted average amortization period of these assets was approximately 35 years as of both December 31, 2023 and 2022.
Interest Capitalization
We capitalize interest costs mainly during the construction period of our LNG terminal and related assets. Upon placing the underlying asset in service, these costs are depreciated over the estimated useful life of the corresponding assets which interest costs were incurred, except for capitalized interest associated with land, which is not depreciated.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement. When we have the contractual right and intent 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. We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2023, 2022 and 2021. See Note 8-Derivative Instruments for additional details about our derivative instruments.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable and contract assets 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 margin deposits on our Consolidated Balance Sheets. 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.
As of December 31, 2023, CCL had SPAs with terms of 10 or more years with a total of 15 third parties and had agreements with Cheniere Marketing International LLP (“Cheniere Marketing”). CCL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.
Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.
Debt
Our debt consists of current and long-term secured and unsecured debt securities and 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 Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. 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 Consolidated 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.
We classify debt on our Consolidated Balance Sheets based on contractual maturity, with the following exceptions:
•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.
•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
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 Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.
Business Segment
We have determined that we operate as a single operating and reportable segment. Substantially all of our long-lived assets are located in the United States. Our chief operating decision maker is regularly provided with consolidated financial information to makes resource allocation decisions and assesses performance in the delivery of an integrated source of LNG to our customers. The financial measures regularly provided to the chief operating decision maker that are most consistent with GAAP are net income (loss) and total consolidated assets, as presented in our Consolidated Financial Statements.
Recent Accounting Standards
ASU 2023-07
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. We plan to adopt this guidance and conform with the applicable disclosures retrospectively when it becomes mandatorily effective for our annual report for the year ending December 31, 2024.
NOTE 3-CCL STAGE III CONTRIBUTION AND MERGER
In June 2022, Cheniere’s board of directors made a positive FID with respect to the investment in the construction and operation of the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 16, 2022. In connection with the positive FID, CCL Stage III, through which Cheniere was developing and constructing the Corpus Christi Stage 3 Project, was contributed to us from Cheniere (the “Contribution”) on June 15, 2022. Immediately following the Contribution, CCL Stage III was merged with and into CCL (the “Merger”), the surviving entity of the merger and our wholly owned subsidiary.
The Contribution was accounted for as a common control transaction as the assets and liabilities were transferred between entities under Cheniere’s control. As a result, the net liability transferred to us was recognized as a contribution in our Consolidated Statements of Member’s Equity and at the historical basis of Cheniere on June 15, 2022 in our Consolidated Balance Sheets. The Contribution was presented prospectively as we have concluded that the Contribution did not represent a change in our reporting entity, primarily as we concluded that CCL Stage III did not constitute a business under FASB topic Accounting Standards Codification 805, Business Combinations. The Merger had no impact on our Consolidated Financial Statements as it occurred between our consolidated subsidiaries.
NOTE 4-RESTRICTED CASH AND CASH EQUIVALENTS
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.
As of December 31, 2023 and 2022, we had $175 million and $738 million of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is contractually or legally restricted to the payment of liabilities related to the Liquefaction Project as required under certain debt arrangements. Additionally, as of December 31, 2022, the balance included $498 million related to the cash contributed from Cheniere, which was restricted for the redemption of the
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remaining outstanding principal balance of the 7.000% Senior Notes due 2024 (the “2024 CCH Senior Notes”) in January 2023.
NOTE 5-TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES
Trade and other receivables, net of current expected credit losses, consisted of the following (in millions):
December 31,
2023 2022
Trade receivables $ 164 $ 319
Other receivables 16 29
Total trade and other receivables, net of current expected credit losses $ 180 $ 348
NOTE 6-INVENTORY
Inventory consisted of the following (in millions):
December 31,
2023 2022
Materials $ 97 $ 92
LNG 12 53
Natural gas 13 31
Other 2 2
Total inventory $ 124 $ 178
NOTE 7-PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION
Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):
December 31,
2023 2022
LNG terminal
Terminal and interconnecting pipeline facilities $ 13,333 $ 13,299
Land 302 302
Construction-in-process 3,207 1,486
Accumulated depreciation (1,858) (1,421)
Total LNG terminal, net of accumulated depreciation 14,984 13,666
Fixed assets
Fixed assets 30 26
Accumulated depreciation (22) (19)
Total fixed assets, net of accumulated depreciation 8 7
Property, plant and equipment, net of accumulated depreciation $ 14,992 $ 13,673
The following table shows depreciation expense and offsets to LNG terminal costs (in millions):
Year Ended December 31,
2023 2022 2021
Depreciation expense $ 448 $ 444 $ 419
Offsets to LNG terminal costs (1) - - 143
(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.
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LNG Terminal Costs
LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and 50 years, as follows:
Components Useful life (years)
LNG storage tanks 50
Natural gas pipeline facilities 40
Marine berth, electrical, facility and roads 35
Water pipelines 30
Liquefaction processing equipment 6-50
Other 15-30
Fixed Assets
Our fixed assets 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 8-DERIVATIVE INSTRUMENTS
CCL has entered into commodity derivatives consisting of natural gas and power supply contracts, including those under the IPM agreements, for the development, commissioning and operation of the Liquefaction Project and expansion project, as well as the associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).
We recognize CCL’s derivative instruments as either assets or liabilities and measure those instruments at fair value. None of CCL’s derivative instruments are designated as cash flow, fair value or net investment hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process, in which case such changes are capitalized.
The following table shows the fair value of our derivative instruments, which are required to be measured at fair value on a recurring basis, by the fair value hierarchy levels prescribed by GAAP (in millions):
Fair Value Measurements as of
December 31, 2023 December 31, 2022
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)
$ 7 $ 35 $ (502) $ (460) $ (54) $ (19) $ (6,205) $ (6,278)
We value the Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, which incorporates observable commodity price curves, when available, and other relevant data.
We include a significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. Our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.
The Level 3 fair value measurements of the natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of December 31, 2023:
Net Fair Value Liability
(in millions)
Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives $(502) Market approach incorporating present value techniques Henry Hub basis spread
$(1.090) - $0.505 / $(0.145)
Option pricing model International LNG pricing spread, relative to Henry Hub (2)
87% - 379% / 197%
(1)Unobservable inputs were weighted by the relative fair value of the instruments.
(2)Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of the Liquefaction Supply Derivatives.
The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):
Year Ended December 31,
2023 2022
Balance, beginning of period $ (6,205) $ (1,221) $ 12
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2) 4,383 (1,492) (1,276)
Included in cost of sales, new deals (3) (1) (2,172) -
Purchases and settlements:
Purchases (4) - (1,938) 9
Settlements (5) 1,321 618 34
Transfers out of level 3 (6) - - -
Balance, end of period $ (502) $ (6,205) $ (1,221)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period
$ 4,382 $ (3,664) $ (1,276)
(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.
(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting
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period and continuing to exist at the end of the period.
(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.
(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
All existing 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 those derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes CCL to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when the derivative instruments are in an asset position. Additionally, counterparties are at risk that CCL will be unable to meet its commitments in instances where the derivative instruments are in a liability position. We incorporate both CCL’s nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of the derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
Liquefaction Supply Derivatives
CCL holds Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of December 31, 2023, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.
The forward notional amount for the Liquefaction Supply Derivatives was approximately 7,774 TBtu and 8,532 TBtu as of December 31, 2023 and 2022, respectively, inclusive of amounts under contracts with unsatisfied contractual conditions, and exclusive of extension options that were uncertain to be taken as of December 31, 2023.
The following table shows the effect and location of the Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations (in millions):
Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)
Year Ended December 31,
2023 2022 2021
LNG revenues $ (5) $ 1 $ 4
Recovery (cost) of sales 5,830 (3,246) (1,244)
Cost of sales-related party (2) - - 11
(1)Does not include the realized value associated with Liquefaction Supply Derivatives 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 during 2021 as discussed in Note 13-Related Party Transactions.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets
The following table shows the fair value and location of the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):
Fair Value Measurements as of (1)
December 31, 2023 December 31, 2022
Consolidated Balance Sheets Location
Current derivative assets $ 19 $ 12
Derivative assets 823 7
Total derivative assets 842 19
Current derivative liabilities (455) (1,374)
Derivative liabilities (847) (4,923)
Total derivative liabilities (1,302) (6,297)
Derivative liability, net $ (460) $ (6,278)
(1)Does not include collateral posted with counterparties by CCL of $3 million and $76 million as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets.
Consolidated Balance Sheets Presentation
The following table shows the fair value of the derivatives outstanding on a gross and net basis (in millions) for the derivative instruments that are presented on a net basis on our Consolidated Balance Sheets:
Liquefaction Supply Derivatives
December 31, 2023 December 31, 2022
Gross assets $ 1,184 $ 19
Offsetting amounts (342) -
Net assets $ 842 $ 19
Gross liabilities $ (1,349) $ (6,622)
Offsetting amounts 47 325
Net liabilities $ (1,302) $ (6,297)
NOTE 9-OTHER NON-CURRENT ASSETS, NET
Other non-current assets, net consisted of the following (in millions):
December 31,
2023 2022
Contract assets, net of current expected credit losses $ 184 $ 142
Advances of cash and conveyed assets to service providers for infrastructure to support LNG terminal, net of accumulated amortization 34 62
Other 65 21
Total other non-current assets, net $ 283 $ 225
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
NOTE 10-ACCRUED LIABILITIES
Accrued liabilities consisted of the following (in millions):
December 31,
2023 2022
Natural gas purchases $ 260 $ 597
Interest costs and related debt fees 128 150
Liquefaction Project costs 158 103
Other accrued liabilities 49 51
Total accrued liabilities $ 595 $ 901
NOTE 11-DEBT
Debt consisted of the following (in millions):
December 31,
2023 2022
Senior Secured Notes:
2024 CCH Senior Notes
$ - $ 498
5.875% due 2025
1,491 1,491
5.125% due 2027
1,201 1,271
3.700% due 2029
1,125 1,361
3.788% weighted average rate due 2039
2,539 2,633
Total Senior Secured Notes 6,356 7,254
Term loan facility agreement (the “CCH Credit Facility”)
- -
Working capital facility agreement (the “CCH Working Capital Facility”) (1)
- -
Total debt 6,356 7,254
Current debt, net of discount and debt issuance costs - (495)
Long-term portion of unamortized discount and debt issuance costs, net (45) (61)
Total long-term debt, net of discount and debt issuance costs $ 6,311 $ 6,698
(1)The CCH Working Capital Facility is classified as short-term debt as we are required to reduce the aggregate outstanding principal amount to zero for a period of five consecutive business days at least once each year.
Senior Secured Notes
The Senior Secured Notes, are jointly and severally guaranteed by our subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The Senior Secured Notes are our senior secured obligations, ranking senior in right of payment to any and all of our future indebtedness that is subordinated to the Senior Secured Notes and equal in right of payment with our other existing and future indebtedness that is senior and secured by the same collateral securing the Senior Secured Notes. The Senior Secured Notes are secured by a first-priority security interest in substantially all of our and the CCH Guarantors’ assets. We may, at any time, redeem all or part of the Senior Secured Notes at specified prices set forth in the respective indentures governing the Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. The series of Senior Secured Notes due in 2039 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.
Cancellation of Senior Secured Notes Contributed from Cheniere
During the years ended December 31, 2023 and 2022, Cheniere repurchased $400 million and $1,217 million, respectively, of certain series of our Senior Secured Notes, with all of such repurchases immediately contributed to us from Cheniere for no consideration under the equity contribution agreements described in Note 13-Related Party Transactions, and cancelled by us. It was determined that for accounting purposes, Cheniere repurchased the bonds on our behalf as a principal as opposed to as an agent, and thus the debt extinguishment was accounted for as an extinguishment directly with Cheniere.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
During the year ended December 31, 2023, we recorded a net distribution to Cheniere totaling $2 million from associated operating activities, inclusive of a $4 million distribution to Cheniere associated with write off of associated debt issuance costs and discount, offset by a $2 million contribution from Cheniere associated with interest paid by Cheniere on our behalf that was due at the time of the debt repayment. During the year ended December 31, 2022, we recorded a net contribution from Cheniere totaling $21 million from associated operating activities, inclusive of $30 million of interest due to the extinguishment of debt at the time of repayment offset by our write off of associated debt issuance costs and discount of $9 million.
The total contribution from Cheniere of $398 million and $1,238 million for the years ended December 31, 2023 and 2022, respectively, associated with the aforementioned activity is reflected within our Consolidated Statements of Member’s Equity.
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2023 (in millions):
Years Ending December 31, Principal Payments
2024 $ -
2025 1,491
2026 -
2027 1,277
2028 123
Thereafter 3,465
Total $ 6,356
Credit Facilities
Below is a summary of our credit facilities outstanding as of December 31, 2023 (in millions):
CCH Credit Facility (1)
CCH Working Capital Facility (2)
Total facility size $ 3,260 $ 1,500
Less:
Outstanding balance - -
Letters of credit issued - 155
Available commitment $ 3,260 $ 1,345
Priority ranking Senior secured Senior secured
Interest rate on available balance (3) SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5%
SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.5% or base rate plus 0.0% - 0.5%
Commitment fees on undrawn balance (3) 0.525%
0.10% - 0.20%
Maturity date (4) June 15, 2027
(1)Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by Cheniere CCH Holdco I, our direct parent company, of its 100% ownership of our limited liability company interests.
(2)Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the CCH Guarantors, as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the Senior Secured Notes and the CCH Credit Facility.
(3)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.
(4)The CCH Credit Facility matures the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project.
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 us and our restricted subsidiaries’ ability to make certain
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investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.
As of December 31, 2023, 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,
2023 2022 2021
Total interest cost $ 323 $ 465 $ 473
Capitalized interest (106) (33) (26)
Total interest expense, net of capitalized interest $ 217 $ 432 $ 447
Fair Value Disclosures
The following table shows the carrying amount and estimated fair value of our senior notes (in millions):
December 31, 2023 December 31, 2022
Carrying
Amount Estimated
Fair Value (1) Carrying
Amount Estimated
Fair Value (1)
Senior Secured Notes
$ 6,356 $ 5,961 $ 7,254 $ 6,752
(1)As of both December 31, 2023 and 2022, $1.7 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.
The estimated fair value of our credit facilities approximates the principal amount outstanding 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 12-REVENUES
The following table represents a disaggregation of revenue earned (in millions):
Year Ended December 31,
2023 2022 2021
Revenues from contracts with customers
LNG revenues $ 3,850 $ 6,335 $ 3,903
LNG revenues-affiliate 1,620 3,027 1,887
Total revenues from contracts with customers 5,470 9,362 5,790
Net derivative gain (loss) (1)
(5) 1 4
Total revenues $ 5,465 $ 9,363 $ 5,794
(1)See Note 8-Derivative Instruments for additional information about our derivatives.
LNG Revenues
We have entered into numerous SPAs with third party customers for the sale of LNG on an FOB basis (delivered to the customer at the Corpus Christi LNG Terminal) or a DAT basis (delivered to the customer at their specified LNG receiving terminal). 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 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
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
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 13-Related Party Transactions for additional information regarding these agreements.
Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer based on the delivery terms described above, 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. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of at the time the contract 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.
When we sell LNG on a DAT basis, we rely on our agreement with our marketing affiliate for all fulfillment costs. We expense fulfillment costs as incurred unless otherwise dictated by GAAP.
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.
Sales of natural gas where, in the delivery of the natural gas to the end customer, we have concluded that we acted as a principal are presented within revenues in our Consolidated Statements of Operations, and where we have concluded that we acted as an agent are netted within cost of sales in our Consolidated Statements of Operations.
Contract Assets and Liabilities
The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):
December 31,
2023 2022
Contract assets, net of current expected credit losses $ 186 $ 144
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. The change in contract assets between the years ended December 31, 2023 and 2022 was primarily attributable to additional 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 other current liabilities and other non-current liabilities on our Consolidated Balance Sheets (in millions):
Year Ended December 31, 2023
Deferred revenue, beginning of period $ 76
Cash received but not yet recognized in revenue -
Revenue recognized from prior period deferral -
Deferred revenue, end of period $ 76
We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
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:
December 31, 2023 December 31, 2022
Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1)
LNG revenues (2) $ 49.5 10 $ 50.9 10
LNG revenues-affiliate 1.0 9 1.2 8
Total revenues $ 50.5 $ 52.1
(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
(2)We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID 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 and consideration is not otherwise constrained from ultimate pricing and receipt.
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. Additionally, we have excluded variable consideration related to volumes that contractually are subject to additional liquefaction capacity beyond what is currently in construction or operation. The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:
Year Ended December 31,
2023 2022
LNG revenues 49 % 70 %
LNG revenues-affiliate 80 % 86 %
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
NOTE 13-RELATED PARTY TRANSACTIONS
Below is a summary of our related party transactions, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):
Year Ended December 31,
2023 2022 2021
LNG revenues-affiliate
SPAs and Letter Agreements with Cheniere Marketing, LLC (“Cheniere Marketing”) (1)
$ 1,620 $ 2,993 $ 1,837
Contracts for Sale and Purchase of Natural Gas and LNG with other affiliates (2) - 34 50
Total LNG revenues-affiliate 1,620 3,027 1,887
Cost of sales-affiliate
Contracts for Sale and Purchase of Natural Gas and LNG (2) 55 103 19
Cheniere Marketing Agreements (1) (3)
116 - 31
Total cost of sales-affiliate 171 103 50
Cost of sales-related party
Natural Gas Supply Agreement (4) - - 146
Operating and maintenance expense-affiliate
Services Agreements (5) 116 120 105
Land Agreements (6) - 1 1
Total operating and maintenance expense-affiliate 116 121 106
Operating and maintenance expense-related party
Natural Gas Transportation Agreements (7) 9 9 9
General and administrative expense-affiliate
Services Agreements (5) 45 38 28
(1)CCL primarily sells LNG to Cheniere Marketing International LLP (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices. In addition, CCL has an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price. As of December 31, 2023 and 2022, CCL had $213 million and $223 million of accounts receivable-affiliate, respectively, under these agreements with Cheniere Marketing.
(2)CCL has an agreement with Sabine Pass Liquefaction, LLC (“SPL”) that allows the parties to sell and purchase natural gas with each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales-affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. As of December 31, 2023 and 2022, CCL had zero and $16 million of accounts receivable-affiliate, respectively, under these agreements with SPL.
(3)CCL and Cheniere Marketing have entered into Shipping Services Agreements (“SSAs”) for the provision of certain shipping and transportation-related services associated with certain SPAs between CCL and third-party customers that are delivered to the customer at their specified LNG receiving terminal. Under the SSAs, CCL pays Cheniere Marketing a fee of 3% to 7% of Henry Hub plus a fixed fee for the shipping services provided. Deliveries under the SSAs commenced in 2023.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
(4)CCL was party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. The related party entity was acquired by a non-related party on November 1, 2021, therefore, as of such date, this agreement ceased to be considered a related party agreement. CCL also has an agreement with Midship Pipeline Company, LLC that allows them to sell and purchase natural gas with each other.
(5)We do not have employees and thus our subsidiaries have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements are primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2023 and 2022, we had $116 million and $132 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense-affiliate.
(6)CCL has agreements with Cheniere Land Holdings, LLC, a wholly owned subsidiary of Cheniere, to rent, obtain easements and license to enter the land owned by CLH for the Liquefaction Project.
(7)CCL is party to natural gas transportation agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. CCL recorded accrued liabilities-related party of $1 million as of both December 31, 2023 and 2022 with this related party.
We had $49 million and $43 million due to affiliates as of December 31, 2023 and 2022, respectively, under agreements with affiliates as described above.
Disclosure of future consideration under revenue contracts with affiliates is included in Note 12-Revenues. Additionally, disclosure of future contractual obligations with affiliates and related parties is included in Note 14-Commitments and Contingencies.
Other Agreements
State Tax Sharing Agreements
CCL and CCP each have a state tax sharing agreement with Cheniere. Under these agreements, Cheniere has agreed to prepare and file all state and local tax returns which each of the entities 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, each of the respective entities will pay to Cheniere an amount equal to the state and local tax that each of the entities would be required to pay if its state and local tax liability were calculated on a separate company basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreements. The agreements for both CCL and CCP were effective for tax returns due on or after May 2015.
Equity Contribution Agreements
We have equity contribution agreements with Cheniere and certain of its subsidiaries (the “Equity Contribution Agreements”) pursuant to which Cheniere agreed to contribute any of our Senior Secured Notes that Cheniere has repurchased to us for no consideration. During the years ended December 31, 2023 and 2022, Cheniere repurchased a total of $400 million and $1,217 million, respectively, of certain series of our Senior Secured Notes, which were immediately contributed under the Equity Contribution Agreements to us from Cheniere and cancelled by us.
NOTE 14-COMMITMENTS AND CONTINGENCIES
Commitments
We have various future commitments under executed contracts that include unconditional purchase obligations and other commitments which do not meet the definition of a liability as of December 31, 2023 and thus are not recognized as liabilities in our Consolidated Financial Statements.
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
EPC Contract
CCL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of the Corpus Christi Stage 3 Project. The total contract price of the EPC contract is approximately $5.7 billion, inclusive of amounts incurred under change orders through December 31, 2023. As of December 31, 2023, we had approximately $2.9 billion remaining obligations under this contract.
Natural Gas Supply, Transportation and Storage Service Agreements
CCL has physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2023, the remaining fixed terms of these contracts ranged up to 15 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs.
Additionally, CCL has natural gas transportation and storage service agreements for the Liquefaction Project. The initial fixed terms of the natural gas transportation agreements range up 20 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs. The initial fixed term of the natural gas storage service agreements ranges up to five years.
As of December 31, 2023, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which contractual conditions were met or are currently expected to be met were as follows (in billions):
Years Ending December 31, Payments Due to Third Parties (1) Payments Due to Related Party (1)
2024 $ 2.4 $ -
2025 2.9 -
2026 3.0 0.1
2027 2.9 0.1
2028 2.1 0.1
Thereafter 22.3 0.7
Total $ 35.6 $ 1.0
(1)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Global gas market prices are based on estimates as of December 31, 2023 to the extent forward prices are not available and assume the highest price in cases of price optionality available under the agreement. 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.
Services Agreements
CCL and CCP have certain fixed commitments under services agreements, SSAs and other agreements of $0.3 billion with third parties and $7.6 billion with affiliates. See Note 13-Related Party Transactions for additional information regarding such agreements.
Environmental and Regulatory Matters
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.
Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
the opinion of management, as of December 31, 2023, 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.
NOTE 15-CUSTOMER CONCENTRATION
The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:
Percentage of Total Revenues from External Customers Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
Year Ended December 31, December 31,
2023 2022 2021 2023 2022
Customer A 22% 21% 21% 13% 17%
Customer B 15% 14% 16% * *
Customer C 14% 14% 15% * *
Customer D * * * 48% 33%
Customer E * 10% * * *
* 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,
2023 2022 2021
Spain $ 1,355 $ 2,192 $ 1,432
Singapore 590 1,248 694
Indonesia 558 889 618
France 543 940 423
Ireland 538 868 599
China 180 - -
United States 81 199 141
Total $ 3,845 $ 6,336 $ 3,907
NOTE 16-SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in millions):
Year Ended December 31,
2023 2022 2021
Cash paid during the period for interest on debt, net of amounts capitalized $ 223 $ 280 $ 423
Right-of-use assets obtained in exchange for new operating lease liabilities 1 3 -
Non-cash investing and financing activity:
Unpaid purchases of property, plant and equipment, net and other non-current assets, net 148 78 38
Conveyance of property, plant and equipment in exchange for other non-current assets - 17 -
Equity contribution of property, plant and equipment from affiliate - 7 -
Cancellation of Senior Secured Notes contributed to us from Cheniere (see Note 11 )
400 1,217 -
We recorded $1.5 billion of contributions in our Consolidated Statements of Member’s Equity during the year ended December 31, 2022 related to the contribution of the CCL Stage III entity to us from Cheniere on June 15, 2022, with such contribution representing a non-cash financing activity. See Note 3-CCL Stage III Contribution and Merger for further discussion.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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, 2023, 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 Consolidated Financial Statements and is incorporated herein by reference.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE
Omitted pursuant to Instruction I of Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to Instruction I of Form 10-K.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS
Omitted pursuant to Instruction I of Form 10-K.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE
Omitted pursuant to Instruction I of Form 10-K.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees billed by KPMG LLP for professional services rendered for 2023 and 2022 (in millions):
Fiscal 2023
Fiscal 2022
Audit Fees $ 1 $ 1
Audit Fees-Audit fees for 2023 and 2022 include fees associated with the audit of our annual Consolidated Financial Statements, reviews of our interim Consolidated 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 2023 and 2022.
Tax Fees-There were no tax fees in 2023 and 2022.
Other Fees-There were no other fees in 2023 and 2022.
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 Cheniere 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, 2023 and 2022.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements and Exhibits
(1) Financial Statements-Cheniere Corpus Christi Holdings, LLC:
Management’s Report to the Member of Cheniere Corpus Christi Holdings, LLC
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Balance Sheets
Consolidated Statements of Member’s Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
(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 in the consolidated financial statements and accompanying notes included in 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 Certificate of Formation of the Company
CCH S-4 3.1 1/5/2017
3.2 Certificate of Correction to Certificate of Formation of the Company
CCH S-4 3.2 1/5/2017
3.3 Amended and Restated Limited Liability Company Agreement of the Company
CCH S-4 3.3 1/5/2017
3.4 Certificate of Formation of CCL
CCH S-4 3.4 1/5/2017
3.5 Amended and Restated Limited Liability Company Agreement of CCL
CCH S-4 3.5 1/5/2017
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
3.6 Certificate of Formation of Corpus Christi Pipeline GP, LLC
CCH S-4 3.6 1/5/2017
3.7 Certificate of Correction to Certificate of Formation of Corpus Christi Pipeline GP, LLC
CCH S-4 3.7 1/5/2017
3.8 Amended and Restated Limited Liability Company Agreement of Corpus Christi Pipeline GP, LLC
CCH S-4 3.8 1/5/2017
3.9 Certificate of Limited Partnership of CCP
CCH S-4 3.9 1/5/2017
3.10 Certificate of Amendment to Certificate of Limited Partnership of CCP
CCH S-4 3.10 1/5/2017
3.11 Amended and Restated Agreement of Limited Partnership of CCP
CCH S-4 3.11 1/5/2017
4.1 Indenture, dated as of May 18, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee
Cheniere 8-K 4.1 5/18/2016
4.2 First Supplemental Indenture, dated as of December 9, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee
Cheniere 8-K 4.1 12/9/2016
4.3 Form of 5.875% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.3 above)
Cheniere 8-K 4.1 12/9/2016
4.4 Second Supplemental Indenture, dated as of May 19, 2017, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as trustee
CCH 8-K 4.1 5/19/2017
4.5 Form of 5.125% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.5 above)
CCH 8-K 4.1 5/19/2017
4.6 Third Supplemental Indenture, dated September 6, 2019, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee
CCH 8-K 4.1 9/12/2019
4.7 Indenture, dated as of September 27, 2019, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and the Bank of New York Mellon, as trustee
CCH 8-K 4.1 9/30/2019
4.8 Form of 4.80% Senior Secured Note due December 31, 2039 (Included as Exhibit A-1 to Exhibit 4.8 above)
CCH 8-K 4.1 9/30/2019
4.9 Indenture, dated as of October 17, 2019, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee
CCH 8-K 4.1 10/18/2019
4.10 Form of 3.925% Senior Secured Note due December 31, 2039 (Included as Exhibit A to Exhibit 4.10 above)
CCH 8-K 4.1 10/18/2019
4.11 Fourth Supplemental Indenture, dated as of November 13, 2019, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee
CCH 8-K 4.1 11/13/2019
4.12 Form of 3.700% Senior Secured Note due 2029 (Included as Exhibit A-1 to Exhibit 4.12 above)
CCH 8-K 4.1 11/13/2019
4.13 Fifth Supplemental Indenture, dated as of August 24, 2021, among the Company, as issuer, CCL, CCP, and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee
CCH 8-K 4.1 8/24/2021
4.14 Form of 2.742% Senior Secured Note due 2039 (Included as Exhibit A-1 to Exhibit 4.14 above)
CCH 8-K 4.1 8/24/2021
4.15 Indenture, dated as of August 20, 2020, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee
CCH 8-K 4.1 8/21/2020
4.16 Form of 3.52% Senior Secured Note due 2039 (Included as Exhibit A-1 to Exhibit 4.16 above)
CCH 8-K 4.1 8/21/2020
10.1 Second Amended and Restated Term Loan Facility Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, the lenders party thereto from time to time and Société Générale as the Term Loan Facility Agent
CCH 8-K 10.1 6/22/2022
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.2 Second Amended and Restated Common Terms Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, Société Générale, as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, and Société Générale as Intercreditor Agent, and any other facility lenders party thereto from time to time
CCH 8-K 10.3 6/22/2022
10.3 Second Amended and Restated Common Security and Account Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, the Senior Creditor Group Representatives, Société Générale as the Intercreditor Agent, Société Générale as Security Trustee and Mizuho Bank, Ltd as the Account Bank
CCH 8-K 10.4 6/22/2022
10.4 Amended and Restated Pledge Agreement, dated May 22, 2018, among Cheniere CCH HoldCo I, LLC and Société Générale as Security Trustee
CCH 8-K 10.4 5/24/2018
10.5 Amended and Restated Equity Contribution Agreement, dated May 22, 2018, among the Company and Cheniere
CCH 8-K 10.5 5/24/2018
10.6 Second Amended and Restated Working Capital Facility Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, the lenders party thereto from time to time, the issuing banks party thereto from time to time, the swing line lenders party thereto from time to time, The Bank of Nova Scotia as Working Capital Facility Agent and Société Générale as Security Trustee
CCH 8-K 10.2 6/22/2022
10.7 Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL Stage III and Bechtel Energy Inc
CEI 10-Q 10.1 5/4/2022
10.8 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL Stage III and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Maintaining Elevated Ground Flare Option, dated March 28, 2022, (ii) the Change Order CO-00002 Package 7 Pre-Investment of Trains 8 and 9 (Without Site Work), dated April 29, 2022 and (iii) the Change Order CO-00003 Modifications to Insurance Language, dated June 13, 2022 (Portions of this exhibit have been omitted.)
CCH 10-Q 10.6 8/4/2022
10.9 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00004 Currency Conversion, dated June 27, 2022, (ii) the Change Order CO-00005 Fuel Adjustment, dated July 15, 2022, (iii) the Change Order CO-00006 Removal of Laydown Yard Scope Option, dated August 2, 2022, (iv) the Change Order CO-00007 Removal of Air Bridges Scope Option, dated August 22, 2022, (v) the Change Order CO-00008 Acid Gas Flare K/O Drum, dated August 16, 2022, and (vi) the Change Order CO-00009 Package 7A (Without Site Work), dated August 16, 2022 (Portions of this exhibit have been omitted.)
CCH 10-Q 10.1 11/3/2022
10.10 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-000010 Insurance Provisional Sum Interim Adjustment, dated September 13, 2022 and (ii) the Change Order CO-000011 Package 6 Descope and Transfer to Owner, dated September 14, 2022 (Portions of this exhibit have been omitted)
CCH 10-K 10.10 2/23/2023
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.11 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction Stage III, LLC and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00012 Chart License Fee Provisional Sum Closure, dated September 16, 2022, (ii) the Change Order CO-00013 HRU Nozzles and Block Headers, dated September 21, 2022, (iii) the Change Order CO-00014 Addition of Nitrogen Receiver, dated December 13, 2022, (iv) the Change Order CO-00015 Package 6 Feed Gas Pipeline Interfaces, dated December 14, 2022, (v) the Change Order CO-00016 Old Sherwin Building Security, dated November 23, 2022, (vi) the Change Order CO-00017 Remote Monitoring Diagnostic for Mixed Refrigerant (MR) Compressors, dated December 14, 2022, (vii) the Change Order CO-00018 EFG Package #1, dated January 9, 2023, (viii) the Change Order CO-00019 Q3 2022 Commodity Price Rise and Fall (ATT MM), dated January 17, 2023, (ix) the Change Order CO-00020 ICSS Vendor Selection and EPC Warranty (Yokogawa), dated September 21, 2022 and (x) the Change Order CO-00021 Laydown Development Package, dated February 6, 2023 (Portions of this exhibit have been omitted.)
CCH 10-Q 10.1 5/2/2023
10.12 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction, LLC and Bechtel Energy, Inc.: (i) the Change Order CO-00022 Refrigerant Storage Packages 1 and 2, dated February 13, 2023, (ii) the Change Order CO-00023 EFG Package #2, dated February 21, 2023, (iii) the Change Order CO-00024 Defrost Improvements (Cold Box), dated February 23, 2023, (iv) the Change Order CO-00025 Miscellaneous Design Improvements, dated February 23, 2023, (v) the Change Order CO-00026 EFG Package #3, dated February 23, 2023, (vi) the Change Order CO-00027 Addition of 86 Lockout Relay on Transformers, dated February 14, 2023, (vii) the Change Order CO-00028 Additional Duct Banks, dated September 15, 2022, (viii) the Change Order CO-00029 2022 FERC Support Hours Interim Adjustment, dated March 13, 2023, (ix) the Change Order CO-00030 Drainage Blanket (A Street), dated April 6, 2023, (x) the Change Order CO-00031 Refrigerant Storage Interface Package #3, dated April 7, 2023, (xi) the Change Order CO-00032 Q4 2022 Commodity Price Rise and Fall (ATT MM), dated April 24, 2023, (xii) the Change Order CO-00033 Lift Owner-Provided Dewar System (Nitrogen Receiver Facility), dated March 1, 2022, (xiii) the Change Order CO-00034 HAZOP Package #1 - Addition of Flame Arrestors for Oil Mist Eliminator Vent, dated April 25, 2023 and (xiv) the Change Order CO-00035 EFG Package #4 (Water Pipeline Pipe Bridge), dated May 19, 2023 (Portions of this exhibit have been omitted.)
CCH 10-Q 10.1 8/3/2023
10.13 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00036 Payment Milestone Updates (Schedule C-1), dated June 19, 2023, (ii) the Change Order CO-00037 Geotechnical Soils Investigation Period & Security Division of Responsibility Change, dated June 20, 2023, (iii) the Change Order CO-00038 Power Monitoring System (ETAP HMI), dated June 29, 2023 and (iv) the Change Order CO-00039 EFG Firewater Connection, dated June 30, 2023 (Portions of this exhibit have been omitted.)
CCH 10-Q 10.1 11/2/2023
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.14* Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00040 Q1 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (ii) the Change Order CO-00041 Q2 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (iii) the Change Order CO-00042 HAZOP Package #2 - Additional IPL (Pressure Transmitter Across the Strainer), dated July 5, 2023, (iv) the Change Order CO-00043 Total Condensate Flowmeter on Three (3) Inch Condensate Line, dated August 31, 2023, (v) the Change Order CO-00044 FERC Package #1 ISA 84 (Accommodation for Two Hundred and Fifty (250) Fire and Gas Detectors), dated August 31, 2023, (vi) the Change Order CO-00045 Increase LNG Rundown Line Check Valve Bypass Size to Six (6) Inches, dated August 31, 2023, (vii) the Change Order CO-00046 Add Manual Bypass Valves Around 31XV-13071, dated September 13, 2023, (viii) the Change Order CO-00047 Relocate Existing 16” Process Water Line and Provide Tie-In, dated September 8, 2023, (ix) the Change Order CO-00048 Future HRU Bypass Tie-In and Thermowell Updates, dated September 12, 2023, (x) the Change Order CO-00049 Butterfly Valves for Flare Drums, dated September 5, 2023, (xi) the Change Order CO-00050 Condensate Shroud on Condensate Rundown Line (Blue Engineering Report), dated September 12, 2023, (xii) the Change Order CO-00051 EFG Package #5 (138KV Feeder Cable), dated September 8, 2023, (xiii) the Change Order CO-00052 Defect Correction Period for Cementitious Fireproofing, dated August 7, 2023, (xiv) the Change Order CO-00053 Chart Transition Joint Spares, dated October 5, 2023, (xv) the Change Order CO-00054 CCL Tank(s) “A” and “C” Tie-In Study & Long Lead Item Purchases, dated September 19, 2023, (xvi) the Change Order CO-00055 FERC Package #2 Firewater Layout, dated September 13, 2023, (xvii) the Change Order CO-00056 HAZOP Package #3 - Stainless Steel C And D Pass Piping / Two Temperature Transmitters per Train, dated February 14, 2023, (xviii) the Change Order CO-00057 HAZOP Package #4 (“Phase Two Items”), dated October 10, 2023, (xix) the Change Order CO-00058 E-HAZOP Package #1 (“LV MCC Ride Through”), dated September 8, 2023, (xx) the Change Order CO-00059 Level Transmitter on Stand Pipe Inside Liquefaction Cold Boxes, dated October 13, 2023, (xxi) the Change Order CO-00060 Small Spill Containment (Additional Curbs), dated July 5, 2023, (xxii) the Change Order CO-00061 Remote Input/Output (RIO) Junction Box Grounding, dated October 10, 2023, (xxiii) the Change Order CO-00062 Geomembrane Liner and Geocell for Laydown 6 Channel, dated August 31, 2023, (xxiv) the Change Order CO-00063 Phased Surfacing of Permanent Plant Roads, dated August 7, 2023, (xxv) the Change Order CO-00064 Provisional Sum Interim Adjustment - Schedule KK-1 12-Month COVID Countermeasures, dated July 24, 2023, (xxvi) the Change Order CO-00065 Modification to FTZ Zone Site (Exhibit A of Attachment LL), dated August 3, 2023, (xxvii) the Change Order CO-00066 Attachment B (Contract Deliverables), dated June 2, 2023, (xxviii) the Change Order CO-00067 Sheet Pile Joint Sealing 310Q02 Sump, dated October 5, 2023, (xxix) the Change Order CO-00068 E-HAZOP Package #2 (“Phase One Items”), dated October 19, 2023, (xxx) the Change Order CO-00069 Package 6 Feed Gas Pipeline and Pig Receiver DMM, dated August 3, 2023, (xxxi) the Change Order CO-00070 Dry Flare Knockout Drum Spill Pad Drain Specification Change, dated October 5, 2023, (xxxii) the Change Order CO-00071 Viewing Platform Piles, dated October 18, 2023, (xxxiii) the Change Order CO-00072 Site Plan Update Package #1 - Re-Route Contractor’S Utility Water & Nitrogen Pipelines and Provide Power & Fiber Cables To Nitrogen Tie-In Point, dated November 2, 2023, (Portions of this exhibit have been omitted.)
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.15 Operation and Maintenance Agreement, dated as of May 13, 2015, among Cheniere LNG O&M Services, LLC and CCL
CCH S-4 10.14 1/5/2017
10.16 Operation and Maintenance Agreement, dated as of May 13, 2015, among Cheniere LNG O&M Services, LLC and CCP
CCH S-4 10.15 1/5/2017
10.17 LNG Sale and Purchase Agreement (FOB), dated April 1, 2014, between CCL (Seller) and Endesa Generación, S.A. (Buyer)
Cheniere 8-K 10.1 4/2/2014
10.18 LNG Sale and Purchase Agreement (FOB), dated April 7, 2014, between CCL (Seller) and Endesa S.A. (Buyer)
Cheniere 8-K 10.1 4/8/2014
10.19 Assignment and Amendment Agreement, dated April 7, 2014, among Endesa Generación S.A., Endesa S.A. and CCL
Cheniere 10-Q 10.3 5/1/2014
10.20 Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated July 23, 2015, between Endesa S.A. (Buyer) and CCL (Seller)
Cheniere 10-Q 10.9 10/30/2015
10.21 Amendment No. 2 of LNG Sale and Purchase Agreement (FOB), dated July 23, 2015, between Endesa S.A. (Buyer) and CCL (Seller)
Cheniere 10-Q 10.10 10/30/2015
10.22 Letter agreement regarding change from LIBOR to SOFR, dated May 18, 2023, to LNG Sale and Purchase Agreement, dated April 1, 2014, between CCL and Endesa S.A. (assignee of Endesa Generacion S.A.), as amended
CCH 10-Q 10.2 8/3/2023
10.23 Letter agreement regarding change from LIBOR to SOFR, dated May 18, 2023, to LNG Sale and Purchase Agreement, dated April 7, 2014, between CCL and Endesa S.A., as amended
CCH 10-Q 10.3 8/3/2023
10.24 Amended and Restated LNG Sale and Purchase Agreement (FOB), dated March 20, 2015, between CCL (Seller) and PT Pertamina (Persero) (Buyer)
Cheniere 10-Q 10.5 4/30/2015
10.25 Amendment No. 1, dated February 4, 2016, to Amended and Restated LNG Sale and Purchase Agreement (FOB) between CCL and PT Pertamina (Persero), dated March 20, 2015
CCH S-4 10.22 1/5/2017
10.26 Amendment No. 2 of Amended and Restated LNG Sale and Purchase Agreement, dated June 27, 2019, between CCL and PT Pertamina (Persero)
CCH 10-Q 10.1 11/1/2019
10.27 LNG Sale and Purchase Agreement (FOB), dated June 2, 2014, between CCL (Seller) and Gas Natural Fenosa LNG SL (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)
Cheniere 8-K 10.1 6/2/2014
10.28 Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 27, 2018, between CCL (Seller) and Gas Natural Fenosa LNG GOM, Limited (Buyer)
CCH 10-Q 10.5 5/4/2018
10.29 Second Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated June 15, 2022, between CCL and Cheniere Marketing International LLP
CCH 8-K 10.6 6/22/2022
10.30 LNG Sale and Purchase Agreement (EOG Early IPM), dated December 30, 2019, between CCL (Seller) and Cheniere Marketing International LLP (Buyer)
CCH 10-K 10.34 2/25/2020
10.31 Letter Agreement regarding changes to the EOG Early IPM SPA, dated November 1, 2022, between CCL and Cheniere Marketing International LLP
CCH 10-Q 10.50 11/3/2022
10.32 Letter agreement regarding change from LIBOR to SOFR, dated June 26, 2023, to LNG Sale and Purchase Agreement (EOG Early IPM) between CCL and Cheniere Marketing International LLP, dated December 30, 2019, as amended
CCH 10-Q 10.4 8/3/2023
10.33 LNG Sale and Purchase Agreement (ARC), dated June 15, 2022, between CCL Stage III and Cheniere Marketing International LLP
CCH 8-K 10.50 6/22/2022
10.34 Letter Agreement regarding changes to the ARC IPM SPA, dated November 1, 2022, between CCL and Cheniere Marketing International LLP
CCH 10-Q 10.40 11/3/2022
Exhibit No. Incorporated by Reference (1)
Description Entity Form Exhibit Filing Date
10.35 LNG Sale and Purchase Agreement (Apache Corporation), dated June 15, 2022, between CCL and Cheniere Marketing International LLP
CCH 10-Q 10.20 11/3/2022
10.36 LNG Sale and Purchase Agreement (EOG Resources, Inc.), dated June 15, 2022, between CCL and Cheniere Marketing International LLP
CCH 10-Q 10.30 11/3/2022
10.37 Letter agreement, dated May 2, 2022, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated November 28, 2014, between CCL and Cheniere Marketing International LLP
CCH 10-Q 10.10 5/4/2022
10.38 Shipping Services Agreement in relation to the PGNiG SPA, dated June 15, 2022, between CCL and Cheniere Marketing International LLP (Portions of this exhibit have been omitted.)
CCH 8-K 10.70 6/22/2022
10.39 Shipping Services Agreement in relation to the CPC SPA, dated November 1, 2022, between CCL and Cheniere Marketing International LLP (Portions of this exhibit have been omitted.)
CCH 10-Q 10.60 11/3/2022
10.40 Shipping Services Agreement in relation to the Foran SPA, dated November 1, 2022, between CCL and Cheniere Marketing International LLP (Portions of this exhibit have been omitted.)
CCH 10-Q 10.70 11/3/2022
22.1* List of Issuers and Guarantor Subsidiaries
31.1* Certification by President and Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1** Certification by President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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) and CCH (SEC File No. 333-215435), as applicable.
* Filed herewith.
** Furnished herewith.
(c) Financial statements of affiliates whose securities are pledged as collateral
All financial statements have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.