Abbreviated Legal Entity Structure
The following diagram depicts our abbreviated legal entity structure as of December 31, 2017,2023, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:
Unless the context requires otherwise, references to “CCH,” “the Company,the “Company,” “we,” “us,” and “our” refer to Cheniere Corpus Christi Holdings, LLC and its consolidated subsidiaries.
In June 2022, as part of the internal restructuring of Cheniere’s subsidiaries, Cheniere contributed its equity interest in Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”), formerly a wholly owned direct subsidiary of Cheniere, to us, and CCL Stage III was subsequently merged with and into CCL, the surviving entity of the merger and our wholly owned subsidiary.
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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
•statements regarding our expected receipt of cash distributions from our subsidiaries;
•statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction facilities,facility, pipeline facilitiesfacility or other projects, or any expansions or portions thereof, by certain dates, or at all;
•statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
•statements regarding our future sources of liquidity and cash requirements;
•statements relating to the construction of our Trains and pipeline, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any such EPC or other contractor, and anticipated costs related thereto;
•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
•statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
•statements regarding our planned development and construction of additional Trains and pipeline,pipelines, including the financing of such Trains;Trains and pipelines;
•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
•any other statements that relate to non-historical or future information.information; and
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,“achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “potential,“project,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
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PART I
General
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 Cheniere Energy, Inc., a Houston-based energy company primarily engaged600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in LNG-related businesses, to develop, construct,liquid form for efficient transport overseas.
We own and operate maintain and own a natural gas liquefaction and export facility (the “Liquefaction Facility”) and a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline” and together with the Liquefaction Facility, the “Liquefaction Project”) on nearly 2,000 acres of land that we own or controllocated near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through wholly-owned subsidiaries CCL, and CCP, respectively.
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 underin construction or operation.
We remain focused on safety, operational excellence and Train 3 is being commercializedcustomer 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 has all necessary regulatory approvalsother optimization projects. We believe these factors provide a foundation for additional growth in place. Constructionour portfolio of customer contracts in the future. We hold a significant land position at the Corpus Christi PipelineLNG 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 nearing completion.made.
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Our Business Strategy
Our primary objective for the Liquefaction Projectbusiness strategy is to generate steadydevelop, construct and reliable revenuesoperate assets to meet our long-term customers’ energy demands. We plan to implement our strategy by:
•safely, efficiently and operating cash flows by:
reliablyoperating and maintaining our assets, safely, efficiently and reliably in compliance with all applicable government regulations;including our Trains;
•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 andand/or optimizing the Liquefaction Project by leveraging existing infrastructure; and
•maintaining a prudent and cost-effective capital structure.structure; and
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, is being developedas described above under the caption General, includes three Trains, three storage tanks, two marine berths and constructed atthe construction of the Corpus Christi LNG terminal. Substantially allStage 3 Project with seven midscale Trains. Additionally, in March 2023, CCL and another subsidiary of our long-lived assets are located inCheniere submitted an application with the United States. InFERC 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 2014,31, 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 authorizationapprovals from the FERC to site, construct and operate Stages 1 and 2 of the Liquefaction Project. The following table summarizes the overall project status of Stage 1 ofTrains at the Liquefaction Project as of December 31, 2017:
| 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 | |||||||||||||||||||
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Natural Gas Supply, Transportation and Storage
CCL has secured natural gas feedstock for a 25-year term and to non-FTA countries for a 20-year term up to a combined total of the equivalent of 767 Bcf/yr
Customers
The concentration of our customer credit risk in order to secure natural gas feedstock for the Liquefaction Project. We expect to enter into gas supply contracts under these enabling agreementsexcess of 10% of total revenues was as and when required for the Liquefaction Project. As of December 31, 2017, CCL has secured up to approximately 2,024 TBtu of natural gas feedstock through long-term natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.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 Liquefaction Project under which Bechtel charges a lump sum for all work performedabove customers contribute to our LNG revenues through SPA contracts.
Additional information regarding our customer contracts can be found in Liquidity and generally bears project cost risk unless certain specified events occur,Capital Resources in which case Bechtel may cause CCLItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 15—Customer Concentration of our Notes to enter into a change order, or CCL agrees with Bechtel to a change order.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. ThisThese rigorous regulatory requirement mayrequirements increase the cost of constructingconstruction and operating the Liquefaction Project,operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations. Any development of additional Trains, pipelines and other related facilities will require a similar permitting process.
Federal Energy Regulatory Commission
The design, construction, operation, maintenance and operationexpansion of our liquefaction facilities,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.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 in interstate commercefor resale of natural gas for resale for ultimate consumption for domestic, commercial, industrial or any other use andin interstate commerce, to natural gas companies engaged in such transportation or sale. However, the FERC’s jurisdiction does not extendsale and to the production, gathering, local distribution or exportconstruction, operation, maintenance and expansion of LNG terminals and interstate natural gas.gas pipelines.
•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;
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•the initiation and discontinuation of services; and
•various other matters.
We are permitted to make sales of facilities usednatural 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 authorizing the provision of services.state regulation.
In order to site, construct and operate the Corpus Christi LNG terminal,Liquefaction Project, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as several other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”“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, although except asunless specifically provided otherwise in the EPAct amendments to the NGA. For example, nothing in the EPAct isamendments to the NGA were intended to affect otherwise applicable law related to any other federal or state agency’s authorities or responsibilities related to LNG terminals.terminals or those of a state acting under federal law.
In December 2014, the FERC issuedMarch 2023, CCL and another subsidiary of Cheniere submitted an order granting CCL authorization under Section 3 of the NGA to site, construct and operate Stage 1 and Stage 2 of the Liquefaction Project and issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing CCP to construct and operate the Corpus Christi Pipeline (the “December 2014 Order”). A party to the proceeding requested a rehearing of the December 2014 Order, and in May 2015, the FERC denied rehearing (the “Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review the December 2014 Order and the Order Denying Rehearing, and that petition was denied on November 4, 2016.
The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. Interstate pipelines must treat all transmission customers on a not unduly discriminatory basis. 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.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 the Liquefaction Project. In addition, the December 2014 Order requires us to obtain certain additionalour FERC construction, operation, reporting, accounting and other regulatory agency approvals as construction progresses. To date, we have been able to obtain these approvals as needed and the need for these approvals has not materially affected our construction progress. Throughout the life of the Liquefaction Project, we will beregulated activities are subject to regular reporting requirements toaudit by the FERC, the U.S. Department of Transportation’s (“DOT”) Pipelinewhich may conduct routine or special inspections and Hazardous Materials Safety Administration (“PHMSA”)issue data requests designed to ensure compliance with FERC rules, regulations, policies and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities.
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 accordanceaddition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the EPAct,life of the Liquefaction Project. For example, throughout the life of the Liquefaction Project, we are subject to regular reporting requirements to the FERC, issued a final rule under the NGA making it unlawfulDepartment 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 any entity, in connection with the purchasethese approvals and reporting obligations has not materially affected our construction or saleoperations.
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DOE Export Licenses
The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG terminalTerminal, as discussed inOur Liquefaction Project. 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.
Pipeline and Hazardous MaterialMaterials Safety Administration
The Corpus Christi PipelineLiquefaction Project is also subject to regulation by PHMSA, who is authorized by the PHMSA, pursuantapplicable pipeline safety laws to which theestablish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established requirements relatingare applicable to the design, installation, testing, construction, operation, replacementmaintenance and management of pipeline facilities.
PHMSA performs inspections of the pipeline and its protective coating. Testing consistsLNG facilities and has authority to undertake enforcement actions, including issuance of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for gas transportation pipelines, which require pipeline operators to perform ongoing assessments of pipeline integrity; 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 preventive and mitigation actions.
violations.
Other Governmental Permits, Approvals and Authorizations
Commodity Futures Trading Commission (“(“CFTC”)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank“Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.those markets. The regulatory regime created byCFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, is designed primarily to (1) regulate certain participants inincluding the swaps markets, including entities falling withinspeculative position limit rules. Given the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of standardized swaps of certain classes as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authorityenactment of the CFTCspeculative position limit rules, as well as the impact of other rules and the SEC regarding the derivatives markets. As required byregulations under the Dodd-Frank Act, the CFTC, the SEC and other regulators have been promulgatingimpact of such rules and regulations implementing the regulatory provisions of the Dodd-Frank Act. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTCon our business continues to review and refine its rulemakings through additional interpretations and supplemental rulemakings.
material.
As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators havealso adopted rules to require Swap Dealers and Major Swap Participants,requiring swap dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation
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margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules which, as to the collection of initial margin, are being phased in, do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.
Environmental Regulation
The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations require significant expenditures for compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution.pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
Clean Air Act (“CAA”)
The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. 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 however, that our operations, or the construction and operations of our liquefaction facilities,Liquefaction Project will be materially and adversely affected by any such requirements.regulatory actions.
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory action to monitor and/or reduceOn 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 of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not possible at this time to predict how future regulations or legislation may addressabove 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 impact our business. However, future regulationsincreasing to $1,500 per metric ton in 2026 and laws could result in increased compliance costs or additional operating restrictionsbeyond. In January 2024, the EPA issued a proposed rule to impose and couldcollect the methane emissions charge authorized under the IRA. We do not believe the methane charge to have a material adverse effect on our business, contracts,operations, financial condition operatingor results cash flow, liquidity and prospects.of operations.
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Coastal Zone Management Act (“(“CZMA”)
Clean Water Act (“CWA”)
The Liquefaction Project is subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in 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. In the eventWhen such wastes are generated in connection with the operations of our facilities, we will beare subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.
Protection of Species, Habitats and Wetlands
Various federal and state statutes, such as the Endangered Species Act, the 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 theour Liquefaction Project or the Corpus Cristi Pipeline may adversely affectaffects 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
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
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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, currently does not experience competitionas 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 Trains 1 and 2. We have entered into eight fixed pricethe contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes.
Competition
Despite the long term nature of our SPAs, with terms of at least 20 years (plus extension rights) with seven third parties that will utilize substantially all of the liquefaction capacity available from these Trains. Each customer will be requiredwhen CCL needs to pay an escalating fixed fee for its annual contract quantity even if it elects not to purchase any LNG from us.
liquefaction facilitiesfacility in Cameron Parish, Louisiana and has entered into six fixed price, 20-year third-party SPAs for the sale of LNG from these natural gas liquefaction facilities, and may continue to enter into commercial agreements with respect to this natural gas liquefaction facility that might otherwise have been entered into with respect to Train 3.(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
Cheniere’s climate strategy is to measure and mitigate emissions – to better position our LNG will increase by 65%, from approximately 255 mtpa, or 12.2 Tcf, in 2016,supplies to approximately 422 mtpa, or 20.3 Tcf, in 2025 and that LNG production from existing facilities and new facilities already under construction will be able to supply the market with approximately 386 mtpa in 2025, resultingremain competitive in a market need for construction of additional facilities capable of producing an incremental 36.4 mtpa of LNG. We believelower carbon future, providing energy, economic and environmental security to our new project that does not already have capacity sold under long-term contracts is competitive with new proposed projects globally and is well-positioned to capture a portion of this incremental market need.
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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 salecustomers in June 2022, and purchase agreements. These agreements contain fixed fees that are requiredin 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 be paid even ifclimate initiatives, including capital expenditures, were not material to our Consolidated Financial Statements during the customers electyears ended December 31, 2023, 2022 and 2021. However, as governments consider and implement actions to cancel or suspend deliveryreduce 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 LNG cargoes. To date,our future climate and sustainability initiatives to evolve accordingly. While we have contracted an aggregate amountnot incurred material direct expenditures related to climate change, we are proactive in our management of LNG that is between approximately 85%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 95% of the expected aggregate adjusted nominal production capacity of Trains 1 and 2 of the Liquefaction Project with third-party customers. As of January 31, 2018, U.S. natural gas prices indicate that LNG exported from the U.S. continuessevere weather events or changes in weather patterns, in addition to be competitively priced, supporting the opportunitytransition risks. Please see Item 1A. Risk Factors for U.S. LNG to fill uncontracted future demand through the execution of long-term, medium-term and short-term contracting of LNG from our terminal.additional discussion.
Subsidiaries
Employees
We have no employees. We have contracts with subsidiaries of Cheniere and its subsidiaries 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 JanuaryDecember 31, 2018,2023, Cheniere and its subsidiaries had 1,2301,605 full-time employees, including 231412 employees who directly supported the Liquefaction Project.
Available Information
Our principal executive offices are located at 700 Milam Street,845 Texas Avenue, Suite 1900,1250, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We electronically fileprovide 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, the SEC. The public may read and copy anyor furnish those materials we file withto, the SEC atunder the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549.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 public may obtain information on the operation of the Public Reference Roomwebsite should not be relied upon for investment purposes and is not incorporated by calling the SEC at 1-800-SEC-0330.reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers, like us, that file electronically with the SEC.issuers.
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. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flow,flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
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Risks Relating to Our Financial Matters
As of December 31, 2017,2023, we had zero$175 million of restricted cash and cash equivalents, $226.6 million$4.6 billion of current restricted cashavailable commitments under our credit facilities and $6.7$6.4 billion of total debt outstanding on a consolidated basis (before unamortized discount and debt issuance costs), excluding $163.6 million of outstanding letters of credit.. We incur, and will incur significant interest expense relating to financing the assets at the Liquefaction Project,Corpus Christi LNG Terminal and we anticipate needing to incurincurring additional debt and debt related interest expense to finance the construction of Train 3.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 as well asand the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, 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 or equity offerings 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 on theupon performance upon satisfactionby our customers to make payments under long-term contracts. As of the conditions precedent to payment thereunder, by six third-party customers that have entered intoDecember 31, 2023, we had SPAs with us and agreed to pay us an aggregatea total of 15 different third party customers.
Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we must seek recoursefail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs upon the occurrence of certain events of force majeure.
Although we have not had a guaranty. If anyhistory of material customer failsdefault or termination events, the occurrence of such events are largely outside of our control and may expose us to perform its obligations under its SPA,unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the SPA.affected.
Our use of hedging arrangements may adversely affect our future operating results or 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.
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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 hedge riskspotentially 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 businessConsolidated 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 cash flows.
Disruptions to the future sale of our LNG inventory and to price risk attributable to future purchasesthird party supply of natural gas to be utilized as fuel to operate our LNG terminals and to secure natural gas feedstock for our liquefaction facilities.
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We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of sufficient quantitiesnatural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of natural gas to satisfy those obligations, which mayour 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 affected SPA customers withcertain 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 rightcriticality of natural gas supply to terminate their SPAs. Ourour 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.
Significant increases in the cost of a lossliquefaction project beyond the amounts that we estimate could impact the commercial viability of key personnelthe 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
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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 business.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
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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
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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
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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 JanuaryDecember 31, 2018,2023, Cheniere and its subsidiaries had 1,2301,605 full-time employees, including 231412 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 liquefactionour facilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing,operating, including the Sabine Pass LiquefactionSPL Project, for the time and expertise of Cheniere’s personnel. Further, we and Cheniere facefaces competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.
Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our ability to engage, and Cheniere’s ability to attract and retain, additional qualified personnel.
A shortage in the labor pool of skilled workers, or otherremoteness of our site locations, general inflationary pressures, or changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. 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.affiliates, including Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of affiliatesCheniere’s affiliates. All of Cheniere. In addition, Cheniere Marketing has entered into an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers. Thesethese agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, CheniereSPL is currently operating the SPL Project and its affiliates are developing the Sabine Pass Liquefaction Project in Cameron Parish, Louisiana, and is developing additional Trains and related facilities and a second natural gas pipeline at a sitean expansion project adjacent to the LiquefactionSPL 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 these projectsthis liquefaction facility that might otherwise have been entered into with respect to Train 3 or another expansionany of the Liquefaction Project and may require that we transfer and/or amend permits and other authorizations we have received to enable them to be used by such projects.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. We anticipatearrangements that we will enter into other such agreements in the future, which cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates willmay be necessary or desirable, additional conflicts of interest will be involved.
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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 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 usobtain and maintain approvals and permits 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, liquiditygovernmental and prospects. Factors which may negatively affect potential demand for LNG from our liquefaction projects are diverse and include, among others:
The design, construction and operation of interstate natural gas pipelines, our LNG terminal, including the capacity onLiquefaction Project, the Corpus Christi PipelineMidscale 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 interconnecting pipelines may not be sufficientCWA, are required in order to accommodate any additional Trains. Developmentconstruct 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 any additional Trains will require us to secure additional pipeline transportation capacity but we may not be able to do so on commercially reasonable terms or at all.
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 an LNG facility takes a number1978 (the “NGPA”). The FERC regulates the purchase and transportation of years, requires a substantial capital investmentnatural gas in interstate commerce, including the construction and mayoperation 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 delayed by factors such as:
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 availability of sufficient financing for LNG projects on commercially reasonable terms;
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Although the vessels could be delayedFERC has not imposed fines or penalties on us to the detriment of our businessdate, we are exposed to substantial penalties and our customers because of: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 that regulateapplicable to our construction and restrict,operation activities relating to, among other things, discharges to air landquality, water quality, waste management, natural resources, and water, with particular respect to the protection of the environmenthealth and natural resources; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances.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 environmental laws and regulations authorize regulators having jurisdiction over the Corpus Christi LNGconstruction and operation of our terminal, marine berths and pipeline, including FERC, PHMSA, EPA and the United States Coast Guard, to issue compliance orders,regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, difficulty obtaining and maintaining permits from regulatory agencies or toincreased capital expenditures related to pollution control equipment 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.
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
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costs or restrictions could have ana material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The PHMSA requires pipeline operators to our lackdevelop 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 assetpipeline safety and geographic diversification, an adverse development atcompliance;
•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 Liquefaction Facility, the Corpus Christi Pipeline,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 in the LNG industry would have a significantly greater impact on our financial conditionmitigating actions may require significant capital and operating results than ifexpenditures. Should we maintained more diverse assetsfail to comply with applicable statutes and operating areas.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
Cyberattacks represent a potentially significant risk to the Company and our industry. We rely on subsidiaries of Cheniere through our service agreements with them, as further discussed in Note 13—Related Party Transactions of our Notes to Consolidated Financial Statements, and Cheniere’s board of directors (the “Board”), which has oversight of our operations, to implement policies and procedures that are intended to manage and reduce this risk.
Risk Management and Strategy As part of its broader approach to risk management, Cheniere’s cybersecurity program is designed to follow an “identify, protect, detect, respond and recover” approach to cybersecurity that is based off of the National Institute of Standards and Technology Cybersecurity Framework (“CSF”). Cheniere’s strategy also includes segmentation of corporate and operations networks, defense in depth and the least privileged access principle. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, Cheniere routinely evaluates opportunities to refine its cybersecurity program in order to mitigate operational network risks. Cheniere includes business continuity planning as a component of its strategy to help ensure critical systems are available to support the Company in the instance of a disruptive event. Cheniere also participates in various industry organizations to stay abreast of recent trends and developments. On an ongoing basis, Cheniere assesses its people, processes and technology and, when necessary, adjusts the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. Cheniere conducts regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance Cheniere’s Cyber Incident Response Plan. To support these efforts, Cheniere has contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems, and security maturity assessments of its corporate and operational networks. Cheniere maintains a training program to help its personnel identify and assist in mitigating cybersecurity and data security risks. Cheniere’s employees and the members of the Board participate in annual training, user awareness campaigns and additional issue-specific training as needed. Cheniere also provides annual training for certain contractors who have access to its information technology networks. 22 With respect to third party service providers, Cheniere’s information security program includes conducting risk-based due diligence of certain service providers’ information security programs prior to onboarding. Cheniere strives to contractually require third party service providers with access to its information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use Cheniere’s data, including personal information, for purposes other than to provide services to them, except as required by applicable law. Cheniere also strives to negotiate contractual requirements which compel its service providers to notify them of information security incidents occurring on their systems which may affect Cheniere’s systems or data, including personal information. During the year ended December 31, 2023, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition. Governance We rely on Cheniere’s cybersecurity leadership team, which consists of its Director and Chief Information Security Officer (“CISO”), Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of Cheniere’s cybersecurity governance, cyber risk management and security operations and are responsible for maintaining Cheniere’s technology defense posture and program. They have decades of experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats. Cheniere’s CISO’s experience includes assessing risks, implementing governance programs, and responding to threats in oil and gas, electric and natural gas utilities and nuclear power generation companies. He maintains a Certified Information Security Manager certification from ISACA, secret clearance from the Department of Homeland Security and has played an active role in the development of various cybersecurity standards including the CSF. Risks that could affect us are an integral part of Cheniere’s Board and Audit Committee deliberations throughout the year. Cybersecurity risks are integrated into Cheniere’s enterprise risk assessment process, which is reviewed by Cheniere’s Board at least annually. Cheniere’s Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while Cheniere’s Audit Committee has been delegated the authority to oversee and periodically review the security of Cheniere’s information technology systems and controls, including programs and defenses against cybersecurity threats. Cheniere’s Audit Committee discusses with Cheniere’s management its cybersecurity risk exposures and the steps Cheniere’s management has taken to mitigate such exposures, including its risk assessment and risk management policies. On a quarterly basis, Cheniere’s cybersecurity leadership team updates Cheniere’s Audit Committee on the overall status of its cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity. For additional information about cybersecurity risks, see the risk 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 under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors. 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.
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Not applicable.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| Year Ended December 31, | ||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
| Revenues | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
| Loss from operations | (19,161 | ) | (6,472 | ) | (23,044 | ) | (38,235 | ) | (32,849 | ) | ||||||||||
| Other expense | (29,491 | ) | (79,015 | ) | (204,053 | ) | (368 | ) | (378 | ) | ||||||||||
| Net loss | (48,652 | ) | (85,487 | ) | (227,097 | ) | (38,603 | ) | (33,227 | ) | ||||||||||
| December 31, | ||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | |||||||||||||
| Property, plant and equipment, net | $ | 8,261,383 | $ | 6,076,672 | $ | 3,924,551 | $ | 44,173 | ||||||||
| Total assets | 8,659,880 | 6,636,448 | 4,304,042 | 68,030 | ||||||||||||
| Long-term debt, net | 6,669,476 | 5,081,715 | 2,713,000 | — | ||||||||||||
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
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.
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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
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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 | |||||||||||||||||||||||||||||
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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 billionbetween the periods, of which $7.7 billionrelated 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
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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 Liquefaction Project is being developedfollowing information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The first stage (“Stage 1”) includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the Liquefaction Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, one LNG storage tankshort term and the completionlong 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 second partial berth. caption Future Sources and Uses of Liquidity.
Supplemental Guarantor Information
The Liquefaction Project also includes the Corpus Christi Pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines. Stage 1 and the Corpus Christi Pipeline are currently under construction, and Train 3 is being commercialized and has all necessary regulatory approvals in place. Construction of the Corpus Christi Pipeline is nearing completion.
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 offeringcapital stock or the assets of approximately $1.4 billion, after deducting commissions,
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
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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 credit facility (the “2015 CCH Credit Facility”).Consolidated Financial Statements.
The following table provides a summarysummarizes 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 position atincludes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 20172023. Estimates are not guarantees of future performance and 2016 (in thousands):actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
| December 31, | |||||||
| 2017 | 2016 | ||||||
| Cash and cash equivalents | $ | — | $ | — | |||
| Restricted cash designated for the Liquefaction Project | 226,559 | 270,540 | |||||
| Available commitments under the following credit facilities: | |||||||
| 2015 CCH Credit Facility | 2,086,714 | 3,602,714 | |||||
| $350 million CCH Working Capital Facility (“CCH Working Capital Facility”) | 186,422 | 350,000 | |||||
| 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.
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(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 being developed and constructedcomprised 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. In December 2014, we received authorization fromTerminal) or a DAT basis (delivered to the FERC to site, construct and operate Stages 1 and 2 of the Liquefaction Project. The following table summarizes the overall project status of Stage 1 of the Liquefaction Project as of December 31, 2017:
In aggregate, the annual fixed fee portion to be paid by the third-partythird party SPA customers is approximately $550 million$2.7 billion for Train 1, increasingthe 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 $1.4Consolidated 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 uponin available commitments under our credit facilities, subject to compliance with the datecovenants, 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 firstCheniere 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 deliveryand financing arrangements before a positive FID is made.
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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 the applicable fixed fees generally starting from the date of first commercial delivery from the applicable Train.
To ensure CCL isthat we are able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it hasTerminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity withfrom CCP and certain third-partythird party
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interstate and intrastate pipeline companies. CCL hasWe have also entered into a firm storage services agreementagreements with a third partyparties to assist in managing volatilityvariability in natural gas needs for the Liquefaction Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to
Capital Expenditures
We enter into such agreements, in order to secure natural gas feedstock for the Liquefaction Project. We expect to enter into gas supply contracts under these enabling agreements as and when required for the Liquefaction Project. As of December 31, 2017, CCL has secured up to approximately 2,024 TBtu of natural gas feedstock through long-term natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.
The following table summarizes the project completion and the Corpus Christi Pipeline are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $11.0 billion and $12.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies and total expected capital costs for the Corpus Christi Pipeline of between $350 million and $400 million. The total contract price of the EPC contract for Stage 2, which was amended and restated in December 2017, is approximately $2.4 billion.
| 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 is nearing completion.Capital Expenditures
We will contemplate making an FID to commence constructionhave contracts with subsidiaries of Stage 2Cheniere 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 based upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct the facility.
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Senior notes (1) | $ | 4,250,000 | $ | 2,750,000 | ||||
| Credit facilities outstanding balance (2) | 2,484,737 | 2,380,788 | ||||||
| Letters of credit issued (2) | 163,578 | — | ||||||
| Available commitments under credit facilities (2) | 2,273,136 | 3,952,714 | ||||||
| Total capital resources from borrowings and available commitments | $ | 9,171,451 | $ | 9,083,502 | ||||
The indenture governingFID of any expansion projects will result in additional cash requirements to fund the CCH Senior Notes (the “CCH Indenture”) contains customary termsconstruction and eventsoperations of default and certain covenants that, among other things, limit our ability and the abilitysuch projects in excess of our restricted subsidiaries to: incur additional indebtedness or issue preferred stock;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.
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Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of our restricted subsidiaries; restrict dividendscontracts. 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 otherestimated forward interest rates in effect at December 31, 2023. Debt and interest payments by restricted subsidiaries to us or any of our restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of usdo not contemplate repurchases, repayments and our restricted subsidiaries taken as a whole; or permit any Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.
Additional Future Cash Requirements for Financing
Capital Allocation Plan
In September 2022, the board of directors of Cheniere approved a $58.9 million reduction torevised long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including our U.S. net deferred tax assets and represents a 121.1% decrease to our effective tax rate. A corresponding change, reducing the effective tax rate, was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.senior notes.
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 | |||||||||||||||||||||||||||||
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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 billionbetween the periods, of which $7.7 billionrelated 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
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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
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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 our cash, cash equivalentsliquidity includes estimates that reflect management’s assumptions and restricted cash for the years endedcurrently known market conditions and other factors as of December 31, 2017, 20162023. Estimates are not guarantees of future performance and 2015actual 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 thousands).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 table presents capital expenditurestiming 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 cash basis; therefore, these amounts differcertain 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.
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(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 amountsLiquefaction Project, with approximately 17 years of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussionweighted average remaining life as of these items follows the table.
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Operating cash flows | $ | (64,316 | ) | $ | (41,079 | ) | $ | (107,202 | ) | ||
| Investing cash flows | (1,962,209 | ) | (2,095,897 | ) | (3,839,415 | ) | |||||
| Financing cash flows | 1,982,544 | 2,360,746 | 3,993,387 | ||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | (43,981 | ) | 223,770 | 46,770 | |||||||
| Cash, cash equivalents and restricted cash—beginning of period | 270,540 | 46,770 | — | ||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 226,559 | $ | 270,540 | $ | 46,770 | |||||
In addition to cash outflowsthe 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 construction costsSPAs associated with IPM agreements for the Liquefaction Project, we received $36.3 million during the year endedwhich pricing is linked to international natural gas prices.
Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2017 from2023, we had $4.6 billion in available commitments under our credit facilities, subject to compliance with the returncovenants, 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 collateral payments previously paid forCheniere submitted an application with the Liquefaction Project, which was offset by $11.3 million paid for infrastructure to support the Liquefaction Project. During the year ended December 31, 2016, we used an additional $44.4 million primarily for infrastructure of the Liquefaction Project, which included the $36.3 million of collateral payments that were returned to us during the year ended December 31, 2017.
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Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts
We are committed to make future cash payments in the futurefor operations and capital expenditures pursuant to certain of our contracts. The following table summarizes certain contractual obligations in placeour estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 20172023 (in thousands)billions):
| Payments Due By Period (1) | ||||||||||||||||||||
| Total | 2018 | 2019 - 2020 | 2021 - 2022 | Thereafter | ||||||||||||||||
| Debt (2) | $ | 6,734,737 | $ | — | $ | — | $ | 2,484,737 | $ | 4,250,000 | ||||||||||
| Interest payments (2) | 2,476,865 | 372,651 | 750,493 | 678,252 | 675,469 | |||||||||||||||
| Construction obligations (3) | 1,203,076 | 831,636 | 371,440 | — | — | |||||||||||||||
| Purchase obligations (4) | 24,352 | 22,936 | 1,416 | — | — | |||||||||||||||
| Operating lease obligations (5) | 1,981 | 895 | 1,086 | — | — | |||||||||||||||
| Obligations to affiliates (6) | 1,098 | 357 | 654 | 87 | — | |||||||||||||||
| Other obligations (7) | 120,915 | 3,000 | 36,493 | 53,989 | 27,433 | |||||||||||||||
| Total | $ | 10,563,024 | $ | 1,231,475 | $ | 1,161,582 | $ | 3,217,065 | $ | 4,952,902 | ||||||||||
| 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 |
(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 maintain lettershave 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 creditnatural 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 cash restricted in supportcosts incurred by us. While our IPM agreements are not revenue contracts for accounting purposes, the payment structure for the purchase of certain performance obligations of our subsidiaries. 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, 2017,2023, 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
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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 ofDecember 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 $163.61,605 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.
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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 and $226.6 millionas of current restricted cash. For more information, see Note 3—RestrictedDecember 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 Notes to Consolidated Financial Statements.senior notes.
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 | |||||||||||||||||||||||||||||
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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 billionbetween the periods, of which $7.7 billionrelated 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 lossincome (loss) by line item:
Revenues
Substantially all of the $3.9 billion decrease between the years ended December 31, 2023 and 2022 was $48.7 millionattributable 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, 2017, compared2022 to a net loss$5.8 billion of $85.5 milliongain in the year ended December 31, 2016. This $36.82023 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 lossof 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 2017Sources 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
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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
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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.
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(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.
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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
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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 ofDecember 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.
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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 loss on early extinguishmentHenry Hub pricing, which was largely offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.
33
Investing Cash Flows
Our consolidatedinvesting net loss was $227.1cash outflows in both years primarily were for the construction costs for the Liquefaction Project. The $742 million increase in the year ended December 31, 2015. This $141.6 million decrease in net loss in 20162023 compared to 20152022 was primarily a resultdue to $1.5 billion of decreased derivative loss, net and decreased interest expense, net of amounts capitalized, which were partially offset by increased loss on early extinguishment of debt.
| Year Ended December 31, | ||||||||||||||||||||
| (in thousands) | 2017 | 2016 | Change | 2015 | Change | |||||||||||||||
| Revenues | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
| Operating and maintenance expense | 3,115 | 1,372 | 1,743 | 572 | 800 | |||||||||||||||
| Operating and maintenance expense—affiliate | 2,401 | 95 | 2,306 | — | 95 | |||||||||||||||
| Development expense (recovery) | 516 | (81 | ) | 597 | 13,690 | (13,771 | ) | |||||||||||||
| Development expense (recovery)—affiliate | 8 | (10 | ) | 18 | 5,525 | (5,535 | ) | |||||||||||||
| General and administrative expense | 5,551 | 4,240 | 1,311 | 3,189 | 1,051 | |||||||||||||||
| General and administrative expense—affiliate | 1,173 | 607 | 566 | 13 | 594 | |||||||||||||||
| Depreciation and amortization expense | 892 | 249 | 643 | 55 | 194 | |||||||||||||||
| Impairment expense and loss on disposal of assets | 5,505 | — | 5,505 | — | — | |||||||||||||||
| Loss from operations | $ | (19,161 | ) | $ | (6,472 | ) | $ | (12,689 | ) | $ | (23,044 | ) | $ | (16,572 | ) | |||||
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, 2016 primarily as a result2022, we had $440 million of increased operating and maintenance expense and general and administrative expensedebt issuances from increased professional fees and labor costs.
Repayments and Related Extinguishment Costs
The following table shows the yearrepayments 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, 20162023 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 as a result of decreased development expenses from decreased professional feespay down our outstanding debt, and labor costs.
| Year Ended December 31, | ||||||||||||||||||||
| (in thousands) | 2017 | 2016 | Change | 2015 | Change | |||||||||||||||
| Interest expense, net of capitalized interest | $ | — | $ | — | $ | — | $ | 25,680 | $ | (25,680 | ) | |||||||||
| Loss on early extinguishment of debt | 32,480 | 63,318 | (30,838 | ) | 16,498 | 46,820 | ||||||||||||||
| Derivative loss (gain), net | (3,249 | ) | 15,571 | (18,820 | ) | 161,917 | (146,346 | ) | ||||||||||||
| Other expense (income) | 260 | 126 | 134 | (42 | ) | 168 | ||||||||||||||
| Total other expense (income) | $ | 29,491 | $ | 79,015 | $ | (49,524 | ) | $ | 204,053 | $ | (125,038 | ) | ||||||||
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, properties, plant and equipment and income taxes.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.
All of our derivative instruments are recorded at fair value.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
34
through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market.
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 thatfor 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 unobservablelimited 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 marketplace, market transactionsestimated and other relevant data.observable forward international LNG commodity prices on our IPM agreements during the years ended December 31, 2023 and 2022.
The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as interest rates andit relates to commodity prices change.
Recent Accounting Standards
For a summary of the asset to the expected undiscounted future cash flowsrecently issued accounting standards, see Note 2—Summary 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 use a variety of fair value measurement approaches when market information for the same or similar assets does not exist. Projections of future operating results and cash flows may vary significantly from results. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
| 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 | |||||||||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||
| Fair Value | Change in Fair Value | Fair Value | Change in Fair Value | ||||||||||||
| Liquefaction Supply Derivatives | $ | (91 | ) | $ | 10 | $ | — | $ | — | ||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||
| Fair Value | Change in Fair Value | Fair Value | Change in Fair Value | ||||||||||||
| Interest Rate Derivatives | $ | (32,258 | ) | $ | 43,994 | $ | (86,488 | ) | $ | 52,047 | |||||
See Note 5—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
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
37
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, 2017,2023, 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 Sabine Pass Liquefaction’sCheniere Corpus Christi Holdings’ Form 10-K.
| By: | /s/ Zach Davis | ||||||||
| Zach Davis | |||||||||
| President and Chief Financial Officer (Principal Executive and Financial Officer) | |||||||||
38
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, 20172023 and 2016,2022, 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, 2017,2023, 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, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2023, 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,
39
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 20, 201821, 2024
40
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.
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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)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 | ||||||||||||
| Member’s equity | 8,532 | 1,084 | ||||||||||||
| Total liabilities and member’s equity | $ | 16,976 | $ | 15,687 | ||||||||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | — | $ | — | ||||
| Restricted cash | 226,559 | 197,201 | ||||||
| Advances to affiliate | 31,486 | 20,108 | ||||||
| Other current assets | 1,494 | 37,195 | ||||||
| Other current assets—affiliate | 190 | 141 | ||||||
| Total current assets | 259,729 | 254,645 | ||||||
| Non-current restricted cash | — | 73,339 | ||||||
| Property, plant and equipment, net | 8,261,383 | 6,076,672 | ||||||
| Debt issuance and deferred financing costs, net | 98,175 | 155,847 | ||||||
| Non-current advances under long-term contracts | — | 46,398 | ||||||
| Other non-current assets, net | 40,593 | 29,547 | ||||||
| Total assets | $ | 8,659,880 | $ | 6,636,448 | ||||
| LIABILITIES AND MEMBER’S EQUITY | ||||||||
| Current liabilities | ||||||||
| Accounts payable | $ | 6,461 | $ | 9,120 | ||||
| Accrued liabilities | 258,060 | 137,648 | ||||||
| Due to affiliates | 23,789 | 7,050 | ||||||
| Derivative liabilities | 19,609 | 43,383 | ||||||
| Total current liabilities | 307,919 | 197,201 | ||||||
| Long-term debt, net | 6,669,476 | 5,081,715 | ||||||
| Non-current derivative liabilities | 15,209 | 43,105 | ||||||
| Other non-current liabilities—affiliate | — | 618 | ||||||
| Commitments and contingencies (see Note 11) | ||||||||
| Member’s equity | 1,667,276 | 1,313,809 | ||||||
| Total liabilities and member’s equity | $ | 8,659,880 | $ | 6,636,448 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Revenues | $ | — | $ | — | $ | — | |||||
| Expenses | |||||||||||
| Operating and maintenance expense | 3,115 | 1,372 | 572 | ||||||||
| Operating and maintenance expense—affiliate | 2,401 | 95 | — | ||||||||
| Development expense (recovery) | 516 | (81 | ) | 13,690 | |||||||
| Development expense (recovery)—affiliate | 8 | (10 | ) | 5,525 | |||||||
| General and administrative expense | 5,551 | 4,240 | 3,189 | ||||||||
| General and administrative expense—affiliate | 1,173 | 607 | 13 | ||||||||
| Depreciation and amortization expense | 892 | 249 | 55 | ||||||||
| Impairment expense and loss on disposal of assets | 5,505 | — | — | ||||||||
| Total expenses | 19,161 | 6,472 | 23,044 | ||||||||
| Loss from operations | (19,161 | ) | (6,472 | ) | (23,044 | ) | |||||
| Other income (expense) | |||||||||||
| Interest expense, net of capitalized interest | — | — | (25,680 | ) | |||||||
| Loss on early extinguishment of debt | (32,480 | ) | (63,318 | ) | (16,498 | ) | |||||
| Derivative gain (loss), net | 3,249 | (15,571 | ) | (161,917 | ) | ||||||
| Other income (expense) | (260 | ) | (126 | ) | 42 | ||||||
| Total other expense | (29,491 | ) | (79,015 | ) | (204,053 | ) | |||||
| Net loss | $ | (48,652 | ) | $ | (85,487 | ) | $ | (227,097 | ) | ||
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(in thousands)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 | |||||||||
| (1,482) | (1,482) | ||||||||||
| 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 | |||||||||
| 398 | 398 | ||||||||||
| Distributions | (280) | (280) | |||||||||
| Net income | 7,150 | 7,150 | |||||||||
| Balance at December 31, 2023 | $ | 8,532 | $ | 8,532 | |||||||
| Cheniere CCH HoldCo I, LLC | Total Member’s Equity | ||||||
| Balance at December 31, 2014 | $ | 65,532 | $ | 65,532 | |||
| Capital contributions | 1,560,915 | 1,560,915 | |||||
| Net loss | (227,097 | ) | (227,097 | ) | |||
| Balance at December 31, 2015 | 1,399,350 | 1,399,350 | |||||
| Capital contributions | 91 | 91 | |||||
| Noncash capital contribution from affiliate | 143 | 143 | |||||
| Distribution to affiliate | (288 | ) | (288 | ) | |||
| Net loss | (85,487 | ) | (85,487 | ) | |||
| Balance at December 31, 2016 | 1,313,809 | 1,313,809 | |||||
| Capital contributions | 402,119 | 402,119 | |||||
| Net loss | (48,652 | ) | (48,652 | ) | |||
| Balance at December 31, 2017 | $ | 1,667,276 | $ | 1,667,276 | |||
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 thousands)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 | |||||||||||
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Cash flows from operating activities | |||||||||||
| Net loss | $ | (48,652 | ) | $ | (85,487 | ) | $ | (227,097 | ) | ||
| Adjustments to reconcile net loss to net cash used in operating activities: | |||||||||||
| Depreciation and amortization expense | 892 | 249 | 55 | ||||||||
| Amortization of debt issuance costs, net of capitalization | — | — | 6,340 | ||||||||
| Loss on early extinguishment of debt | 32,480 | 63,318 | 16,498 | ||||||||
| Total losses (gains) on derivatives, net | (3,158 | ) | 15,571 | 161,917 | |||||||
| Net cash used for settlement of derivative instruments | (50,981 | ) | (34,082 | ) | (56,918 | ) | |||||
| Impairment expense and loss on disposal of assets | 5,505 | — | — | ||||||||
| Changes in operating assets and liabilities: | |||||||||||
| Accounts payable and accrued liabilities | 152 | 415 | 1,002 | ||||||||
| Due to affiliates | 1,567 | (331 | ) | 275 | |||||||
| Advances to affiliate | — | — | (10,073 | ) | |||||||
| Other, net | (1,454 | ) | (745 | ) | 301 | ||||||
| Other, net—affiliate | (667 | ) | 13 | 498 | |||||||
| Net cash used in operating activities | (64,316 | ) | (41,079 | ) | (107,202 | ) | |||||
| Cash flows from investing activities | |||||||||||
| Property, plant and equipment, net | (1,987,254 | ) | (2,051,530 | ) | (3,820,947 | ) | |||||
| Other | 25,045 | (44,367 | ) | (18,468 | ) | ||||||
| Net cash used in investing activities | (1,962,209 | ) | (2,095,897 | ) | (3,839,415 | ) | |||||
| Cash flows from financing activities | |||||||||||
| Proceeds from issuances of debt | 3,040,000 | 4,838,000 | 2,713,000 | ||||||||
| Repayments of debt | (1,436,050 | ) | (2,420,212 | ) | — | ||||||
| Debt issuance and deferred financing costs | (23,496 | ) | (56,783 | ) | (280,528 | ) | |||||
| Capital contributions | 402,119 | 91 | 1,560,915 | ||||||||
| Distributions | — | (288 | ) | — | |||||||
| Other | (29 | ) | (62 | ) | — | ||||||
| Net cash provided by financing activities | 1,982,544 | 2,360,746 | 3,993,387 | ||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | (43,981 | ) | 223,770 | 46,770 | |||||||
| Cash, cash equivalents and restricted cash—beginning of period | 270,540 | 46,770 | — | ||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 226,559 | $ | 270,540 | $ | 46,770 | |||||
| December 31, | |||||||
| 2017 | 2016 | ||||||
| Cash and cash equivalents | $ | — | $ | — | |||
| Restricted cash | 226,559 | 197,201 | |||||
| Non-current restricted cash | — | 73,339 | |||||
| Total cash, cash equivalents and restricted cash | $ | 226,559 | $ | 270,540 | |||
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
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, 1 and 2, two LNG storage tanks, one completeand marine berth and a second partial berth and all ofberths at the Liquefaction Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, oneCorpus Christi LNG storage tank and the completion of the second partial berth. Stage 1Terminal and the Corpus Christi PipelineStage 3 Project, the “Liquefaction Project”).
We are currently under construction,pursuing a certain expansion project to provide additional liquefaction capacity, and Train 3 is being commercializedwe have commenced commercialization to support the additional liquefaction capacity associated with this expansion project.
We do not have employees and has all necessary regulatory approvalsthus we have various services agreements with affiliates of Cheniere in place. Constructionthe 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 Corpus Christi Pipelineactivity 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 nearing completion.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 wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
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 thefair value measurements of derivatives and other instruments useful lives of property, plant and equipment derivative instruments,and certain valuations including asset retirement obligations (“(“AROs”), income taxes including valuation allowances for deferred tax assets and fair value measurements.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 other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability.liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market
45
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 theour use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for interest rate derivativesderivative instruments as disclosed in Note 5—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. DebtThe fair values, as disclosed in Note 7—Debt,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 quoted market pricespast 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 identical instruments, if available, or based on valuationscertain 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 similar debt instruments using observable or unobservable inputs.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.
46
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Generally, we begin capitalizing the costs of our LNG terminal and related pipeline 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 front-end engineeringpreliminary review and design work,selection of equipment alternatives, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminal and related pipeline.terminal.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease optionacquisition costs, that are capitalized as property, plant and equipmentdetailed engineering design work and certain permits that are capitalized as other non-current assets. The
We realize offsets to LNG terminal costs for sales of lease options are amortized overcommissioning cargoes that were earned or loaded prior to the lifestart of commercial operations of the lease once obtained. If no lease is obtained, the costs are expensed.
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Current restricted cash | ||||||||
| Liquefaction Project | $ | 226,559 | $ | 197,201 | ||||
| Non-current restricted cash | ||||||||
| Liquefaction Project | $ | — | $ | 73,339 | ||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| LNG terminal costs | ||||||||
| LNG terminal construction-in-process | $ | 8,242,520 | $ | 6,060,299 | ||||
| LNG site and related costs | 13,844 | 14,006 | ||||||
| Total LNG terminal costs | 8,256,364 | 6,074,305 | ||||||
| Fixed assets | ||||||||
| Fixed assets | 6,042 | 2,620 | ||||||
| Accumulated depreciation | (1,023 | ) | (253 | ) | ||||
| Total fixed assets, net | 5,019 | 2,367 | ||||||
| Property, plant and equipment, net | $ | 8,261,383 | $ | 6,076,672 | ||||
| December 31, | ||||||||
| Balance Sheet Location | 2017 | 2016 | ||||||
| Non-current derivative assets | $ | 2,469 | $ | — | ||||
| Derivative liabilities | (19,609 | ) | (43,383 | ) | ||||
| Non-current derivative liabilities | (15,118 | ) | (43,105 | ) | ||||
| Total derivative liabilities | (34,727 | ) | (86,488 | ) | ||||
| Derivative liability, net | $ | (32,258 | ) | $ | (86,488 | ) | ||
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Interest Rate Derivatives gain (loss) | $ | 3,249 | $ | (15,571 | ) | $ | (161,917 | ) | |||
| December 31, | ||||||||
| Balance Sheet Location | 2017 | 2016 | ||||||
| Non-current derivative liabilities | $ | (91 | ) | $ | — | |||
| Year Ended December 31, | |||||||||||||
| Statement of Operations Location | 2017 | 2016 | 2015 | ||||||||||
| Liquefaction Supply Derivatives loss | Operating and maintenance expense | $ | 91 | $ | — | $ | — | ||||||
| Gross Amounts Recognized | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | ||||||||||
| Offsetting Derivative Assets (Liabilities) | ||||||||||||
| As of December 31, 2017 | ||||||||||||
| Interest Rate Derivatives | $ | 2,808 | $ | (339 | ) | $ | 2,469 | |||||
| Interest Rate Derivatives | (34,747 | ) | 20 | (34,727 | ) | |||||||
| Liquefaction Supply Derivatives | (130 | ) | 39 | (91 | ) | |||||||
| As of December 31, 2016 | ||||||||||||
| Interest Rate Derivatives | (95,923 | ) | 9,435 | (86,488 | ) | |||||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Interest costs and related debt fees | $ | 136,283 | $ | 59,994 | ||||
| Liquefaction Project costs | 107,055 | 73,150 | ||||||
| Other | 14,722 | 4,504 | ||||||
| Total accrued liabilities | $ | 258,060 | $ | 137,648 | ||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Long-term debt | ||||||||
| 7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”) | $ | 1,250,000 | $ | 1,250,000 | ||||
| 5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”) | 1,500,000 | 1,500,000 | ||||||
| 5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”) | 1,500,000 | — | ||||||
| 2015 CCH Credit Facility | 2,484,737 | 2,380,788 | ||||||
| Unamortized debt issuance costs | (65,261 | ) | (49,073 | ) | ||||
| Total long-term debt, net | 6,669,476 | 5,081,715 | ||||||
| Current debt | ||||||||
| $350 million CCH Working Capital Facility (“CCH Working Capital Facility”) | — | — | ||||||
| Total debt, net | $ | 6,669,476 | $ | 5,081,715 | ||||
| Years Ending December 31, | Principal Payments | |||
| 2018 | $ | — | ||
| 2019 | — | |||
| 2020 | — | |||
| 2021 | — | |||
| 2022 | 2,484,737 | |||
| Thereafter | 4,250,000 | |||
| Total | $ | 6,734,737 | ||
| 2015 CCH Credit Facility | CCH Working Capital Facility | |||||||
| Original facility size | $ | 8,403,714 | $ | 350,000 | ||||
| Less: | ||||||||
| Outstanding balance | 2,484,737 | — | ||||||
| Commitments terminated | 3,832,263 | — | ||||||
| Letters of credit issued | — | 163,578 | ||||||
| Available commitment | $ | 2,086,714 | $ | 186,422 | ||||
| Interest rate | LIBOR plus 2.25% or base rate plus 1.25% (1) | LIBOR plus 1.50% - 2.00% or base rate plus 0.50% - 1.00% | ||||||
| Maturity date | Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date | December 14, 2021, with various terms for underlying loans | ||||||
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Total interest cost | $ | 360,932 | $ | 221,865 | $ | 110,156 | ||||||
| Capitalized interest, including amounts capitalized as AFUDC | (360,932 | ) | (221,865 | ) | (84,476 | ) | ||||||
| Total interest expense, net | $ | — | $ | — | $ | 25,680 | ||||||
| December 31, 2017 | December 31, 2016 | |||||||||||||||
| Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||
| Senior notes (1) | $ | 4,250,000 | $ | 4,590,625 | $ | 2,750,000 | $ | 2,901,563 | ||||||||
| Credit facilities (2) | 2,484,737 | 2,484,737 | 2,380,788 | 2,380,788 | ||||||||||||
| Year Ended December 31, | |||||||||
| 2017 | 2016 | 2015 | |||||||
| U.S. federal statutory tax rate | 35.0 | % | 35.0 | % | 35.0 | % | |||
| U.S. tax reform rate change | (121.1 | )% | — | % | — | % | |||
| Other | (0.2 | )% | — | % | — | % | |||
| Valuation allowance | 86.3 | % | (35.0 | )% | (35.0 | )% | |||
| Effective tax rate | — | % | — | % | — | % | |||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Deferred tax assets | ||||||||
| Federal net operating loss carryforward | $ | 49,194 | $ | 53,618 | ||||
| Derivative instruments | 15,487 | 46,754 | ||||||
| Long-term debt | 14,270 | 15,953 | ||||||
| Property, plant and equipment | 9,143 | 13,680 | ||||||
| Other | 303 | 393 | ||||||
| Less: valuation allowance | (88,397 | ) | (130,398 | ) | ||||
| Total net deferred tax asset | $ | — | $ | — | ||||
| Years Ending December 31, | Operating Leases | ||
| 2018 | $ | 895 | |
| 2019 | 841 | ||
| 2020 | 245 | ||
| 2021 | — | ||
| 2022 | — | ||
| Thereafter | — | ||
| Total | $ | 1,981 | |
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Cash paid during the period for interest, net of amounts capitalized | $ | — | $ | — | $ | 17,456 | |||||
| Noncash capital contribution for conveyance of asset from affiliate | — | 143 | — | ||||||||
| Condensed Consolidating Balance Sheet | |||||||||||||||
| December 31, 2017 | |||||||||||||||
| (in thousands) | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| ASSETS | |||||||||||||||
| Current assets | |||||||||||||||
| Cash and cash equivalents | $ | — | $ | — | $ | — | $ | — | |||||||
| Restricted cash | 226,559 | — | — | 226,559 | |||||||||||
| Advances to affiliate | — | 31,486 | — | 31,486 | |||||||||||
| Other current assets | 246 | 1,248 | — | 1,494 | |||||||||||
| Other current assets—affiliate | — | 191 | (1 | ) | 190 | ||||||||||
| Total current assets | 226,805 | 32,925 | (1 | ) | 259,729 | ||||||||||
| Property, plant and equipment, net | 651,687 | 7,609,696 | — | 8,261,383 | |||||||||||
| Debt issuance and deferred financing costs, net | 98,175 | — | — | 98,175 | |||||||||||
| Investments in subsidiaries | 7,648,111 | — | (7,648,111 | ) | — | ||||||||||
| Other non-current assets, net | 2,469 | 38,124 | — | 40,593 | |||||||||||
| Total assets | $ | 8,627,247 | $ | 7,680,745 | $ | (7,648,112 | ) | $ | 8,659,880 | ||||||
| LIABILITIES AND MEMBER’S EQUITY | |||||||||||||||
| Current liabilities | |||||||||||||||
| Accounts payable | $ | 82 | $ | 6,379 | $ | — | $ | 6,461 | |||||||
| Accrued liabilities | 136,389 | 121,671 | — | 258,060 | |||||||||||
| Due to affiliates | — | 23,789 | — | 23,789 | |||||||||||
| Derivative liabilities | 19,609 | — | — | 19,609 | |||||||||||
| Total current liabilities | 156,080 | 151,839 | — | 307,919 | |||||||||||
| Long-term debt, net | 6,669,476 | — | — | 6,669,476 | |||||||||||
| Non-current derivative liabilities | 15,118 | 91 | — | 15,209 | |||||||||||
| Deferred tax liability | — | 2,983 | (2,983 | ) | — | ||||||||||
| Member’s equity | 1,786,573 | 7,525,832 | (7,645,129 | ) | 1,667,276 | ||||||||||
| Total liabilities and member’s equity | $ | 8,627,247 | $ | 7,680,745 | $ | (7,648,112 | ) | $ | 8,659,880 | ||||||
| Condensed Consolidating Balance Sheet | |||||||||||||||
| December 31, 2016 | |||||||||||||||
| (in thousands) | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| ASSETS | |||||||||||||||
| Current assets | |||||||||||||||
| Cash and cash equivalents | $ | — | $ | — | $ | — | $ | — | |||||||
| Restricted cash | 197,201 | — | — | 197,201 | |||||||||||
| Advances to affiliate | — | 20,108 | — | 20,108 | |||||||||||
| Other current assets | 152 | 37,043 | — | 37,195 | |||||||||||
| Other current assets—affiliate | — | 142 | (1 | ) | 141 | ||||||||||
| Total current assets | 197,353 | 57,293 | (1 | ) | 254,645 | ||||||||||
| Non-current restricted cash | 73,339 | — | — | 73,339 | |||||||||||
| Property, plant and equipment, net | 306,342 | 5,770,330 | — | 6,076,672 | |||||||||||
| Debt issuance and deferred financing costs, net | 155,847 | — | — | 155,847 | |||||||||||
| Investments in subsidiaries | 5,927,833 | — | (5,927,833 | ) | — | ||||||||||
| Non-current advances under long-term contracts | — | 46,398 | — | 46,398 | |||||||||||
| Other non-current assets, net | 50 | 29,497 | — | 29,547 | |||||||||||
| Total assets | $ | 6,660,764 | $ | 5,903,518 | $ | (5,927,834 | ) | $ | 6,636,448 | ||||||
| LIABILITIES AND MEMBER’S EQUITY | |||||||||||||||
| Current liabilities | |||||||||||||||
| Accounts payable | $ | 332 | $ | 8,788 | $ | — | $ | 9,120 | |||||||
| Accrued liabilities | 61,328 | 76,320 | — | 137,648 | |||||||||||
| Due to affiliates | — | 7,050 | — | 7,050 | |||||||||||
| Derivative liabilities | 43,383 | — | — | 43,383 | |||||||||||
| Total current liabilities | 105,043 | 92,158 | — | 197,201 | |||||||||||
| Long-term debt, net | 5,081,715 | — | — | 5,081,715 | |||||||||||
| Non-current derivative liabilities | 43,105 | — | — | 43,105 | |||||||||||
| Other non-current liabilities—affiliate | — | 618 | — | 618 | |||||||||||
| Member’s equity | 1,430,901 | 5,810,742 | (5,927,834 | ) | 1,313,809 | ||||||||||
| Total liabilities and member’s equity | $ | 6,660,764 | $ | 5,903,518 | $ | (5,927,834 | ) | $ | 6,636,448 | ||||||
| Condensed Consolidating Statement of Operations | |||||||||||||||
| Year Ended December 31, 2017 | |||||||||||||||
| (in thousands) | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| Revenues | $ | — | $ | — | $ | — | $ | — | |||||||
| Expenses | |||||||||||||||
| Operating and maintenance expense | — | 3,115 | — | 3,115 | |||||||||||
| Operating and maintenance expense—affiliate | — | 2,401 | — | 2,401 | |||||||||||
| Development expense | — | 516 | — | 516 | |||||||||||
| Development expense—affiliate | — | 8 | — | 8 | |||||||||||
| General and administrative expense | 1,360 | 4,191 | — | 5,551 | |||||||||||
| General and administrative expense—affiliate | — | 1,173 | — | 1,173 | |||||||||||
| Depreciation and amortization expense | 13 | 879 | — | 892 | |||||||||||
| Impairment expense and loss on disposal of assets | — | 5,505 | — | 5,505 | |||||||||||
| Total expenses | 1,373 | 17,788 | — | 19,161 | |||||||||||
| Loss from operations | (1,373 | ) | (17,788 | ) | — | (19,161 | ) | ||||||||
| Other income (expense) | |||||||||||||||
| Loss on early extinguishment of debt | (32,480 | ) | — | — | (32,480 | ) | |||||||||
| Derivative gain, net | 3,249 | — | — | 3,249 | |||||||||||
| Other income (expense) | (265 | ) | 15,580 | (15,575 | ) | (260 | ) | ||||||||
| Total other income (expense) | (29,496 | ) | 15,580 | (15,575 | ) | (29,491 | ) | ||||||||
| Loss before income taxes | (30,869 | ) | (2,208 | ) | (15,575 | ) | (48,652 | ) | |||||||
| Income tax provision | — | (2,983 | ) | 2,983 | — | ||||||||||
| Net loss | $ | (30,869 | ) | $ | (5,191 | ) | $ | (12,592 | ) | $ | (48,652 | ) | |||
| Condensed Consolidating Statement of Operations | |||||||||||||||
| Year Ended December 31, 2016 | |||||||||||||||
| (in thousands) | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| Revenues | $ | — | $ | — | $ | — | $ | — | |||||||
| Expenses | |||||||||||||||
| Operating and maintenance expense | — | 1,372 | — | 1,372 | |||||||||||
| Operating and maintenance expense—affiliate | — | 95 | — | 95 | |||||||||||
| Development expense recovery | — | (81 | ) | — | (81 | ) | |||||||||
| Development expense recovery—affiliate | — | (10 | ) | — | (10 | ) | |||||||||
| General and administrative expense | 709 | 3,531 | — | 4,240 | |||||||||||
| General and administrative expense—affiliate | — | 607 | — | 607 | |||||||||||
| Depreciation and amortization expense | — | 249 | — | 249 | |||||||||||
| Total expenses | 709 | 5,763 | — | 6,472 | |||||||||||
| Loss from operations | (709 | ) | (5,763 | ) | — | (6,472 | ) | ||||||||
| Other income (expense) | |||||||||||||||
| Loss on early extinguishment of debt | (63,318 | ) | — | — | (63,318 | ) | |||||||||
| Derivative loss, net | (15,571 | ) | — | — | (15,571 | ) | |||||||||
| Other income (expense) | (131 | ) | 5 | — | (126 | ) | |||||||||
| Total other income (expense) | (79,020 | ) | 5 | — | (79,015 | ) | |||||||||
| Net loss | $ | (79,729 | ) | $ | (5,758 | ) | $ | — | $ | (85,487 | ) | ||||
| Condensed Consolidating Statement of Operations | |||||||||||||||
| Year Ended December 31, 2015 | |||||||||||||||
| (in thousands) | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| Revenues | $ | — | $ | — | $ | — | $ | — | |||||||
| Expenses | |||||||||||||||
| Operating and maintenance expense | — | 572 | — | 572 | |||||||||||
| Development expense | — | 13,690 | — | 13,690 | |||||||||||
| Development expense—affiliate | — | 5,525 | — | 5,525 | |||||||||||
| General and administrative expense | 724 | 2,465 | — | 3,189 | |||||||||||
| General and administrative expense—affiliate | — | 13 | — | 13 | |||||||||||
| Depreciation and amortization expense | — | 55 | — | 55 | |||||||||||
| Total expenses | 724 | 22,320 | — | 23,044 | |||||||||||
| Loss from operations | (724 | ) | (22,320 | ) | — | (23,044 | ) | ||||||||
| Other income (expense) | |||||||||||||||
| Interest expense, net of capitalized interest | (25,680 | ) | — | — | (25,680 | ) | |||||||||
| Loss on early extinguishment of debt | (16,498 | ) | — | — | (16,498 | ) | |||||||||
| Derivative loss, net | (161,917 | ) | — | — | (161,917 | ) | |||||||||
| Other income | 36 | 6 | — | 42 | |||||||||||
| Total other income (expense) | (204,059 | ) | 6 | — | (204,053 | ) | |||||||||
| Net loss | $ | (204,783 | ) | $ | (22,314 | ) | $ | — | $ | (227,097 | ) | ||||
| Condensed Consolidating Statement of Cash Flows | |||||||||||||||
| Year Ended December 31, 2017 | |||||||||||||||
| (in thousands) | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| Cash flows from operating activities | |||||||||||||||
| Net loss | $ | (30,869 | ) | $ | (5,191 | ) | $ | (12,592 | ) | $ | (48,652 | ) | |||
| Adjustments to reconcile net loss to net cash used in operating activities: | |||||||||||||||
| Depreciation and amortization expense | 13 | 879 | — | 892 | |||||||||||
| Allowance for funds used during construction | — | (15,575 | ) | 15,575 | — | ||||||||||
| Deferred income taxes | — | 2,983 | (2,983 | ) | — | ||||||||||
| Loss on early extinguishment of debt | 32,480 | — | — | 32,480 | |||||||||||
| Total losses (gains) on derivatives, net | (3,249 | ) | 91 | — | (3,158 | ) | |||||||||
| Net cash used for settlement of derivative instruments | (50,981 | ) | — | — | (50,981 | ) | |||||||||
| Impairment expense and loss on disposal of assets | — | 5,505 | — | 5,505 | |||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||
| Accounts payable and accrued liabilities | 68 | 84 | — | 152 | |||||||||||
| Due to affiliates | — | 1,567 | — | 1,567 | |||||||||||
| Other, net | (95 | ) | (1,359 | ) | — | (1,454 | ) | ||||||||
| Other, net—affiliate | — | (667 | ) | — | (667 | ) | |||||||||
| Net cash used in operating activities | (52,633 | ) | (11,683 | ) | — | (64,316 | ) | ||||||||
| Cash flows from investing activities | |||||||||||||||
| Property, plant and equipment, net | (253,612 | ) | (1,733,642 | ) | — | (1,987,254 | ) | ||||||||
| Investments in subsidiaries | (1,720,280 | ) | — | 1,720,280 | — | ||||||||||
| Other | — | 25,045 | — | 25,045 | |||||||||||
| Net cash used in investing activities | (1,973,892 | ) | (1,708,597 | ) | 1,720,280 | (1,962,209 | ) | ||||||||
| Cash flows from financing activities | |||||||||||||||
| Proceeds from issuances of debt | 3,040,000 | — | — | 3,040,000 | |||||||||||
| Repayments of debt | (1,436,050 | ) | — | — | (1,436,050 | ) | |||||||||
| Debt issuance and deferred financing costs | (23,496 | ) | — | — | (23,496 | ) | |||||||||
| Capital contributions | 402,119 | 1,720,437 | (1,720,437 | ) | 402,119 | ||||||||||
| Distributions | — | (157 | ) | 157 | — | ||||||||||
| Other | (29 | ) | — | — | (29 | ) | |||||||||
| Net cash provided by financing activities | 1,982,544 | 1,720,280 | (1,720,280 | ) | 1,982,544 | ||||||||||
| Net decrease in cash, cash equivalents and restricted cash | (43,981 | ) | — | — | (43,981 | ) | |||||||||
| Cash, cash equivalents and restricted cash—beginning of period | 270,540 | — | — | 270,540 | |||||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 226,559 | $ | — | $ | — | $ | 226,559 | |||||||
| December 31, 2017 | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| Cash and cash equivalents | $ | — | $ | — | $ | — | $ | — | |||||||
| Restricted cash | 226,559 | — | — | 226,559 | |||||||||||
| Total cash, cash equivalents and restricted cash | $ | 226,559 | $ | — | $ | — | $ | 226,559 | |||||||
| Condensed Consolidating Statement of Cash Flows | |||||||||||||||
| Year Ended December 31, 2016 | |||||||||||||||
| (in thousands) | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| Cash flows from operating activities | |||||||||||||||
| Net loss | $ | (79,729 | ) | $ | (5,758 | ) | $ | — | $ | (85,487 | ) | ||||
| Adjustments to reconcile net loss to net cash used in operating activities: | |||||||||||||||
| Depreciation and amortization expense | — | 249 | — | 249 | |||||||||||
| Loss on early extinguishment of debt | 63,318 | — | — | 63,318 | |||||||||||
| Total losses on derivatives, net | 15,571 | — | — | 15,571 | |||||||||||
| Net cash used for settlement of derivative instruments | (34,082 | ) | — | — | (34,082 | ) | |||||||||
| Changes in operating assets and liabilities: | |||||||||||||||
| Accounts payable and accrued liabilities | 121 | 294 | — | 415 | |||||||||||
| Due to affiliates | — | (331 | ) | — | (331 | ) | |||||||||
| Other, net | (153 | ) | (592 | ) | — | (745 | ) | ||||||||
| Other, net—affiliate | — | 13 | — | 13 | |||||||||||
| Net cash used in operating activities | (34,954 | ) | (6,125 | ) | — | (41,079 | ) | ||||||||
| Cash flows from investing activities | |||||||||||||||
| Property, plant and equipment, net | (126,547 | ) | (1,924,983 | ) | — | (2,051,530 | ) | ||||||||
| Investments in subsidiaries | (1,975,474 | ) | — | 1,975,474 | — | ||||||||||
| Other | — | (44,367 | ) | — | (44,367 | ) | |||||||||
| Net cash used in investing activities | (2,102,021 | ) | (1,969,350 | ) | 1,975,474 | (2,095,897 | ) | ||||||||
| Cash flows from financing activities | |||||||||||||||
| Proceeds from issuances of debt | 4,838,000 | — | — | 4,838,000 | |||||||||||
| Repayments of debt | (2,420,212 | ) | — | — | (2,420,212 | ) | |||||||||
| Debt issuance and deferred financing costs | (56,783 | ) | — | — | (56,783 | ) | |||||||||
| Capital contributions | 90 | 1,975,475 | (1,975,474 | ) | 91 | ||||||||||
| Distribution to affiliate | (288 | ) | — | — | (288 | ) | |||||||||
| Other | (62 | ) | — | — | (62 | ) | |||||||||
| Net cash provided by financing activities | 2,360,745 | 1,975,475 | (1,975,474 | ) | 2,360,746 | ||||||||||
| Net increase in cash, cash equivalents and restricted cash | 223,770 | — | — | 223,770 | |||||||||||
| Cash, cash equivalents and restricted cash—beginning of period | 46,770 | — | — | 46,770 | |||||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 270,540 | $ | — | $ | — | $ | 270,540 | |||||||
| December 31, 2016 | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| Cash and cash equivalents | $ | — | $ | — | $ | — | $ | — | |||||||
| Restricted cash | 197,201 | — | — | 197,201 | |||||||||||
| Non-current restricted cash | 73,339 | — | — | 73,339 | |||||||||||
| Total cash, cash equivalents and restricted cash | $ | 270,540 | $ | — | $ | — | $ | 270,540 | |||||||
| Condensed Consolidating Statement of Cash Flows | |||||||||||||||
| Year Ended December 31, 2015 | |||||||||||||||
| (in thousands) | |||||||||||||||
| Parent Issuer | Guarantors | Eliminations | Consolidated | ||||||||||||
| Cash flows from operating activities | |||||||||||||||
| Net loss | $ | (204,783 | ) | $ | (22,314 | ) | $ | — | $ | (227,097 | ) | ||||
| Adjustments to reconcile net loss to net cash used in operating activities: | |||||||||||||||
| Depreciation and amortization expense | — | 55 | — | 55 | |||||||||||
| Amortization of debt issuance costs, net of capitalization | 6,340 | — | — | 6,340 | |||||||||||
| Loss on early extinguishment of debt | 16,498 | — | — | 16,498 | |||||||||||
| Total losses on derivatives, net | 161,917 | — | — | 161,917 | |||||||||||
| Net cash used for settlement of derivative instruments | (56,918 | ) | — | — | (56,918 | ) | |||||||||
| Changes in operating assets and liabilities: | |||||||||||||||
| Accounts payable and accrued liabilities | 453 | 549 | — | 1,002 | |||||||||||
| Due to affiliates | (860 | ) | 1,135 | — | 275 | ||||||||||
| Advances to affiliate | — | (10,073 | ) | — | (10,073 | ) | |||||||||
| Other, net | — | 301 | — | 301 | |||||||||||
| Other, net—affiliate | — | 498 | — | 498 | |||||||||||
| Net cash used in operating activities | (77,353 | ) | (29,849 | ) | — | (107,202 | ) | ||||||||
| Cash flows from investing activities | |||||||||||||||
| Property, plant and equipment, net | (63,783 | ) | (3,757,164 | ) | — | (3,820,947 | ) | ||||||||
| Investments in subsidiaries | (3,804,848 | ) | — | 3,804,848 | — | ||||||||||
| Other | (633 | ) | (17,835 | ) | — | (18,468 | ) | ||||||||
| Net cash used in investing activities | (3,869,264 | ) | (3,774,999 | ) | 3,804,848 | (3,839,415 | ) | ||||||||
| Cash flows from financing activities | |||||||||||||||
| Proceeds from issuances of long-term debt | 2,713,000 | — | — | 2,713,000 | |||||||||||
| Debt issuance and deferred financing costs | (280,528 | ) | — | — | (280,528 | ) | |||||||||
| Capital contributions | 1,560,915 | 3,804,848 | (3,804,848 | ) | 1,560,915 | ||||||||||
| Net cash provided by financing activities | 3,993,387 | 3,804,848 | (3,804,848 | ) | 3,993,387 | ||||||||||
| Net increase in cash, cash equivalents and restricted cash | 46,770 | — | — | 46,770 | |||||||||||
| Cash, cash equivalents and restricted cash—beginning of period | — | — | — | — | |||||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | 46,770 | $ | — | $ | — | $ | 46,770 | |||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| Year ended December 31, 2017: | ||||||||||||||||
| Revenues | $ | — | $ | — | $ | — | $ | — | ||||||||
| Loss from operations | (2,719 | ) | (3,138 | ) | (5,576 | ) | (7,728 | ) | ||||||||
| Net income (loss) | (1,757 | ) | (68,758 | ) | (8,577 | ) | 30,440 | |||||||||
| Year ended December 31, 2016: | ||||||||||||||||
| Revenues | $ | — | $ | — | $ | — | $ | — | ||||||||
| Loss from operations | (733 | ) | (1,672 | ) | (1,809 | ) | (2,258 | ) | ||||||||
| Net income (loss) | (160,884 | ) | (106,585 | ) | 18,230 | 163,752 | ||||||||||
| Fiscal 2017 | Fiscal 2016 | |||||||
| Audit Fees | $ | 1,050 | $ | 1,070 | ||||
| Tax Fees | 89 | 29 | ||||||
| Total | $ | 1,139 | $ | 1,099 | ||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | — | $ | — | ||||
| Restricted cash | — | — | ||||||
| Advances to affiliate | 11,414 | 2,184 | ||||||
| Other current assets | 1,237 | 37,014 | ||||||
| Other current assets—affiliate | 190 | 141 | ||||||
| Total current assets | 12,841 | 39,339 | ||||||
| Property, plant and equipment, net | 7,259,438 | 5,640,973 | ||||||
| Non-current advances under long-term contracts | — | 46,398 | ||||||
| Other non-current assets, net | 37,854 | 26,285 | ||||||
| Total assets | $ | 7,310,133 | $ | 5,752,995 | ||||
| LIABILITIES AND MEMBER’S EQUITY | ||||||||
| Current liabilities | ||||||||
| Accounts payable | $ | 4,456 | $ | 1,105 | ||||
| Accrued liabilities | 96,886 | 57,924 | ||||||
| Due to affiliates | 21,741 | 5,836 | ||||||
| Total current liabilities | 123,083 | 64,865 | ||||||
| Non-current derivative liabilities | 91 | — | ||||||
| Other non-current liabilities—affiliate | — | 618 | ||||||
| Commitments and contingencies (see Note 8) | ||||||||
| Member’s equity | 7,186,959 | 5,687,512 | ||||||
| Total liabilities and member’s equity | $ | 7,310,133 | $ | 5,752,995 | ||||
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Revenues | $ | — | $ | — | $ | — | ||||||
| Expenses | ||||||||||||
| Operating and maintenance expense | 3,099 | 1,350 | 572 | |||||||||
| Operating and maintenance expense—affiliate | 2,331 | 92 | — | |||||||||
| Development expense (recovery) | 516 | (81 | ) | 13,690 | ||||||||
| Development expense (recovery)—affiliate | 8 | (10 | ) | 5,525 | ||||||||
| General and administrative expense | 3,951 | 3,231 | 2,353 | |||||||||
| General and administrative expense—affiliate | 1,127 | 600 | — | |||||||||
| Depreciation and amortization expense | 810 | 239 | 55 | |||||||||
| Impairment expense and loss on disposal of assets | 5,500 | — | — | |||||||||
| Total expenses | 17,342 | 5,421 | 22,195 | |||||||||
| Loss from operations | (17,342 | ) | (5,421 | ) | (22,195 | ) | ||||||
| Other income | ||||||||||||
| Other income | 5 | 5 | 6 | |||||||||
| Other income—affiliate | 12 | 12 | — | |||||||||
| Total other income | 17 | 17 | 6 | |||||||||
| Net loss | $ | (17,325 | ) | $ | (5,404 | ) | $ | (22,189 | ) | |||
| Cheniere Corpus Christi Holdings, LLC | Total Member’s Equity | ||||||
| Balance at December 31, 2014 | $ | 51,921 | $ | 51,921 | |||
| Capital contributions | 3,790,251 | 3,790,251 | |||||
| Net loss | (22,189 | ) | (22,189 | ) | |||
| Balance at December 31, 2015 | 3,819,983 | 3,819,983 | |||||
| Capital contributions | 1,872,933 | 1,872,933 | |||||
| Net loss | (5,404 | ) | (5,404 | ) | |||
| Balance at December 31, 2016 | 5,687,512 | 5,687,512 | |||||
| Capital contributions | 1,516,772 | 1,516,772 | |||||
| Net loss | (17,325 | ) | (17,325 | ) | |||
| Balance at December 31, 2017 | $ | 7,186,959 | $ | 7,186,959 | |||
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Cash flows from operating activities | ||||||||||||
| Net loss | $ | (17,325 | ) | $ | (5,404 | ) | $ | (22,189 | ) | |||
| Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||||||
| Depreciation and amortization expense | 810 | 239 | 55 | |||||||||
| Total losses on derivatives, net | 91 | — | — | |||||||||
| Impairment expense and loss on disposal of assets | 5,500 | — | — | |||||||||
| Changes in operating assets and liabilities: | ||||||||||||
| Accounts payable and accrued liabilities | 58 | 369 | 529 | |||||||||
| Due to affiliates | 1,561 | (241 | ) | 1,139 | ||||||||
| Advances to affiliate | — | — | (3,122 | ) | ||||||||
| Other, net | (1,202 | ) | (580 | ) | 430 | |||||||
| Other, net—affiliate | (667 | ) | 13 | 498 | ||||||||
| Net cash used in operating activities | (11,174 | ) | (5,604 | ) | (22,660 | ) | ||||||
| Cash flows from investing activities | ||||||||||||
| Property, plant and equipment, net | (1,530,642 | ) | (1,822,962 | ) | (3,753,264 | ) | ||||||
| Other | 25,045 | (44,367 | ) | (14,327 | ) | |||||||
| Net cash used in investing activities | (1,505,597 | ) | (1,867,329 | ) | (3,767,591 | ) | ||||||
| Cash flows from financing activities | ||||||||||||
| Capital contributions | 1,516,771 | 1,872,933 | 3,790,251 | |||||||||
| Net cash provided by financing activities | 1,516,771 | 1,872,933 | 3,790,251 | |||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | — | — | — | |||||||||
| Cash, cash equivalents and restricted cash—beginning of period | — | — | — | |||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | — | $ | — | $ | — | ||||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Cash and cash equivalents | $ | — | $ | — | ||||
| Restricted cash | — | — | ||||||
| Total cash, cash equivalents and restricted cash | $ | — | $ | — | ||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| LNG terminal costs | ||||||||
| LNG terminal construction-in-process | $ | 7,244,447 | $ | 5,628,320 | ||||
| LNG site and related costs | 11,662 | 11,662 | ||||||
| Total LNG terminal costs | 7,256,109 | 5,639,982 | ||||||
| Fixed assets | ||||||||
| Fixed assets | 4,261 | 1,234 | ||||||
| Accumulated depreciation | (932 | ) | (243 | ) | ||||
| Total fixed assets, net | 3,329 | 991 | ||||||
| Property, plant and equipment, net | $ | 7,259,438 | $ | 5,640,973 | ||||
| December 31, | ||||||||
| Balance Sheet Location | 2017 | 2016 | ||||||
| Non-current derivative liabilities | $ | (91 | ) | $ | — | |||
| Year Ended December 31, | |||||||||||||
| Statement of Operations Location | 2017 | 2016 | 2015 | ||||||||||
| Liquefaction Supply Derivatives loss | Operating and maintenance expense | $ | 91 | $ | — | $ | — | ||||||
| Gross Amounts Recognized | Gross Amounts Offset in the Balance Sheets | Net Amounts Presented in the Balance Sheets | ||||||||||
| Offsetting Derivative Assets (Liabilities) | ||||||||||||
| As of December 31, 2017 | ||||||||||||
| Liquefaction Supply Derivatives | $ | (130 | ) | $ | 39 | $ | (91 | ) | ||||
| As of December 31, 2016 | ||||||||||||
| Liquefaction Supply Derivatives | — | — | — | |||||||||
| Year Ended December 31, | |||||||||
| 2017 | 2016 | 2015 | |||||||
| U.S. federal statutory tax rate | 35.0 | % | 35.0 | % | 35.0 | % | |||
| U.S. tax reform rate change | (100.8 | )% | — | % | — | % | |||
| Other | (0.5 | )% | (0.1 | )% | — | % | |||
| Valuation allowance | 66.3 | % | (34.9 | )% | (35.0 | )% | |||
| Effective tax rate | — | % | — | % | — | % | |||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Deferred tax assets | ||||||||
| Federal net operating loss carryforward | $ | 5,788 | $ | 7,721 | ||||
| Property, plant and equipment | 20,069 | 29,560 | ||||||
| Other | 327 | 394 | ||||||
| Less: valuation allowance | (26,184 | ) | (37,675 | ) | ||||
| Total net deferred tax asset | $ | — | $ | — | ||||
| Years Ending December 31, | Operating Leases | ||
| 2018 | $ | 895 | |
| 2019 | 841 | ||
| 2020 | 245 | ||
| 2021 | — | ||
| 2022 | — | ||
| Thereafter | — | ||
| Total | $ | 1,981 | |
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | — | $ | — | ||||
| Restricted cash | — | — | ||||||
| Advances to affiliate | 20,072 | 17,924 | ||||||
| Other current assets | 11 | 29 | ||||||
| Total current assets | 20,083 | 17,953 | ||||||
| Property, plant and equipment, net | 350,258 | 129,357 | ||||||
| Other non-current assets | 270 | 3,212 | ||||||
| Total assets | $ | 370,611 | $ | 150,522 | ||||
| LIABILITIES AND PARTNERS’ EQUITY | ||||||||
| Current liabilities | ||||||||
| Accounts payable | $ | 1,923 | $ | 7,683 | ||||
| Accrued liabilities | 24,785 | 18,396 | ||||||
| Due to affiliates | 2,048 | 1,214 | ||||||
| Total current liabilities | 28,756 | 27,293 | ||||||
| Deferred tax liability | 2,983 | — | ||||||
| Commitments and contingencies (see Note 6) | ||||||||
| Partners’ equity | 338,872 | 123,229 | ||||||
| Total liabilities and partners’ equity | $ | 370,611 | $ | 150,522 | ||||
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Revenues | $ | — | $ | — | $ | — | |||||
| Expenses | |||||||||||
| Operating and maintenance expense | 16 | 22 | — | ||||||||
| Operating and maintenance expense—affiliate | 82 | 15 | — | ||||||||
| General and administrative expense | 234 | 295 | 111 | ||||||||
| General and administrative expense—affiliate | 46 | 7 | 13 | ||||||||
| Depreciation and amortization expense | 69 | 10 | — | ||||||||
| Loss on disposal of assets | 5 | — | — | ||||||||
| Total expenses | 452 | 349 | 124 | ||||||||
| Loss from operations | (452 | ) | (349 | ) | (124 | ) | |||||
| Other income | 15,575 | — | — | ||||||||
| Income (loss) before income taxes | 15,123 | (349 | ) | (124 | ) | ||||||
| Income tax provision | (2,983 | ) | — | — | |||||||
| Net income (loss) | $ | 12,140 | $ | (349 | ) | $ | (124 | ) | |||
| Corpus Christi Pipeline GP, LLC | Cheniere Corpus Christi Holdings, LLC | Total Partners’ Equity | ||||||||||
| Balance at December 31, 2014 | $ | 1 | $ | 6,425 | $ | 6,426 | ||||||
| Capital contributions | — | 14,596 | 14,596 | |||||||||
| Net loss | — | (124 | ) | (124 | ) | |||||||
| Balance at December 31, 2015 | 1 | 20,897 | 20,898 | |||||||||
| Capital contributions | — | 102,537 | 102,537 | |||||||||
| Non-cash capital contribution from affiliate | — | 143 | 143 | |||||||||
| Net loss | — | (349 | ) | (349 | ) | |||||||
| Balance at December 31, 2016 | 1 | 123,228 | 123,229 | |||||||||
| Capital contributions | — | 203,660 | 203,660 | |||||||||
| Distributions | — | (157 | ) | (157 | ) | |||||||
| Net income | — | 12,140 | 12,140 | |||||||||
| Balance at December 31, 2017 | $ | 1 | $ | 338,871 | $ | 338,872 | ||||||
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Cash flows from operating activities | |||||||||||
| Net income (loss) | $ | 12,140 | $ | (349 | ) | $ | (124 | ) | |||
| Adjustments to reconcile net income (loss) to net cash used in operating activities: | |||||||||||
| Depreciation and amortization expense | 69 | 10 | — | ||||||||
| Allowance for funds used during construction | (15,575 | ) | — | — | |||||||
| Deferred income taxes | 2,983 | — | — | ||||||||
| Loss on disposal of assets | 5 | — | — | ||||||||
| Changes in operating assets and liabilities: | |||||||||||
| Accounts payable and accrued liabilities | 26 | (75 | ) | 20 | |||||||
| Due to affiliates | 6 | (90 | ) | (4 | ) | ||||||
| Advances to affiliate | — | — | (6,951 | ) | |||||||
| Other, net | (157 | ) | (12 | ) | (129 | ) | |||||
| Net cash used in operating activities | (503 | ) | (516 | ) | (7,188 | ) | |||||
| Cash flows from investing activities | |||||||||||
| Property, plant and equipment, net | (203,000 | ) | (102,021 | ) | (3,900 | ) | |||||
| Other | — | — | (3,508 | ) | |||||||
| Net cash used in investing activities | (203,000 | ) | (102,021 | ) | (7,408 | ) | |||||
| Cash flows from financing activities | |||||||||||
| Capital contributions | 203,660 | 102,537 | 14,596 | ||||||||
| Distributions | (157 | ) | — | — | |||||||
| Net cash provided by financing activities | 203,503 | 102,537 | 14,596 | ||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | — | — | — | ||||||||
| Cash, cash equivalents and restricted cash—beginning of period | — | — | — | ||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | — | $ | — | $ | — | |||||
| December 31, | |||||||
| 2017 | 2016 | ||||||
| Cash and cash equivalents | $ | — | $ | — | |||
| Restricted cash | — | — | |||||
| Total cash, cash equivalents and restricted cash | $ | — | $ | — | |||
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.
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.
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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
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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
of settlement isare 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. Our assessment of AROs is described below.
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
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 evaluating financial performance andit becomes mandatorily effective for purposes of allocating resources.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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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 consists of natural gas pipeline costs and fixed assets, as followsaccumulated depreciation consisted of the following (in thousands)millions):
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Natural gas pipeline costs | ||||||||
| Natural gas pipeline construction-in-process | $ | 346,526 | $ | 125,637 | ||||
| Land | 2,182 | 2,344 | ||||||
| Total natural gas pipeline costs | 348,708 | 127,981 | ||||||
| Fixed assets | ||||||||
| Fixed assets | 1,628 | 1,386 | ||||||
| Accumulated depreciation | (78 | ) | (10 | ) | ||||
| Total fixed assets, net | 1,550 | 1,376 | ||||||
| Property, plant and equipment, net | $ | 350,258 | $ | 129,357 | ||||
| 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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CHENIERE CORPUS CHRISTI PIPELINE, L.P. HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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, ended December 31, 2017, 2016 and 2015 was $68 thousand, $10 thousand and zero, respectively.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 4—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.
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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 | 2021 | ||||||||||||||||||||||||||||||
| 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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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
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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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
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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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
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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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 | ||||||||||||||||||||||||||
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
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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.
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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 | % | ||||||||||||||||||||||||||||
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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.
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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 $2.0$49 million and $1.2$43 million due to affiliates as of December 31, 20172023 and 2016,2022, respectively, under agreements with affiliates as described below.above.
Other Agreements
State Tax Sharing AgreementAgreements
CCL and CCP each have a state tax sharing agreement with Cheniere. Under this agreement,these agreements, Cheniere has agreed to prepare and file all state and local tax returns which weeach 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, weeach of the respective entities will pay to Cheniere an amount equal to the state and local tax that weeach of the entities would be required to pay if ourits state and local tax liability were calculated on a separate company basis. ThereTo date, there have been no state and local taxes paidtax payments demanded by Cheniere under the tax sharing agreements. The agreements for which Cheniere could have demanded payment from us under this agreement; therefore, Cheniere has not demanded any such payments from us. The agreement isboth CCL and CCP were effective for tax returns due on or after May 2015.
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Current: | ||||||||||||
| Federal | $ | — | $ | — | $ | — | ||||||
| State | — | — | — | |||||||||
| Total current | — | — | — | |||||||||
| Deferred: | ||||||||||||
| Federal | 2,983 | — | — | |||||||||
| State | — | — | — | |||||||||
| Total deferred | 2,983 | — | — | |||||||||
| Total income tax provision | $ | 2,983 | $ | — | $ | — | ||||||
| Year Ended December 31, | |||||||||
| 2017 | 2016 | 2015 | |||||||
| U.S. federal statutory tax rate | 35.0 | % | 35.0 | % | 35.0 | % | |||
| U.S. tax reform rate change | (13.2 | )% | — | % | — | % | |||
| Other | — | % | (0.2 | )% | (0.1 | )% | |||
| Valuation allowance | (2.1 | )% | (34.8 | )% | (34.9 | )% | |||
| Effective tax rate | 19.7 | % | — | % | — | % | |||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Deferred tax assets | ||||||||
| Federal net operating loss carryforward | $ | 4 | $ | — | ||||
| Property, plant and equipment | — | 322 | ||||||
| Less: valuation allowance | — | (322 | ) | |||||
| Total net deferred tax assets | 4 | — | ||||||
| Deferred tax liabilities | ||||||||
| Property, plant and equipment | (2,982 | ) | — | |||||
| Other | (5 | ) | — | |||||
| Total deferred tax liabilities | (2,987 | ) | — | |||||
| Net deferred tax liabilities | $ | (2,983 | ) | $ | — | |||
NOTE 6—14—COMMITMENTS AND CONTINGENCIES
Commitments
We have various contractualfuture commitments under executed contracts that include unconditional purchase obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain commitments and other executed contractscommitments which do not meet the definition of a liability as of December 31, 2017,2023 and thus are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.
61
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
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 considered materialcurrently expected to our financial positionbe 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 meet the definition of a commitmentbasis spreads as of December 31, 2017. Additionally, we2023. 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 operating leasebeen 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 affiliates, as disclosed in third parties and $7.6 billion with affiliates. See Note 4—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
62
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
the opinion of management, as of December 31, 2017,2023, 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 7—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 thousands)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 | — | ||||||||||||||
| 400 | 1,217 | — | |||||||||||||||
| Year Ended December 31, | ||||||||
| 2017 | 2016 | 2015 | ||||||
| Non-cash capital contribution for conveyance of asset from affiliate | — | 143 | — | |||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| ASSETS | ||||||||
| Cash and cash equivalents | $ | — | $ | — | ||||
| Restricted cash | — | — | ||||||
| Receivable—affiliate | 1,000 | 1,000 | ||||||
| Total assets | $ | 1,000 | $ | 1,000 | ||||
| LIABILITIES AND MEMBER’S EQUITY | ||||||||
| Liabilities | $ | — | $ | — | ||||
| Member’s equity | 1,000 | 1,000 | ||||||
| Total liabilities and member’s equity | $ | 1,000 | $ | 1,000 | ||||
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Revenues | $ | — | $ | — | $ | — | ||||||
| General and administrative expense | 5,585 | 5,300 | 1,207 | |||||||||
| Net loss | $ | (5,585 | ) | $ | (5,300 | ) | $ | (1,207 | ) | |||
| Cheniere Corpus Christi Holdings, LLC | Total Member’s Equity | |||||||
| Balance at December 31, 2014 | $ | 1,000 | $ | 1,000 | ||||
| Capital contributions | 1,207 | 1,207 | ||||||
| Net loss | (1,207 | ) | (1,207 | ) | ||||
| Balance at December 31, 2015 | 1,000 | 1,000 | ||||||
| Capital contributions | 5,300 | 5,300 | ||||||
| Net loss | (5,300 | ) | (5,300 | ) | ||||
| Balance at December 31, 2016 | 1,000 | 1,000 | ||||||
| Capital contributions | 5,585 | 5,585 | ||||||
| Net loss | (5,585 | ) | (5,585 | ) | ||||
| Balance at December 31, 2017 | $ | 1,000 | $ | 1,000 | ||||
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Cash flows from operating activities | ||||||||||||
| Net loss | $ | (5,585 | ) | $ | (5,300 | ) | $ | (1,207 | ) | |||
| Cash flows from investing activities | — | — | — | |||||||||
| Cash flows from financing activities | ||||||||||||
| Capital contributions | 5,585 | 5,300 | 1,207 | |||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | — | — | — | |||||||||
| Cash, cash equivalents and restricted cash—beginning of period | — | — | — | |||||||||
| Cash, cash equivalents and restricted cash—end of period | $ | — | $ | — | $ | — | ||||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Cash and cash equivalents | $ | — | $ | — | ||||
| Restricted cash | — | — | ||||||
| Total cash, cash equivalents and restricted cash | $ | — | $ | — | ||||
| Year Ended December 31, | |||||||||
| 2017 | 2016 | 2015 | |||||||
| U.S. federal statutory tax rate | 35.0 | % | 35.0 | % | 35.0 | % | |||
| U.S. tax reform rate change | (30.3 | )% | — | % | — | % | |||
| Valuation allowance | (4.7 | )% | (35.0 | )% | (35.0 | )% | |||
| Effective tax rate | — | % | — | % | — | % | |||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Deferred tax assets | ||||||||
| Federal net operating loss carryforward | $ | 2,539 | $ | 2,277 | ||||
| Less: valuation allowance | (2,539 | ) | (2,277 | ) | ||||
| Total net deferred tax asset | $ | — | $ | — | ||||
63
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 22, 2017,31, 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 U.S. government enacted comprehensiveExchange 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.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
64
PART III
ITEM 10. MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE
Omitted pursuant to Instruction I of Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to Instruction I of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS
Omitted pursuant to Instruction I of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE
Omitted pursuant to Instruction I of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG LLP, 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 legislation (Tax Cutsfees in 2023 and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%.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 legislation, we remeasured ourindependent accountants and the fees for such services during the fiscal years ended December 31, 2017 U.S. deferred tax assets2023 and liabilities. The result2022.
65
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements and Exhibits
(1) Financial Statements—Cheniere Corpus Christi Holdings, LLC:
(2) Financial Statement Schedules:
All financial statement schedules have been omitted because they are not required, are not applicable, or the remeasurement was a $1,700 reduction to our U.S. net deferred tax assets and represents a 30.3% decrease to our effective tax rate. This remeasurement is fully offset by a corresponding change to our valuation allowance, and therefore there was no impact to current period income tax expense.
(3) Exhibits:
Certain of Cheniere. Cheniere’s federalthe agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and state tax returnsconditions by the parties to the agreements that have been made solely for the years after 2013 remain open for examination. Tax authorities 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 the ability to review and adjust carryover attributesbeen qualified by disclosures that were generated priormade to these periods if utilizedthe other parties in an open tax year.
•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 | CCH | S-4 | 3.1 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.2 | CCH | S-4 | 3.2 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.3 | CCH | S-4 | 3.3 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.4 | CCH | S-4 | 3.4 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.5 | CCH | S-4 | 3.5 | 1/5/2017 | ||||||||||||||||||||||||||||
66
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 3.6 | CCH | S-4 | 3.6 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.7 | CCH | S-4 | 3.7 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.8 | CCH | S-4 | 3.8 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.9 | CCH | S-4 | 3.9 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.10 | CCH | S-4 | 3.10 | 1/5/2017 | ||||||||||||||||||||||||||||
| 3.11 | CCH | S-4 | 3.11 | 1/5/2017 | ||||||||||||||||||||||||||||
| 4.1 | Cheniere | 8-K | 4.1 | 5/18/2016 | ||||||||||||||||||||||||||||
| 4.2 | Cheniere | 8-K | 4.1 | 12/9/2016 | ||||||||||||||||||||||||||||
| 4.3 | Cheniere | 8-K | 4.1 | 12/9/2016 | ||||||||||||||||||||||||||||
| 4.4 | CCH | 8-K | 4.1 | 5/19/2017 | ||||||||||||||||||||||||||||
| 4.5 | CCH | 8-K | 4.1 | 5/19/2017 | ||||||||||||||||||||||||||||
| 4.6 | CCH | 8-K | 4.1 | 9/12/2019 | ||||||||||||||||||||||||||||
| 4.7 | CCH | 8-K | 4.1 | 9/30/2019 | ||||||||||||||||||||||||||||
| 4.8 | CCH | 8-K | 4.1 | 9/30/2019 | ||||||||||||||||||||||||||||
| 4.9 | CCH | 8-K | 4.1 | 10/18/2019 | ||||||||||||||||||||||||||||
| 4.10 | CCH | 8-K | 4.1 | 10/18/2019 | ||||||||||||||||||||||||||||
| 4.11 | CCH | 8-K | 4.1 | 11/13/2019 | ||||||||||||||||||||||||||||
| 4.12 | CCH | 8-K | 4.1 | 11/13/2019 | ||||||||||||||||||||||||||||
| 4.13 | CCH | 8-K | 4.1 | 8/24/2021 | ||||||||||||||||||||||||||||
| 4.14 | CCH | 8-K | 4.1 | 8/24/2021 | ||||||||||||||||||||||||||||
| 4.15 | CCH | 8-K | 4.1 | 8/21/2020 | ||||||||||||||||||||||||||||
| 4.16 | CCH | 8-K | 4.1 | 8/21/2020 | ||||||||||||||||||||||||||||
| 10.1 | CCH | 8-K | 10.1 | 6/22/2022 | ||||||||||||||||||||||||||||
67
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.2 | CCH | 8-K | 10.3 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.3 | CCH | 8-K | 10.4 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.4 | CCH | 8-K | 10.4 | 5/24/2018 | ||||||||||||||||||||||||||||
| 10.5 | CCH | 8-K | 10.5 | 5/24/2018 | ||||||||||||||||||||||||||||
| 10.6 | CCH | 8-K | 10.2 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.7 | CEI | 10-Q | 10.1 | 5/4/2022 | ||||||||||||||||||||||||||||
| 10.8 | CCH | 10-Q | 10.6 | 8/4/2022 | ||||||||||||||||||||||||||||
| 10.9 | CCH | 10-Q | 10.1 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.10 | CCH | 10-K | 10.10 | 2/23/2023 | ||||||||||||||||||||||||||||
68
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.11 | CCH | 10-Q | 10.1 | 5/2/2023 | ||||||||||||||||||||||||||||
| 10.12 | CCH | 10-Q | 10.1 | 8/3/2023 | ||||||||||||||||||||||||||||
| 10.13 | CCH | 10-Q | 10.1 | 11/2/2023 | ||||||||||||||||||||||||||||
69
70
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.15 | CCH | S-4 | 10.14 | 1/5/2017 | ||||||||||||||||||||||||||||
| 10.16 | CCH | S-4 | 10.15 | 1/5/2017 | ||||||||||||||||||||||||||||
| 10.17 | Cheniere | 8-K | 10.1 | 4/2/2014 | ||||||||||||||||||||||||||||
| 10.18 | Cheniere | 8-K | 10.1 | 4/8/2014 | ||||||||||||||||||||||||||||
| 10.19 | Cheniere | 10-Q | 10.3 | 5/1/2014 | ||||||||||||||||||||||||||||
| 10.20 | Cheniere | 10-Q | 10.9 | 10/30/2015 | ||||||||||||||||||||||||||||
| 10.21 | Cheniere | 10-Q | 10.10 | 10/30/2015 | ||||||||||||||||||||||||||||
| 10.22 | CCH | 10-Q | 10.2 | 8/3/2023 | ||||||||||||||||||||||||||||
| 10.23 | CCH | 10-Q | 10.3 | 8/3/2023 | ||||||||||||||||||||||||||||
| 10.24 | Cheniere | 10-Q | 10.5 | 4/30/2015 | ||||||||||||||||||||||||||||
| 10.25 | CCH | S-4 | 10.22 | 1/5/2017 | ||||||||||||||||||||||||||||
| 10.26 | CCH | 10-Q | 10.1 | 11/1/2019 | ||||||||||||||||||||||||||||
| 10.27 | Cheniere | 8-K | 10.1 | 6/2/2014 | ||||||||||||||||||||||||||||
| 10.28 | CCH | 10-Q | 10.5 | 5/4/2018 | ||||||||||||||||||||||||||||
| 10.29 | CCH | 8-K | 10.6 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.30 | CCH | 10-K | 10.34 | 2/25/2020 | ||||||||||||||||||||||||||||
| 10.31 | CCH | 10-Q | 10.50 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.32 | CCH | 10-Q | 10.4 | 8/3/2023 | ||||||||||||||||||||||||||||
| 10.33 | CCH | 8-K | 10.50 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.34 | CCH | 10-Q | 10.40 | 11/3/2022 | ||||||||||||||||||||||||||||
71
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.35 | CCH | 10-Q | 10.20 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.36 | CCH | 10-Q | 10.30 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.37 | CCH | 10-Q | 10.10 | 5/4/2022 | ||||||||||||||||||||||||||||
| 10.38 | CCH | 8-K | 10.70 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.39 | CCH | 10-Q | 10.60 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.40 | CCH | 10-Q | 10.70 | 11/3/2022 | ||||||||||||||||||||||||||||
| 22.1* | ||||||||||||||||||||||||||||||||
| 31.1* | ||||||||||||||||||||||||||||||||
| 32.1** | ||||||||||||||||||||||||||||||||
| 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.
ITEM 16. FORM 10-K SUMMARY
None.
72
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| CHENIERE CORPUS CHRISTI HOLDINGS, LLC | |||||||||||
| By: | /s/ Zach Davis | ||||||||||
| Zach Davis | |||||||||||
| President and Chief Financial Officer (Principal Executive and Financial Officer) | |||||||||||
| Date: | February 21, 2024 | ||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the utilization of Cheniere’s NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of Cheniere’s NOLs in full over the carryover period. Cheniere will continue to monitor trading activity in its respective shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize Cheniere’s existing NOL carryforwards.dates indicated.
| Signature | Title | Date | ||||||
| /s/ Zach Davis | Manager, President and Chief Financial Officer (Principal Executive and Financial Officer) | February 21, 2024 | ||||||
| Zach Davis | ||||||||
| /s/ Corey Grindal | Manager | February 21, 2024 | ||||||
| Corey Grindal | ||||||||
| /s/ David Slack | Chief Accounting Officer (Principal Accounting Officer) | February 21, 2024 | ||||||
| David Slack | ||||||||
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