Abbreviated Legal Entity Structure
The following diagram depicts our abbreviated legal entity structure as of December 31, 2017,2022, 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.”statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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 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 company primarily engagedsource that is essential for heating, cooking and other industrial uses. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in 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.
In June 2022, Cheniere’s board of directors (the “Board”) made a positive FID with respect to the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to 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. Refer to Note 3—CCL Stage III Contribution and Merger of our Notes to Consolidated Financial Statements for additional information on the Contribution and Merger of CCL Stage III.
We also own and operate through CCP a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines. Stage 1pipelines (the “Corpus Christi Pipeline” and together with the existing operational Trains, midscale Trains, storage tanks and marine berths, the “Liquefaction Project”).
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted most of our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Through our SPAs and IPM agreements, we have contracted approximately 88% of the total anticipated production capacity from the Liquefaction Project with approximately 18 years of weighted average remaining life as of December 31, 2022. For further discussion of the contracted future cash flows under our revenue arrangements, see Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Corpus Christi Pipeline are currentlyLNG Terminal, which provides opportunity for further liquefaction capacity expansion. In September 2022, CCL and another subsidiary of Cheniere entered the pre-filing review process with the FERC under construction,the National Environmental Policy Act 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 (“Midscale Trains 8 and Train 39”). The development of
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Midscale Trains 8 and 9 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 being commercialized and has all necessary regulatory approvals in place. Construction of the Corpus Christi Pipeline is nearing completion.made.
Our Business Strategy
Our primary objectivebusiness strategy for the Liquefaction Project is to generatedevelop, construct and operate assets to meet our long-term customers’ energy demands. We plan to implement our strategy by:
•safely, efficiently and reliably operating and maintaining our assets;
•procuring natural gas and pipeline transport capacity to our facility;
•commencing commercial delivery for our long-term SPA customers, of which we have initiated for 13 of 15 third party long-term SPA customers as of December 31, 2022;
•maximizing the production of LNG to serve our customers and generating steady and reliablestable revenues and operating cash flows by:;
•further expanding andand/or optimizing the Liquefaction Project by leveraging existing infrastructure; and
•maintaining a prudent and cost-effective capital structure.structure; and
•strategically identifying actionable environmental solutions.
Our Business
Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Our Liquefaction Project
The Liquefaction Project, is being developedas described above under the caption General, includes three Trains and constructed attwo marine berths and the construction of the Corpus Christi LNG terminal. Substantially all of our long-lived assets are located in the United States. In December 2014, we received authorization from the FERCStage 3 Project with up to site, construct and operate Stages 1 and 2 ofseven midscale Trains adjacent to the Liquefaction Project. Additionally, in September 2022, CCL and another subsidiary of Cheniere entered the pre-filing review process with the FERC under the National Environmental Policy Act for Midscale Trains 8 and 9.
The following table summarizes the overall project completion and construction status of the Corpus Christi Stage 1 of the Liquefaction3 Project as of DecemberJanuary 31, 2017:
2023:
| Overall project completion percentage | 24.5% | ||||||||||
| Completion percentage of: | |||||||||||
| Engineering | 41.3% | ||||||||||
| Procurement | 36.9% | ||||||||||
| Subcontract work | 29.5% | ||||||||||
| Construction | 2.2% | ||||||||||
| 2H 2025 - 1H | |||||||||||
The following summarizes the volumes of natural gas for which we have received approvals from FERC to site, construct and operate the Liquefaction Project and the orders we have received from the DOE has authorizedauthorizing the export of domestically produced LNG by vessel from the Liquefaction Project through December 31, 2050:
| FERC Approved Volume | DOE Approved Volume | ||||||||||||||||||||||
| (in Bcf/yr) | (in mtpa) | (in Bcf/yr) | (in mtpa) | ||||||||||||||||||||
| Trains 1 through 3 of the Liquefaction Project: | |||||||||||||||||||||||
| FTA countries | 875.16 | 17 | 875.16 | 17 | |||||||||||||||||||
| Non-FTA countries | 875.16 | 17 | 875.16 | 17 | |||||||||||||||||||
| Corpus Christi Stage 3 Project: | |||||||||||||||||||||||
| FTA countries | 582.14 | 11.45 | 582.14 | 11.45 | |||||||||||||||||||
| Non-FTA countries | 582.14 | 11.45 | 582.14 | 11.45 | |||||||||||||||||||
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Pipeline Facilities
In November 2019, the FERC authorized CCP to construct and operate the pipeline for the Corpus Christi Stage 3 Project, which is designed to transport 1.5 Bcf/d of natural gas feedstock required by the Corpus Christi Stage 3 Project from the existing regional natural gas pipeline grid.
Natural Gas Supply, Transportation and Storage
CCL has secured natural gas feedstock for the Corpus Christi LNG terminalTerminal through traditional long-term natural gas supply and IPM agreements. Additionally, to FTA countries 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
Information regarding our customer contracts can be found in Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following table shows customers with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing volatility 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 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. Asrevenues of December 31, 2017, CCL has secured up to approximately 2,024 TBtu10% or greater 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.total revenues from external customers:
| Percentage of Total Revenues from External Customers | ||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||
| Endesa Generación, S.A. (which subsequently assigned its SPA to Endesa S.A.) and Endesa S.A. | 21% | 21% | 31% | |||||||||||||||||||||||||||||
| PT Pertamina (Persero) | 14% | 16% | 16% | |||||||||||||||||||||||||||||
| Naturgy LNG GOM, Limited | 14% | 15% | 14% | |||||||||||||||||||||||||||||
| Trafigura Pte Ltd and affiliates | 10% | * | —% | |||||||||||||||||||||||||||||
* Less than 10%
All of the Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause CCLabove customers contribute to enter into a change order, or CCL agrees with Bechtel to a change order.our LNG revenues through SPA contracts.
Governmental Regulation
The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. ThisThese rigorous regulatory requirement 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 import or 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 Natural Gas Act of 1938, as amended (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.
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•rates and charges, and terms and conditions for natural gas transportation, storage and related services;
•the certification and construction of new facilities and modification of existing facilities;
•the extension and abandonment of services and facilities;
•the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;
•the acquisition and disposition of facilities;
•the initiation and discontinuation of services; and
•various other matters.
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,Terminal, 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”) 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 issued an order granting CCL authorization under Section 3 of the NGA to site, construct and operate StageTrains 1 and Stage 2through 3 of the Liquefaction Project and issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing CCP to constructconstruction and operateoperation of 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.relevant Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review the December 2014 Order and the Order Denying Rehearing, andRehearing; that petition was denied on November 4, 2016.
In 2002, the FERC concluded that it would apply light-handed regulation over the rates, termsJune of 2018, CCL Stage III, CCL and conditions agreed to by parties for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at non-discriminatory rates or maintain a tariff or rate schedule on fileCCP filed an application with the FERC as distinguishedfor authorization under Section 3 of the NGA to site, construct and operate the Corpus Christi Stage 3 Project at the existing Liquefaction Project and pipeline location, which is being developed by a wholly owned subsidiary of Cheniere that is not owned or controlled by us. In November 2019, the FERC authorized the Corpus Christi Stage 3 Project. The Corpus Christi Stage 3 Project consists of the addition of seven midscale Trains and related facilities. The order is not subject to appellate court review. In 2020, the FERC authorized CCP to construct and operate a portion of the Corpus Christi Stage 3 Project (Sinton Compressor Station Unit No. 1) on an interim basis independently from the requirements applied to our FERC-regulated natural gas pipeline. The EPAct codifiedremaining the FERC’s policy, but those provisions expired on January 1, 2015. Nonetheless, we see no indication thatCorpus Christi Stage 3 Project facilities, which received FERC approval for in-service in December 2020.
On September 27, 2019, CCL filed a request with the FERC intendspursuant to modifySection 3 of the NGA, requesting authorization to increase the total LNG production capacity of the terminal from currently authorized levels to an amount which reflects more accurately the capacity of the facility based on enhancements during the engineering, design and construction process, as well
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as operational experience to date. The requested authorizations do not involve construction of new facilities. Corresponding applications for authorization to export the incremental volumes were also submitted to the DOE. The DOE issued Orders granting authorization to export LNG to FTA countries in April 2020 and to non-FTA countries in March 2022. In October 2021, the FERC issued its longstanding policyOrders Amending Authorization under Section 3 of light-handed regulationthe NGA. In March 2022, the DOE authorized the export of an additional 108.16 Bcf/yr of domestically produced LNG terminals.by vessel from the Corpus Christi LNG Terminal through December 31, 2050 to non-FTA countries, that were previously authorized for FTA countries only.
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 material 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 have not materially affected our construction or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement of material fact or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud or deceit upon any entity.operations.
DOE Export Licenses
The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG terminalTerminal as discussed in Our Liquefaction Project. 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. PHMSA 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.
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Other Governmental Permits, Approvals and Authorizations
Commodity Futures Trading Commission (“CFTC”)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.those markets. The regulatory regime created byCFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, is designed primarily to (1) regulate certain participants inincluding the swaps markets, including entities falling withinspeculative position limit rules. Given the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of standardized swaps of certain classes as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authorityrecent enactment of the 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.be uncertain, but is not expected to be material.
As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators havealso adopted rules to requirerequiring Swap Dealers and Major Swap Participants,(as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules which, as to the collection of initial margin, are being phased in, do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.
Environmental Regulation
The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations require significant expenditures for compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution.pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
Clean Air Act (“CAA”)
The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by any such requirements.
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On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022. We do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.
We are supportive of regulations reducing greenhouse gas (“GHG”) emissions over time. Since 2009, the EPA has promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule for multiple sections of the economy. This rule requires mandatoryGHG emissions regulations related to reporting and reductions of GHG emissions from stationary sources, including fuel combustion sources. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, theour facilities. The EPA has defined GHG
From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory actionOn August 16, 2022, President Biden signed H.R. 5376(P.L. 117-169), the Inflation Reduction Act of 2022 (“IRA”) which includes a charge on methane emissions above a certain threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program (“GHGRP”) Part 98 (“Subpart W”) regulations. The charge starts at $900 per metric ton of methane in 2024, $1,200 per metric ton in 2025, and increasing to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap$1,500 per metric ton in 2026 and trade programs. It is not possible atbeyond. At this time, we do not expect it to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, contracts,operations, financial condition operatingor results cash flow, liquidity and prospects.of operations.
Coastal Zone Management Act (“CZMA”)
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 the Liquefaction Projectour Corpus Christi LNG Terminal or the Corpus CristiChristi 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 that our operations, or the construction and operations of our Liquefaction Project, will be materially and adversely affected by such regulatory actions.
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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 80 mtpa of import capacity over the near-term to secure access to LNG and displace Russian gas imports. In India, there are nearly 12,000 kilometers of gas pipelines under construction to expand the gas distribution network and increase access to natural gas. And in China, billions of U.S. dollars have already been invested and hundreds of billions of U.S. dollars are expected to be further invested all along the natural gas value chain to decrease harmful emissions.
As a result of these dynamics, we expect gas and LNG to continue to play an important role in satisfying energy demand going forward. In its fourth quarter 2022 forecast, Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 53%, from 388.5 mtpa, or 18.6 Tcf, in 2021, to 595.7 mtpa, or 28.6 Tcf, in 2030 and to 677.8 mtpa or 32.5 Tcf in 2040. In its fourth quarter 2022 forecast, WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 537 mtpa in 2030, declining to 490 mtpa in 2040. This could result in a market need for construction of an additional approximately 59 mtpa of LNG production by 2030 and about 187 mtpa by 2040. As a cleaner burning fuel with lower emissions than coal or liquid fuels in power generation, we expect gas and LNG to play a central role in balancing grids and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project currently does not experience competitionand Corpus Christi Stage 3 Project are competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.
Our LNG terminal business has 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. 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 88% of the total anticipated production capacity from the Liquefaction Project, with approximately 18 years of weighted average remaining life as of December 31, 2022, which includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to Trains 1 and 2. We have entered into eight fixed price SPAs with termsthe contracted volumes irrespective of at least 20 years (plus extension rights) with seven third parties that will utilize substantially alltheir election to cancel or suspend deliveries of the liquefaction capacity available from these Trains. Each customer will be required to pay an escalating fixed fee for its annual contract quantity even if it elects not to purchase any LNG from us.cargoes.
When CCL needs to replace any existing SPA or enter into new SPAs, weCCL will compete on the basis of price per contracted volume of LNG with other natural gas liquefaction projects throughout the world. Cheniere is currently developing natural gas
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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.
Consequently, we are requiredcollaborating with natural gas midstream companies, methane detection technology providers and/or leading academic institutions on quantification, monitoring, reporting and verification (“QMRV”) of GHG research and development projects, co-founding and sponsoring multidisciplinary research and education initiatives led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines.
Cheniere also joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative in October 2022.
Our total expenditures related to be paid even if the customers electclimate initiatives, including capital expenditures, were not material to cancel or suspend deliveryour Consolidated Financial Statements during the years ended December 31, 2022, 2021 and 2020. However, as 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 initiatives to evolve accordingly. While we have contracted an aggregate amountnot incurred material direct capital expenditures related to climate change, we aspire to conduct our business in a safe and responsible manner and are proactive in our management of LNG that is between approximately 85%environmental impacts, risks and opportunities. We face certain business and operational risks associated with physical impacts from climate change, such as potential increases in severe weather events or changes in weather patterns, in addition to 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. continues 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
Our assets are generally held by or under our subsidiaries. We conduct most of our business through these subsidiaries, including the development and constructionoperation of our Liquefaction Project.
Employees
We have no employees. We have contracts with Cheniere and its subsidiaries for operations, maintenance and management services. As of JanuaryDecember 31, 2018,2022, Cheniere and its subsidiaries had 1,2301,551 full-time employees, including 231337 employees who directly supported the Liquefaction Project. See Note 13—Related Party Transactions of our Notes to Consolidated Financial Statements for a discussion of the services agreements pursuant to which general and administrative services are provided to CCL and CCP.
Available Information
Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We 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.Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content
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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 factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flow,flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
•Risks Relating to the Completion of Our Liquefaction FacilitiesOperations and the DevelopmentIndustry; and Operation of Our Business.
Risks Relating to Our Financial Matters
Our existing level of cash resources negative operating cash flow and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
As of December 31, 2017,2022, we had zerono cash and cash equivalents, $226.6$738 million of current restricted cash and $6.7cash equivalents, $4.6 billion of available commitments under our credit facilities and $7.3 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 to finance the construction of Train 3.the Corpus Christi Stage 3 Project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings 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 theseour credit 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, 2022, we had SPAs with us and agreed to pay us an aggregatea total of
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
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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, other than certain derivatives for which we have elected to apply accrual accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to 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. 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 includes $4.9 billion and $4.2 billion, respectively, of losses resulting from changes in the fair values of our derivatives, of which substantially all of such losses were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements.
These transactions and other derivative transactions have and may continue to result in substantial volatility in results of operations reported under GAAP, particularly in periods of significant commodity, currency or financial market variability. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
In addition, our liquidity may be adversely impacted by the cash margin requirements of the commodities exchanges or the failure of a counterparty to perform in accordance with a contract. As of December 31, 2022 and 2021, we had collateral posted with counterparties by us of $76 million and $13 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 years ended December 31, 2021 and 2020, four TBtu and 17 TBtu, respectively, were 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.
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Table of the over-the-counter (“OTC”) derivatives market and entities like us that participate in that market may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributableContents
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 terminalspipeline and to secure natural gas feedstock for our liquefaction facilities.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various other conditions.factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of natural gas to our pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transport across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our ability to complete development and/or construction of additional Trains will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient financial resources to construct Stage 2 or satisfy the other conditions, including regulatory conditions, required to construct Stage 2,funding, we may be unable to fully develop the Liquefaction Project and may suffer adverse consequences under certain existing contractual arrangements.execute our business strategy.
We need to meet significant additional conditions to construct Stage 2 as partcontinuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. The commercial development of the Liquefaction Project, including regulatory conditions. The constructionan LNG facility takes a number of Stage 2 as part of the Liquefaction Project will constitute an “Expansion” under the terms of our Common Terms Agreementyears and the CCH Indenturerequires a substantial capital investment that is dependent on sufficient funding and would require us to meet certain conditions thereunder, including obtaining the consent of our senior lenders under the Common Terms Agreement and the demonstration of a fixed projected debt service coverage ratio of at least 1.40:1.00 under the CCH Indenture.commercial interest, among other factors.
Cost overruns and delays in the completion of one or more Trains orour expansion projects, including the Corpus Christi Pipeline,Stage 3 Project, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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successfully under their agreements, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules or comply with existing or future EPC contracts resulting from the occurrence of certain specified events that may give Bechtel the right to cause us to enter into change ordersenvironmental or resulting from changes with which we otherwise agree. We have already experienced increased costs due to change orders. Cheniere does not have any prior experience in constructing liquefaction facilities other than the ongoing experience obtained in connection with the construction of Trains at Cheniere’s natural gas liquefaction facility at Sabine Pass (the “Sabine Pass Liquefaction Project”). Other than Trains 1 through 4 of the Sabine Pass Liquefaction Project, as of January 2018, no liquefaction facilities have been constructed and placed in service in the United States in over 40 years.regulations. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations. Additionally, our SPAs generally provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The construction and operation of the Corpus Christi LNG Terminal and the operation of the Corpus Christi Pipeline 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 leadresult in significant delays in commencement or interruptions of operations and/or in damage to reduced revenues or terminationdestruction of oneour facilities or moredamage 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 SPAs by our customers.
We are dependent on Bechtelour EPC partners and other contractors for the successful completion of the Liquefaction Project.Corpus Christi Stage 3 Project and any potential expansion projects.
Timely and cost-effective completion of the LiquefactionCorpus Christi Stage 3 Project and any potential expansion projects 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 Bechtelour 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-partythird 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.
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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 LiquefactionCorpus Christi Stage 3 Project and any potential expansion projects, 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 BechtelEPC partners and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as provided under the agreement.
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 LiquefactionCorpus Christi Stage 3 Project and any potential expansion projects, or result in a contractor’s unwillingness to perform further work on the Liquefaction Project.work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows,flow, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
•competitive liquefaction capacity in North America;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions, including 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;gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
•cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources, such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•political conditions in customer regions;
•sudden decreases in demand for LNG as a result of natural gas producing regions;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 imports into or exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows,flow, liquidity and prospects.
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Failure of exported LNG to be a long-term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Liquefaction Project will be,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 North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction or regasification facilities in the United States.
As described in Market Factors and Competition, we have contracted through our SPAs and IPM agreements approximately 88% of the total anticipated production capacity from the Liquefaction Project with approximately 18 years of weighted average remaining life as of December 31, 2022. However, as a result of thesethe factors described above and other factors, the LNG we produce may not beremain a long term competitive source of energy in the United States or internationally. The failure of LNGinternationally, particularly when our existing long term contracts begin to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or to the United States on a commercial basis.expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG to or from the United States generally, or from the Liquefaction Project specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We face competition based upon the international market price for LNG.
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to 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 placednot currently available.
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A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Facilities, could negatively impact our operations, result in service, its operations will involve significant risks.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.
complete shutdown of its pipeline system for six days. Should multiple of the facilities performing below expected levels of efficiency;
Outbreaks of infectious diseases, such as the outbreak of 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 the Delta and Omicron variants, has had no adverse impact on economic terms thatour on-going operations, the risk of future variants is unknown. While we believe we can continue to mitigate any significant adverse impact to our employees and operations at our critical facilities related to the virus in 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, including employees of Cheniere and its subsidiaries, for key personnel, and the unavailability of skilled workers or Cheniere’s failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.
As of December 31, 2022, Cheniere and its subsidiaries had 1,551 full-time employees, including 337 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 meetprovide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our feed gas transportation requirements, whichfacilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing, including the liquefaction facility operated by SPL (the “SPL Project”), for the time and expertise of Cheniere’s personnel. Further, we and Cheniere face competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.
Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on us.
A shortage in the labor pool of skilled workers, remoteness of our SPAssite locations or other general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could have a material adverse effect onrequire an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Additionally,
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We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.
We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. These agreements involve conflicts of interest between us, on the capacityone hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently operating the SPL Project in Cameron Parish, Louisiana, and is developing related facilities and a second natural gas pipeline at a site adjacent to the Liquefaction Project, and may continue to enter in commercial arrangements with respect to any future expansion of the Liquefaction Project.
We have or will have numerous contracts and commercial arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements with one or more Cheniere-affiliated entities as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.
We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.
Risks Relating to Regulations
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipeline and the export of LNG could impede operations and construction and could have a material adverse effect on us.
The design, construction and operation of interstate natural gas pipelines, our LNG terminal, including the Liquefaction Project and other facilities, as well as the import and export of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.
To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the three Trains and related facilities of the Liquefaction Project and the seven midscale trains and related facilities for the Corpus Christi Stage 3 Project, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Corpus Christi Pipeline and the interconnecting pipelinespipeline for the Corpus Christi Stage 3 Project. In September 2022, CCL and another subsidiary of Cheniere entered the pre-filing review process with the FERC under the National Environmental Policy Act for Midscale Trains 8 and 9. To date, the DOE has also issued orders under Section 4 of the NGA authorizing CCL to export domestically produced LNG. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipeline on land owned by third parties. If we were to lose these rights or be required to relocate our pipeline, our business could be materially and adversely affected.
Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. We are currently in compliance with such conditions; however, failure to comply or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which may notarise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns, could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be sufficientsubject to accommodate any additional Trains. Development of any additional Trainsrehearing requests, appeals and other challenges. There is no assurance that we will require us to secure additional pipeline transportation capacity butobtain and maintain these governmental permits, approvals and authorizations, or that we may notwill be able to do soobtain them on commercially reasonable terms or at all.
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
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construction and mayoperation of pipelines, the rates, terms and conditions of service and 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;
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 Christiconstruction and operation of our LNG terminal, docks 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 to 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.
The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that will apply to our facilities beginning in calendar year 2024. In October 2015, the EPA promulgated a final rule to implement the Obama Administration’s Clean Power Plan, which is designed to reduce GHG emissions from power plants in the United States. In February 2016, the U.S. Supreme Court stayed the final rule, effectively suspending the duty to comply with the rule until certain legal challenges are resolved. In March 2017, President Trump directed EPA via Executive Order to review and determine whether it is appropriate to revise or rescind the Clean Power Plan. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan after concluding the October 2015 final rule exceeds EPA’s statutory authority under the CAA. The October 2017 proposal does not include regulations to replace the Clean Power Plan and EPA stated in the October 2017 proposal that it has not determined whether it will issue replacement regulations to regulate GHG emissions from existing EGUs. The Trump Administration announced in June 2017 that the United States would withdraw from the Paris Accord, anaddition, other international, agreement within the United Nations Framework Convention on Climate Change under which the Obama Administration committed the United States to reducing its economy-wide GHG emission by 26-28% below 2005 levels by 2025. Other federal and state initiatives may be considered in the future to address GHG emissions through for example, United States treaty commitments, direct regulation, market-based regulations such as a carbonGHG emissions tax or cap-and-trade programs.programs or clean energy or performance-based standards. Such initiatives including a future replacement rule for the Clean Power Plan could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.
Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.
On February 28, 2022, the EPA removed a stay of formaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022. We do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals,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
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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, 2022 and 2021. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
•perform ongoing assessments of diversificationpipeline safety and compliance;
•identify and characterize applicable threats to pipeline segments that could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidityimpact a high consequence area;
•improve data collection, integration and prospects.analysis;
•repair and remediate the pipeline as necessary; and
We are required to our lack of asset and geographic diversification, an adverse development at the Liquefaction Facility, the Corpus Christi Pipeline,utilize pipeline integrity 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. Although no fines or penalties have been imposed on us to date, should we maintained more diverse assetsfail to comply with applicable statutes and operating areas.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.LEGAL PROCEEDINGS |
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.
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 2020 items and variance drivers between the year ended December 31, 2021 as compared to December 31, 2020 are not included herein and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2021.
Our discussion and analysis includes the following subjects:
Overview
We are a limited liability company formed by Cheniere Energy, Inc. (“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 (the “Corpus Christi LNG Terminal”) with three operational Trains. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for up to seven midscale Trains. We also own a pipeline that interconnects the Corpus Christi LNG Terminal with number of large interstate and intrastate pipelines (the “Corpus Christi Pipeline” and together with the existing operational Trains and the midscale Trains, the “Liquefaction Project”). For further discussion of our business, see Items 1. and 2. Business and Properties.
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We contract our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Through our SPAs and IPM agreements, we have contracted approximately 88% of the total anticipated production capacity from the Liquefaction Project with approximately 18 years of weighted average remaining life as of December 31, 2022. We believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our business in the future.
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Overview of Significant Events
Our significant events since January 1, 2022 and through the filing date of this Form 10-K include the following:
Strategic
•In November 2022, CCL and Cheniere Marketing entered into an SPA for approximately 0.85 mtpa of LNG associated with the IPM agreement between CCL and Apache Corporation and an SPA for approximately 2.55 mtpa of LNG associated with the IPM agreement between CCL and EOG Resources, Inc.
•In November 2022, CCL and Cheniere Marketing entered into Shipping Services Agreements for the provision of certain shipping and transportation-related services associated with (1) the SPA between CCL and Foran Energy Group Co. Ltd. and (2) the SPA between Cheniere Marketing and CPC Corporation, Taiwan, which will be novated from Cheniere Marketing to CCL following substantial completion of Train 6 of the Corpus Christi Stage 3 Project.
•In September 2022, CCL and another subsidiary of Cheniere entered the pre-filing review process with the FERC under the National Environmental Policy Act for an expansion adjacent to the CCL Project consisting of two midscale Trains with an expected total production capacity of approximately 3 mtpa of LNG (“Midscale Trains 8 and 9”).
•In July 2022, CCL entered into a long-term LNG SPA with PTT Global LNG Company Limited (“PTTGL”), under which PTTGL has agreed to purchase 20 million tonnes of LNG from CCL for twenty years beginning in 2026. The SPA calls for a combination of FOB and DAT deliveries. The purchase price for LNG under the SPA is indexed to the Henry Hub price, plus a fixed liquefaction fee.
•In March 2022, CCL amended its existing long-term SPA with Engie SA (“Engie”), increasing the volume Engie has agreed to purchase from CCL to approximately 11 million tonnes of LNG on an FOB basis, and extending the term to approximately 20 years, which began in September 2021.
•On June 15, 2022, Cheniere’s Board made a positive FID with respect to the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel under the EPC contract to commence construction of the Corpus Christi Stage 3 Project effective June 16, 2022. In connection with the positive FID, CCL Stage III was contributed to us and subsequently merged with and into CCL, with CCL the surviving company of the merger and our wholly owned subsidiary. Notable contracts received by CCL in connection with the merger included the following:
◦IPM agreements held by CCL Stage III with ARC Resources U.S. Corp (“ARC U.S.”), EOG Resources, Inc. and Apache Corporation, each with terms of approximately 15 years, aggregating approximately 65 million tonnes, approximately 40 million tonnes of which commences with commercial operations of certain Trains of the Corpus Christi Stage 3 Project (the “Transferred IPM Agreements”);
◦SPAs held by Cheniere Marketing International LLP (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, or its subsidiaries, with Foran Energy Group, Ltd, CPC Corporation, Sinochem Group Co. Ltd. and PKN ORLEN S.A. (“PKN ORLEN”, the surviving entity after the merger with Polskie Gornictwo Naftowe I Gazownictwo S.A. (“PGNiG”)), for which CCL entered into a newly executed agreement between CCL and PKN ORLEN taking the place of a portion of the term of the existing agreement between PKN ORLEN and Cheniere Marketing, aggregating approximately 105 million tonnes of LNG to be delivered through 2046; and
◦the aforementioned EPC contract with Bechtel for the Corpus Christi Stage 3 Project for a contract price of approximately $5.5 billion, subject to adjustment only by change order.
•In June 2022, CCL and Cheniere Marketing entered into an SPA for a term of 15 years for approximately 44 TBtu per annum of LNG associated with the IPM agreement between CCL and ARC U.S. referenced above.
Operational
•As of February 17, 2023, over 660 cumulative LNG cargoes totaling approximately 45 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
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Financial
•In December 2022, Cheniere repurchased $752 million in aggregate principal amount outstanding of our 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”) pursuant to a tender offer, with cash on hand. In January 2023, the remaining outstanding principal amount of $498 million of the 2024 CCH Senior Notes was redeemed with cash on hand.
•In June 2022, CCH amended and restated its term loan credit facility (the “CCH Credit Facility”) and its working capital facility (the “CCH Working Capital Facility”) to, among other things, (1) increase the commitments to approximately $4.0 billion and $1.5 billion for the CCH Credit Facility and the CCH Working Capital Facility, respectively, which are intended to fund a portion of the cost of developing, constructing and operating the Corpus Christi Stage 3 Project, (2) extend the maturity of the CCH Credit Facility to the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project and extend the maturity of the CCH Working Capital Facility to June 15, 2027, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.
Market Environment
The LNG market in 2022 saw unprecedented price volatility across all natural gas and LNG benchmarks. Gas market fundamentals across the globe were tight and exacerbated by the Russia / Ukraine war risks, and later by the drastic reduction in Russian natural gas flows to the European Union (“EU”). Concerns over low natural gas and LNG inventories and low additional LNG supply availability early in the year were intensified by the war dynamics in Europe and by further constraints on natural gas and LNG supplies caused by the outage at the Freeport LNG facility in June and the explosion on the Nordstream 1 and Nordstream 2 Pipelines in September. Several EU policy initiatives were passed to ensure underground gas storage in the region was filled before winter. Europe had to compete for LNG cargoes resulting in unprecedented price spikes. These conditions were worsened by high coal prices, low nuclear generation output and low hydro levels in Europe, which limited optionality for power generators and deepened the energy crisis in Europe.
Despite the generally tight supply conditions, according to Kpler, global LNG demand grew by approximately 5% from 2021, adding an additional 19.5 million tonnes to the overall market. LNG imports into Europe and Turkey, increased by 45.9 million tonnes, or 61% year-over-year in 2022. This growth was primarily accompanied by a pronounced slowdown in economic activity in China, which contributed to a 7% decrease in Asia’s LNG demand of 19.1 million tonnes from 2021. These sizeable EU LNG requirements resulting from the war fallout and the increase in global demand, especially demand for increased imports to Europe and Turkey, exposed the vulnerability of the LNG industry in terms of supply constraints and under-investments. This was manifested in the price levels and the magnitude of the price spreads between the benchmarks. As an example, the Dutch Title Transfer Facility (“TTF”) monthly settlement prices averaged $40.9/MMBtu in 2022, approximately 184% higher than the $14.4/MMBtu average in 2021, and the TTF monthly settlement prices averaged $42.3/MMBtu in the fourth quarter of 2022, approximately 46% higher than the $28.9/MMBtu average in the fourth quarter of 2021. Similarly, the 2022 average settlement price for the Platts Japan Korea Marker (“JKM”) increased 128% year-over-year to an average of $34.2/MMBtu in 2022, and the fourth quarter of 2022 average settlement price for the JKM increased 38% year-over-year to an average of $38.5/MMBtu. This extreme price increase triggered a strong supply response from the U.S., which played a significant role in balancing the global LNG market. Despite the outage at Freeport LNG, the U.S. exported approximately 77 million tonnes of LNG in 2022, a gain of approximately 9% from 2021, as the market continued to pull on supplies from our facilities and those of our competitors. Exports from our Liquefaction Project reached 14.9 million tonnes, representing over 10% of the gain in the U.S. total for the year.
Despite the global impacts of the Russia / Ukraine war, we do not believe we have significant exposure to adverse direct or indirect impacts of the war, as we do not conduct business in Russia and refrain from business dealings with Russian entities. Additionally, we are not aware of any specific adverse direct or indirect effects of the war on our supply chain. Consequently, we believe we are well positioned to help meet the needs of our international LNG customers to overcome their supply shortages.
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Results of Operations
| Year Ended December 31, | |||||||||||||||||||||||||||||
| (in millions) | 2022 | 2021 | Variance | ||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||
| LNG revenues | $ | 6,336 | $ | 3,907 | $ | 2,429 | |||||||||||||||||||||||
| LNG revenues—affiliate | 3,027 | 1,887 | 1,140 | ||||||||||||||||||||||||||
| Total revenues | 9,363 | 5,794 | 3,569 | ||||||||||||||||||||||||||
| Operating costs and expenses | |||||||||||||||||||||||||||||
| Cost of sales (excluding items shown separately below) | 9,656 | 4,326 | 5,330 | ||||||||||||||||||||||||||
| Cost of sales—affiliate | 103 | 50 | 53 | ||||||||||||||||||||||||||
| Cost of sales—related party | — | 146 | (146) | ||||||||||||||||||||||||||
| Operating and maintenance expense | 458 | 423 | 35 | ||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | 121 | 106 | 15 | ||||||||||||||||||||||||||
| Operating and maintenance expense—related party | 9 | 9 | — | ||||||||||||||||||||||||||
| General and administrative expense | 8 | 7 | 1 | ||||||||||||||||||||||||||
| General and administrative expense—affiliate | 38 | 28 | 10 | ||||||||||||||||||||||||||
| Depreciation and amortization expense | 445 | 420 | 25 | ||||||||||||||||||||||||||
| Other | 6 | 2 | 4 | ||||||||||||||||||||||||||
| Total operating costs and expenses | 10,844 | 5,517 | 5,327 | ||||||||||||||||||||||||||
| Income (loss) from operations | (1,481) | 277 | (1,758) | ||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (432) | (447) | 15 | ||||||||||||||||||||||||||
| Loss on modification or extinguishment of debt | (37) | (9) | (28) | ||||||||||||||||||||||||||
| Interest rate derivative gain (loss), net | 2 | (1) | 3 | ||||||||||||||||||||||||||
| Other income, net | 6 | — | 6 | ||||||||||||||||||||||||||
| Total other expense | (461) | (457) | (4) | ||||||||||||||||||||||||||
| Net loss | $ | (1,942) | $ | (180) | $ | (1,762) | |||||||||||||||||||||||
Operational volumes loaded and recognized from the Liquefaction Project
| Year Ended December 31, | |||||||||||||||||||||||||||||
| (in TBtu) | 2022 | 2021 | |||||||||||||||||||||||||||
| Volumes loaded during the current period | 775 | 734 | |||||||||||||||||||||||||||
| Less: volumes loaded during the current period and in transit at the end of the period | (3) | — | |||||||||||||||||||||||||||
| Total volumes recognized in the current period | 772 | 734 | |||||||||||||||||||||||||||
Net loss
The unfavorable variance of $1.8 billion for the year ended December 31, 2022 as compared to the same period of 2021 was substantially all attributable to increased derivative losses from changes in fair value and settlements of $2.0 billion between the years, of which $1.2 billion related to our IPM agreements which we procure natural gas at a price indexed to international gas prices. Included in the derivative loss incurred during the year ended December 31, 2022 was a loss incurred of $2.1 billion associated with, and following the Contribution of, the Transferred IPM Agreements on June 15, 2022, primarily attributable to CCL’s lower credit risk profile relative to that of CCL Stage III, resulting in a higher derivative liability given reduced risk of CCL’s own nonperformance.
Partially offsetting the increased net loss during the periods was an increase in LNG revenues, net of cost of sales and excluding the effect of derivative losses, of $347 million, of which approximately 70% was attributable to higher margins on sales indexed to Henry Hub, with variable consideration on our long-term SPAs generally priced at 115% of Henry Hub, and approximately 30% was attributable to increased volume delivered between the comparable periods, in part due to the
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substantial completion and commencement of operations of Train 3 of the Liquefaction Project, which achieved substantial completion on March 26, 2021 (the “Train 3 Completion”).
The following is additional detailed discussion of the significant variance drivers of the change in net loss by line item:
Revenues. $3.6 billion increase between comparable periods primarily attributable to:
•$3.0 billion increase due to higher pricing per MMBtu, from increased Henry Hub pricing; and
•$514 million increase due to higher volumes of LNG delivered between the periods, which increased 38 TBtu or 5%, as result of the additional production capacity of approximately 5 mtpa arising from the Train 3 Completion.
Operating costs and expenses. $5.3 billion increase between comparable periods primarily attributable to:
•$3.2 billion increase in cost of sales excluding the effect of derivative losses described below, primarily as a result of $2.8 billion in increased cost of natural gas feedstock largely due to higher U.S. natural gas prices and, to a lesser extent, from increased volume of natural gas liquified and delivered as LNG, as discussed above under the caption Revenues; and
•$2.0 billion increase in derivative losses from changes in fair value and settlements included in cost of sales, from $1.2 billion in the year ended December 31, 2021 to $3.2 billion in the year ended December 31, 2022, primarily due to non-cash unfavorable changes in fair value of our commodity derivatives that are attributed to positions indexed to international gas prices.
Significant factors affecting our results of operations
In addition to sources and uses of liquidity as discussed in Liquidity and Capital Resources, below are additional significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments, which in addition to managing exposure to commodity-related marketing and price risks are utilized to manage exposure to changing interest rates volatility, are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreements, including those transferred to CCL during the year ended December 31, 2022 as described further in Overview of Significant Events, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control, notwithstanding the operational intent to mitigate risk exposure over time.
Commissioning cargoes
Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the year ended December 31, 2021, we realized offsets to LNG terminal costs of $143 million corresponding to 28 TBtu of LNG that were related to the sale of commissioning cargoes. We did not record any offsets to LNG terminal costs during the year ended December 31, 2022.
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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. In the second partial berth.long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The Liquefaction Project also includestable below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
| December 31, 2022 | |||||||||||
| Restricted cash and cash equivalents designated for the Liquefaction Project | $ | 738 | |||||||||
| Available commitments under our credit facilities (1): | |||||||||||
| CCH Credit Facility | 3,260 | ||||||||||
| CCH Working Capital Facility | 1,322 | ||||||||||
| Total available commitments under our credit facilities | 4,582 | ||||||||||
| Total available liquidity | $ | 5,320 | |||||||||
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2022. 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, 2022 will be driven by future sources of liquidity and future cash requirements as further discussed below under the Corpus Christi Pipeline that will interconnect the Corpus Christi LNG terminal with several interstatecaption Future Sources 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. ConstructionUses of the Corpus Christi Pipeline is nearing completion.Liquidity.
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 CCH Senior Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or federal or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
Summarized financial information about us and the Guarantors as a group is omitted herein because such information would not be materially different from our Consolidated Financial Statements.
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Future Sources and Uses of Liquidity
Future Sources of Liquidity under Executed Contracts
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs which has not yet been recognized as revenue. This future consideration is in most cases not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2022. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the outstanding borrowings under our credit facility (the “2015 CCH Credit Facility”).
| 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 Contracts by Period (1) | ||||||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | |||||||||||||||||||||||
| LNG revenues (fixed fees) (2) | $ | 2.0 | $ | 9.6 | $ | 40.5 | $ | 52.1 | ||||||||||||||||||
| LNG revenues (variable fees) (2) (3) | 4.7 | 21.9 | 97.0 | 123.6 | ||||||||||||||||||||||
| Total | $ | 6.7 | $ | 31.5 | $ | 137.5 | $ | 175.7 | ||||||||||||||||||
(1)Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)LNG revenues (including $1.2 billion and $40.3 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2022. The DOE has authorizedpricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Certain of our contracts contain additional variable consideration based on the exportoutcome of domestically produced contingent events and the movement of various indexes. We have not included such variable consideration to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt.
LNG by vesselRevenues
Through our SPAs and IPM agreements, we have contracted approximately 88% of the total anticipated production capacity from the Corpus Christi LNG terminal to FTA countries for a 25-year term and to non-FTA countries for a 20-year term up to a combined totalLiquefaction Project, with approximately 18 years of weighted average remaining life as of December 31, 2022. The majority of the equivalentcontracted capacity is comprised of 767 Bcf/yr (approximately 15 mtpa) of natural gas. The terms of each of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 7 to 10 years from the date the order was issued.
In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $550 million$2.7 billion for Trainthe Liquefaction Project, including the Corpus Christi Stage 3 Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of BBB+, Baa1 and BBB+ by S&P Global Ratings, Moody’s Corporation and Fitch Ratings, respectively. A discussion of revenues under our SPAs can be found in Note 1 increasing2—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.
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Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2022, 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 September 2022, CCL and another subsidiary of firstCheniere entered the pre-filing review process with the FERC under the National Environmental Policy Act for Midscale Trains 8 and 9. 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.
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 Train 2our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures under executed contracts as of December 31, 2022 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | |||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | ||||||||||||||||||||
| Purchase obligations (2): | |||||||||||||||||||||||
| Natural gas supply agreements (3) | $ | 4.2 | $ | 13.5 | $ | 21.9 | $ | 39.6 | |||||||||||||||
| Natural gas transportation and storage service agreements (4) | 0.2 | 1.0 | 3.0 | 4.2 | |||||||||||||||||||
| Capital expenditures | 0.9 | 3.1 | — | 4.0 | |||||||||||||||||||
| Other purchase obligations (5) | 0.1 | 0.7 | 7.0 | 7.8 | |||||||||||||||||||
| Total | $ | 5.4 | $ | 18.3 | $ | 31.9 | $ | 55.6 | |||||||||||||||
(1)Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)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 conditions precedent 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, 2022. 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.
(5)Includes $7.5 billion of purchase obligations to affiliates under services agreements, $6.3 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 Corpus Christi LNG Terminal through long-term natural gas supply and 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
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liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global LNG market price paid for the natural gas feedstock purchase.
As of December 31, 2022, we have secured approximately 89% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2023. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2023. Natural gas supply is generally secured on an indexed pricing basis, 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 with CCP and certain third-partyfrom third party 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.
Corpus Christi Stage 3 Project
The total contract price offollowing table summarizes the EPC contract for Stage 1, which does not include the Corpus Christi Pipeline, is approximately $7.8 billion, reflecting amounts incurred under change orders through December 31, 2017. Total expected capital costs for Stage 1project 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 | 24.5% | ||||||||||
| Completion percentage of: | |||||||||||
| Engineering | 41.3% | ||||||||||
| Procurement | 36.9% | ||||||||||
| Subcontract work | 29.5% | ||||||||||
| Construction | 2.2% | ||||||||||
| Date of expected substantial completion | 2H 2025 - 1H 2027 | ||||||||||
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 2 ofCheniere for operations, maintenance and management services. Cheniere and its subsidiaries’ full-time employee headcount was 1,551, including 337 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 | ||||
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connection with reaching FID, we issued an aggregate principal amountmay be required to secure financing to meet the cash needs that such project will initially require, in support of $1.5 billioncommercializing 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 and 9. We expect that any potential future expansion at the Corpus Christi LNG Terminal would increase cash requirements to support expanded operations, although expansion could be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2022 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | |||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | ||||||||||||||||||||
| Debt (2) | $ | 0.5 | $ | 2.9 | $ | 3.9 | $ | 7.3 | |||||||||||||||
| Interest payments (2) | 0.3 | 1.1 | 0.8 | 2.2 | |||||||||||||||||||
| Total | $ | 0.8 | $ | 4.0 | $ | 4.7 | $ | 9.5 | |||||||||||||||
(1)The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)Debt and interest payments are based on the 2027 CCH Senior Notes,total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in addition toeffect at December 31, 2022, excluding debt and interest payments on the existing 2024 CCH Senior Notes and 2025which are based on the redemption payment made January 5, 2023. In December 2022, we issued a notice of redemption for the remaining aggregate principal amount outstanding of the 2024 CCH Senior Notes. TheOther than debt and interest payments on the 2024 CCH Senior Notes, are jointlydebt and severally guaranteed by our subsidiaries, CCL, CCPinterest payments do not contemplate repurchases, repayments and CCP GP (each a “Guarantor” and collectively, the “Guarantors”).
Additional Future Cash Requirements for Financing
Revised Capital Allocation Plan
In September 2022, the board of directors of Cheniere approved a revised long-term capital allocation plan, which may involve the remeasurement was a $58.9 million reduction torepayment, 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, reducingsenior notes. During the effective tax rate, was recordedyear ended December 31, 2022, we redeemed $2.4 billion of indebtedness pursuant to the valuation allowance, and therefore there was no impact to current period income tax expense.capital allocation plan.
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| Year Ended December 31, | |||||||||||||||||||||||||||||
| (in millions) | 2022 | 2021 | Variance | ||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||
| LNG revenues | $ | 6,336 | $ | 3,907 | $ | 2,429 | |||||||||||||||||||||||
| LNG revenues—affiliate | 3,027 | 1,887 | 1,140 | ||||||||||||||||||||||||||
| Total revenues | 9,363 | 5,794 | 3,569 | ||||||||||||||||||||||||||
| Operating costs and expenses | |||||||||||||||||||||||||||||
| Cost of sales (excluding items shown separately below) | 9,656 | 4,326 | 5,330 | ||||||||||||||||||||||||||
| Cost of sales—affiliate | 103 | 50 | 53 | ||||||||||||||||||||||||||
| Cost of sales—related party | — | 146 | (146) | ||||||||||||||||||||||||||
| Operating and maintenance expense | 458 | 423 | 35 | ||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | 121 | 106 | 15 | ||||||||||||||||||||||||||
| Operating and maintenance expense—related party | 9 | 9 | — | ||||||||||||||||||||||||||
| General and administrative expense | 8 | 7 | 1 | ||||||||||||||||||||||||||
| General and administrative expense—affiliate | 38 | 28 | 10 | ||||||||||||||||||||||||||
| Depreciation and amortization expense | 445 | 420 | 25 | ||||||||||||||||||||||||||
| Other | 6 | 2 | 4 | ||||||||||||||||||||||||||
| Total operating costs and expenses | 10,844 | 5,517 | 5,327 | ||||||||||||||||||||||||||
| Income (loss) from operations | (1,481) | 277 | (1,758) | ||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (432) | (447) | 15 | ||||||||||||||||||||||||||
| Loss on modification or extinguishment of debt | (37) | (9) | (28) | ||||||||||||||||||||||||||
| Interest rate derivative gain (loss), net | 2 | (1) | 3 | ||||||||||||||||||||||||||
| Other income, net | 6 | — | 6 | ||||||||||||||||||||||||||
| Total other expense | (461) | (457) | (4) | ||||||||||||||||||||||||||
| Net loss | $ | (1,942) | $ | (180) | $ | (1,762) | |||||||||||||||||||||||
Operational volumes loaded and Uses of Cashrecognized from the Liquefaction Project
| Year Ended December 31, | |||||||||||||||||||||||||||||
| (in TBtu) | 2022 | 2021 | |||||||||||||||||||||||||||
| Volumes loaded during the current period | 775 | 734 | |||||||||||||||||||||||||||
| Less: volumes loaded during the current period and in transit at the end of the period | (3) | — | |||||||||||||||||||||||||||
| Total volumes recognized in the current period | 772 | 734 | |||||||||||||||||||||||||||
Net loss
The following table summarizes the sources and usesunfavorable variance of our cash, cash equivalents and restricted cash$1.8 billion for the yearsyear ended December 31, 2017, 20162022 as compared to the same period of 2021 was substantially all attributable to increased derivative losses from changes in fair value and 2015 (in thousands). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amountssettlements 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, | |||||||||||
| 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 | |||||
Partially offsetting the increased net loss during the periods was an increase in LNG revenues, net of cost of sales and excluding the effect of derivative losses, of $347 million, of which approximately 70% was attributable to higher margins on sales indexed to Henry Hub, with variable consideration on our long-term SPAs generally priced at 115% of Henry Hub, and approximately 30% was attributable to increased volume delivered between the comparable periods, in part due to the
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substantial completion and commencement of operations of Train 3 of the Liquefaction Project, which wasachieved substantial completion on March 26, 2021 (the “Train 3 Completion”).
The following is additional detailed discussion of the significant variance drivers of the change in net loss by line item:
Revenues. $3.6 billion increase between comparable periods primarily attributable to:
•$3.0 billion increase due to higher pricing per MMBtu, from increased Henry Hub pricing; and
•$514 million increase due to higher volumes of LNG delivered between the periods, which increased 38 TBtu or 5%, as result of the additional production capacity of approximately 5 mtpa arising from the Train 3 Completion.
Operating costs and expenses. $5.3 billion increase between comparable periods primarily attributable to:
•$3.2 billion increase in cost of sales excluding the effect of derivative losses described below, primarily as a result of $2.8 billion in increased cost of natural gas feedstock largely due to higher U.S. natural gas prices and, to a lesser extent, from increased volume of natural gas liquified and delivered as LNG, as discussed above under the caption Revenues; and
•$2.0 billion increase in derivative losses from changes in fair value and settlements included in cost of sales, from $1.2 billion in the year ended December 31, 2021 to $3.2 billion in the year ended December 31, 2022, primarily due to non-cash unfavorable changes in fair value of our commodity derivatives that are attributed to positions indexed to international gas prices.
Significant factors affecting our results of operations
In addition to sources and uses of liquidity as discussed in Liquidity and Capital Resources, below are additional significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments, which in addition to managing exposure to commodity-related marketing and price risks are utilized to manage exposure to changing interest rates volatility, are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreements, including those transferred to CCL during the year ended December 31, 2022 as described further in Overview of Significant Events, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control, notwithstanding the operational intent to mitigate risk exposure over time.
Commissioning cargoes
Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset by $11.3 million paidagainst LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for infrastructure to support the Liquefaction Project.construction of that Train. During the year ended December 31, 2016,2021, we used an additional $44.4realized offsets to LNG terminal costs of $143 million primarily for infrastructurecorresponding to 28 TBtu of the Liquefaction Project, which included the $36.3 million of collateral paymentsLNG that were returnedrelated to usthe sale of commissioning cargoes. We did not record any offsets to LNG terminal costs during the year ended December 31, 2017.2022.
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Liquidity and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash inflows duringto meet our requirements in the year endedshort term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
| December 31, 2022 | |||||||||||
| Restricted cash and cash equivalents designated for the Liquefaction Project | $ | 738 | |||||||||
| Available commitments under our credit facilities (1): | |||||||||||
| CCH Credit Facility | 3,260 | ||||||||||
| CCH Working Capital Facility | 1,322 | ||||||||||
| Total available commitments under our credit facilities | 4,582 | ||||||||||
| Total available liquidity | $ | 5,320 | |||||||||
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2017 were $2.0 billion, primarily2022. 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, 2022 will be driven by future sources of liquidity and future cash requirements as further discussed below under the caption Future Sources and Uses of Liquidity.
Supplemental Guarantor Information
The 7.000% Senior Secured Notes due 2024, 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 3.751% (collectively, the “CCH Senior 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 CCH Senior 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 CCH Senior 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 CCH Senior Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or federal or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
Summarized financial information about us and the Guarantors as a group is omitted herein because such information would not be materially different from our Consolidated Financial Statements.
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Future Sources and Uses of Liquidity
Future Sources of Liquidity under Executed Contracts
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs which has not yet been recognized as revenue. This future consideration is in most cases not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2022. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed contracts as of December 31, 2022 (in billions):
| Estimated Revenues Under Executed Contracts by Period (1) | ||||||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | |||||||||||||||||||||||
| LNG revenues (fixed fees) (2) | $ | 2.0 | $ | 9.6 | $ | 40.5 | $ | 52.1 | ||||||||||||||||||
| LNG revenues (variable fees) (2) (3) | 4.7 | 21.9 | 97.0 | 123.6 | ||||||||||||||||||||||
| Total | $ | 6.7 | $ | 31.5 | $ | 137.5 | $ | 175.7 | ||||||||||||||||||
(1)Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of:of a variety of factors described in this annual report on Form 10-K.
LNG Revenues
Through our SPAs and IPM agreements, we have contracted approximately 88% of the 2027 CCH Senior Notes, which was used to prepay $1.4 billiontotal anticipated production capacity from the Liquefaction Project, with approximately 18 years of outstanding borrowings under the 2015 CCH Credit Facility;
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.
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Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2022, 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 September 2022, CCL and another subsidiary of borrowingsCheniere entered the pre-filing review process with the FERC under the 2015 CCH Credit Facility;
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 under executed contracts as of December 31, 20172022 (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) | |||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | ||||||||||||||||||||
| Purchase obligations (2): | |||||||||||||||||||||||
| Natural gas supply agreements (3) | $ | 4.2 | $ | 13.5 | $ | 21.9 | $ | 39.6 | |||||||||||||||
| Natural gas transportation and storage service agreements (4) | 0.2 | 1.0 | 3.0 | 4.2 | |||||||||||||||||||
| Capital expenditures | 0.9 | 3.1 | — | 4.0 | |||||||||||||||||||
| Other purchase obligations (5) | 0.1 | 0.7 | 7.0 | 7.8 | |||||||||||||||||||
| Total | $ | 5.4 | $ | 18.3 | $ | 31.9 | $ | 55.6 | |||||||||||||||
(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 conditions precedent 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, 2022. 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.
(5)Includes $7.5 billion of purchase obligations to affiliates under services agreements, $6.3 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 Corpus Christi LNG Terminal through long-term natural gas supply and 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 obligationsnatural gas under the IPM agreements generates a take-or-pay style fixed
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liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global LNG market price paid for the natural gas feedstock purchase.
As of December 31, 2017,2022, we have secured approximately 89% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2023. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2023. Natural gas supply is generally secured on an indexed pricing basis, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied conditions precedent as of December 31, 2022, we have secured up to 8,309 TBtu of natural gas feedstock through agreements with remaining terms that range up to 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 third party pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project.
Capital Expenditures
We enter into lump sum turnkey contracts with third party contractors for the 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 bares 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. Additionally, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity. See Financially Disciplined Growth section for further discussion.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of January 31, 2023:
| Overall project completion percentage | 24.5% | ||||||||||
| Completion percentage of: | |||||||||||
| Engineering | 41.3% | ||||||||||
| Procurement | 36.9% | ||||||||||
| Subcontract work | 29.5% | ||||||||||
| Construction | 2.2% | ||||||||||
| Date of expected substantial completion | 2H 2025 - 1H 2027 | ||||||||||
Additional Future Cash Requirements for Operations and Capital Expenditures
Corporate Activities
We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. Cheniere and its subsidiaries’ full-time employee headcount was 1,551, including 337 employees who directly supported the Liquefaction Project operations as of December 31, 2022. 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
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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 and 9. We expect that any potential future expansion at the Corpus Christi LNG Terminal would increase cash requirements to support expanded operations, although expansion could be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2022 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | |||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | ||||||||||||||||||||
| Debt (2) | $ | 0.5 | $ | 2.9 | $ | 3.9 | $ | 7.3 | |||||||||||||||
| Interest payments (2) | 0.3 | 1.1 | 0.8 | 2.2 | |||||||||||||||||||
| Total | $ | 0.8 | $ | 4.0 | $ | 4.7 | $ | 9.5 | |||||||||||||||
(1)The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)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, 2022, excluding debt and interest payments on the 2024 CCH Senior Notes which are based on the redemption payment made January 5, 2023. In December 2022, we issued a notice of redemption for the remaining aggregate principal amount outstanding of the 2024 CCH Senior Notes. Other than debt and interest payments on the 2024 CCH Senior Notes, debt and interest payments do not contemplate repurchases, repayments and retirements that we expect to make prior to contractual maturity. See further discussion in Note 11—Debt of our Notes to Consolidated Financial Statements.
Debt
As of December 31, 2022, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $7.3 billion and credit facilities with no outstanding balances. As of December 31, 2022, 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, 2022, our senior notes had $163.6a weighted average contractual interest rate of 4.64%. We amended the CCH Credit Facility and the CCH Working Capital Facility to incorporate a replacement rate as a result of the expected LIBOR transition. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.100% 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 1.25%. We had $178 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, 2022.
Additional Future Cash Requirements for Financing
Revised 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 Notessenior notes. During the year ended December 31, 2022, we redeemed $2.4 billion of indebtedness pursuant to Consolidated Financial Statements.the capital allocation plan.
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Results of Operations
| Year Ended December 31, | |||||||||||||||||||||||||||||
| (in millions) | 2022 | 2021 | Variance | ||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||
| LNG revenues | $ | 6,336 | $ | 3,907 | $ | 2,429 | |||||||||||||||||||||||
| LNG revenues—affiliate | 3,027 | 1,887 | 1,140 | ||||||||||||||||||||||||||
| Total revenues | 9,363 | 5,794 | 3,569 | ||||||||||||||||||||||||||
| Operating costs and expenses | |||||||||||||||||||||||||||||
| Cost of sales (excluding items shown separately below) | 9,656 | 4,326 | 5,330 | ||||||||||||||||||||||||||
| Cost of sales—affiliate | 103 | 50 | 53 | ||||||||||||||||||||||||||
| Cost of sales—related party | — | 146 | (146) | ||||||||||||||||||||||||||
| Operating and maintenance expense | 458 | 423 | 35 | ||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | 121 | 106 | 15 | ||||||||||||||||||||||||||
| Operating and maintenance expense—related party | 9 | 9 | — | ||||||||||||||||||||||||||
| General and administrative expense | 8 | 7 | 1 | ||||||||||||||||||||||||||
| General and administrative expense—affiliate | 38 | 28 | 10 | ||||||||||||||||||||||||||
| Depreciation and amortization expense | 445 | 420 | 25 | ||||||||||||||||||||||||||
| Other | 6 | 2 | 4 | ||||||||||||||||||||||||||
| Total operating costs and expenses | 10,844 | 5,517 | 5,327 | ||||||||||||||||||||||||||
| Income (loss) from operations | (1,481) | 277 | (1,758) | ||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (432) | (447) | 15 | ||||||||||||||||||||||||||
| Loss on modification or extinguishment of debt | (37) | (9) | (28) | ||||||||||||||||||||||||||
| Interest rate derivative gain (loss), net | 2 | (1) | 3 | ||||||||||||||||||||||||||
| Other income, net | 6 | — | 6 | ||||||||||||||||||||||||||
| Total other expense | (461) | (457) | (4) | ||||||||||||||||||||||||||
| Net loss | $ | (1,942) | $ | (180) | $ | (1,762) | |||||||||||||||||||||||
Operational volumes loaded and recognized from the Liquefaction Project
| Year Ended December 31, | |||||||||||||||||||||||||||||
| (in TBtu) | 2022 | 2021 | |||||||||||||||||||||||||||
| Volumes loaded during the current period | 775 | 734 | |||||||||||||||||||||||||||
| Less: volumes loaded during the current period and in transit at the end of the period | (3) | — | |||||||||||||||||||||||||||
| Total volumes recognized in the current period | 772 | 734 | |||||||||||||||||||||||||||
Net loss
The unfavorable variance of $1.8 billion for the year ended December 31, 2022 as compared to the same period of 2021 was substantially all attributable to increased derivative losses from changes in fair value and settlements of $2.0 billion between the years, of which $1.2 billion related to our IPM agreements which we procure natural gas at a price indexed to international gas prices. Included in the derivative loss incurred during the year ended December 31, 2022 was a loss incurred of $2.1 billion associated with, and following the Contribution of, the Transferred IPM Agreements on June 15, 2022, primarily attributable to CCL’s lower credit risk profile relative to that of CCL Stage III, resulting in a higher derivative liability given reduced risk of CCL’s own nonperformance.
Partially offsetting the increased net loss during the periods was $48.7an increase in LNG revenues, net of cost of sales and excluding the effect of derivative losses, of $347 million, of which approximately 70% was attributable to higher margins on sales indexed to Henry Hub, with variable consideration on our long-term SPAs generally priced at 115% of Henry Hub, and approximately 30% was attributable to increased volume delivered between the comparable periods, in part due to the
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substantial completion and commencement of operations of Train 3 of the Liquefaction Project, which achieved substantial completion on March 26, 2021 (the “Train 3 Completion”).
The following is additional detailed discussion of the significant variance drivers of the change in net loss by line item:
Revenues. $3.6 billion increase between comparable periods primarily attributable to:
•$3.0 billion increase due to higher pricing per MMBtu, from increased Henry Hub pricing; and
•$514 million increase due to higher volumes of LNG delivered between the periods, which increased 38 TBtu or 5%, as result of the additional production capacity of approximately 5 mtpa arising from the Train 3 Completion.
Operating costs and expenses. $5.3 billion increase between comparable periods primarily attributable to:
•$3.2 billion increase in cost of sales excluding the effect of derivative losses described below, primarily as a result of $2.8 billion in increased cost of natural gas feedstock largely due to higher U.S. natural gas prices and, to a lesser extent, from increased volume of natural gas liquified and delivered as LNG, as discussed above under the caption Revenues; and
•$2.0 billion increase in derivative losses from changes in fair value and settlements included in cost of sales, from $1.2 billion in the year ended December 31, 2017, compared2021 to a net loss of $85.5 million$3.2 billion in the year ended December 31, 2016. This $36.8 million decrease2022, primarily due to non-cash unfavorable changes in net lossfair value of our commodity derivatives that are attributed to positions indexed to international gas prices.
Significant factors affecting our results of operations
In addition to sources and uses of liquidity as discussed in 2017 was primarily a resultLiquidity and Capital Resources, below are additional significant factors that affect our results of decreased lossoperations.
Gains and losses on early extinguishment of debtderivative instruments
Derivative instruments, which in addition to managing exposure to commodity-related marketing and decreased derivative loss, net associated withprice risks are utilized to manage exposure to changing interest rate derivative activity.
| 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 | ) | |||||
Commissioning cargoes
Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the year ended December 31, 2016 primarily as a result2021, we realized offsets to LNG terminal costs of increased operating and maintenance expense and general and administrative expense from increased professional fees and labor costs.
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Liquidity and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
| December 31, 2022 | |||||||||||
| Restricted cash and cash equivalents designated for the Liquefaction Project | $ | 738 | |||||||||
| Available commitments under our credit facilities (1): | |||||||||||
| CCH Credit Facility | 3,260 | ||||||||||
| CCH Working Capital Facility | 1,322 | ||||||||||
| Total available commitments under our credit facilities | 4,582 | ||||||||||
| Total available liquidity | $ | 5,320 | |||||||||
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2022. 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, 2022 will be driven by future sources of liquidity and future cash requirements as further discussed below under the caption Future Sources and Uses of Liquidity.
Supplemental Guarantor Information
The 7.000% Senior Secured Notes due 2024, 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 3.751% (collectively, the “CCH Senior 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 CCH Senior 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 CCH Senior 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 CCH Senior Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or federal or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
Summarized financial information about us and the Guarantors as a group is omitted herein because such information would not be materially different from our Consolidated Financial Statements.
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Future Sources and Uses of Liquidity
Future Sources of Liquidity under Executed Contracts
Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs which has not yet been recognized as revenue. This future consideration is in most cases not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2022. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed contracts as of December 31, 2022 (in billions):
| Estimated Revenues Under Executed Contracts by Period (1) | ||||||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | |||||||||||||||||||||||
| LNG revenues (fixed fees) (2) | $ | 2.0 | $ | 9.6 | $ | 40.5 | $ | 52.1 | ||||||||||||||||||
| LNG revenues (variable fees) (2) (3) | 4.7 | 21.9 | 97.0 | 123.6 | ||||||||||||||||||||||
| Total | $ | 6.7 | $ | 31.5 | $ | 137.5 | $ | 175.7 | ||||||||||||||||||
(1)Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)LNG revenues (including $1.2 billion and $40.3 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated forward prices and basis spreads as of December 31, 2022. The pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt.
LNG Revenues
Through our SPAs and IPM agreements, we have contracted approximately 88% of the total anticipated production capacity from the Liquefaction Project, with approximately 18 years of weighted average remaining life as of December 31, 2022. 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 a FOB or DAT basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. The variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases and variable transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.7 billion for the Liquefaction Project, including the Corpus Christi Stage 3 Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of BBB+, Baa1 and BBB+ by S&P Global Ratings, Moody’s Corporation and Fitch Ratings, 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.
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Additional Future Sources of Liquidity
Available Commitments under Credit Facilities
As of December 31, 2022, 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 September 2022, CCL and another subsidiary of Cheniere entered the pre-filing review process with the FERC under the National Environmental Policy Act for Midscale Trains 8 and 9. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.
Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts
We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures under executed contracts as of December 31, 2022 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | |||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | ||||||||||||||||||||
| Purchase obligations (2): | |||||||||||||||||||||||
| Natural gas supply agreements (3) | $ | 4.2 | $ | 13.5 | $ | 21.9 | $ | 39.6 | |||||||||||||||
| Natural gas transportation and storage service agreements (4) | 0.2 | 1.0 | 3.0 | 4.2 | |||||||||||||||||||
| Capital expenditures | 0.9 | 3.1 | — | 4.0 | |||||||||||||||||||
| Other purchase obligations (5) | 0.1 | 0.7 | 7.0 | 7.8 | |||||||||||||||||||
| Total | $ | 5.4 | $ | 18.3 | $ | 31.9 | $ | 55.6 | |||||||||||||||
(1)Agreements in force as of December 31, 2022 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2022. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)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 conditions precedent 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, 2022. 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.
(5)Includes $7.5 billion of purchase obligations to affiliates under services agreements, $6.3 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 Corpus Christi LNG Terminal through long-term natural gas supply and 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
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liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global LNG market price paid for the natural gas feedstock purchase.
As of December 31, 2022, we have secured approximately 89% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2023. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2023. Natural gas supply is generally secured on an indexed pricing basis, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied conditions precedent as of December 31, 2022, we have secured up to 8,309 TBtu of natural gas feedstock through agreements with remaining terms that range up to 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 third party pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project.
Capital Expenditures
We enter into lump sum turnkey contracts with third party contractors for the 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 bares 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. Additionally, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity. See Financially Disciplined Growth section for further discussion.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of January 31, 2023:
| Overall project completion percentage | 24.5% | ||||||||||
| Completion percentage of: | |||||||||||
| Engineering | 41.3% | ||||||||||
| Procurement | 36.9% | ||||||||||
| Subcontract work | 29.5% | ||||||||||
| Construction | 2.2% | ||||||||||
| Date of expected substantial completion | 2H 2025 - 1H 2027 | ||||||||||
Additional Future Cash Requirements for Operations and Capital Expenditures
Corporate Activities
We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. Cheniere and its subsidiaries’ full-time employee headcount was 1,551, including 337 employees who directly supported the Liquefaction Project operations as of December 31, 2022. 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
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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 and 9. We expect that any potential future expansion at the Corpus Christi LNG Terminal would increase cash requirements to support expanded operations, although expansion could be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.
Future Cash Requirements for Financing under Executed Contracts
We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2022 (in billions):
| Estimated Payments Due Under Executed Contracts by Period (1) | |||||||||||||||||||||||
| 2023 | 2024 - 2027 | Thereafter | Total | ||||||||||||||||||||
| Debt (2) | $ | 0.5 | $ | 2.9 | $ | 3.9 | $ | 7.3 | |||||||||||||||
| Interest payments (2) | 0.3 | 1.1 | 0.8 | 2.2 | |||||||||||||||||||
| Total | $ | 0.8 | $ | 4.0 | $ | 4.7 | $ | 9.5 | |||||||||||||||
(1)The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2022. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
(2)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, 2022, excluding debt and interest payments on the 2024 CCH Senior Notes which are based on the redemption payment made January 5, 2023. In December 2022, we issued a notice of redemption for the remaining aggregate principal amount outstanding of the 2024 CCH Senior Notes. Other than debt and interest payments on the 2024 CCH Senior Notes, debt and interest payments do not contemplate repurchases, repayments and retirements that we expect to make prior to contractual maturity. See further discussion in Note 11—Debt of our Notes to Consolidated Financial Statements.
Debt
As of December 31, 2022, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $7.3 billion and credit facilities with no outstanding balances. As of December 31, 2022, 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, 2022, our senior notes had a weighted average contractual interest rate of 4.64%. We amended the CCH Credit Facility and the CCH Working Capital Facility to incorporate a replacement rate as a result of the expected LIBOR transition. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.100% 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 1.25%. We had $178 million aggregate amount of issued letters of credit under the CCH Working Capital Facility as of December 31, 2022.
Additional Future Cash Requirements for Financing
Revised 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. During the year ended December 31, 20162022, we redeemed $2.4 billion of indebtedness pursuant to the capital allocation plan.
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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, | ||||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||
| Net cash provided by operating activities | $ | 1,734 | $ | 1,424 | ||||||||||||||||
| Net cash used in investing activities | (980) | (240) | ||||||||||||||||||
| Net cash used in financing activities | (60) | (1,210) | ||||||||||||||||||
| Net increase (decrease) in restricted cash and cash equivalents | $ | 694 | $ | (26) | ||||||||||||||||
Operating Cash Flows
Operating cash flows during the years ended December 31, 2022 and 2021 were $1,734 million and $1,424 million, respectively. The $310 million increase between the periods was primarily related to cash used as working capital as a result of decreased development expensespayment timing differences and timing of cash receipts from decreased professional fees 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 | ) | ||||||||
Investing Cash Flows
Our investing cash net outflows in both years primarily were for the construction costs for the Liquefaction Project. The $740 million increase in 2022 compared to the year ended December 31, 2016. Loss on early extinguishment of debt recognized in 20172021 was attributableprimarily due to the write-offs of debt issuance costs of $32.5 million in May 2017 upon the prepayment of approximately $1.4 billion of outstanding borrowings under the 2015 CCH Credit Facility in connection with the issuance of the 2027 CCH Senior Notes. Loss on early extinguishment of debtspend during the year ended December 31, 2016 was primarily attributable2022 related to a $63.3 million write-offconstruction work performed by Bechtel for the Corpus Christi Stage 3 Project. We expect our capital expenditures to increase in future periods as construction work progresses on the Corpus Christi Stage 3 Project following the issuance of full notice to proceed to Bechtel in June 2022.
Financing Cash Flows
The following table summarizes our financing activities (in millions):
| Year Ended December 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Proceeds from issuances of debt | $ | 440 | $ | 1,150 | ||||||||||
| Repayments of debt | (2,419) | (1,188) | ||||||||||||
| Debt issuance and deferred financing costs | (44) | (4) | ||||||||||||
| Debt extinguishment costs | (19) | (5) | ||||||||||||
| Contributions | 2,182 | — | ||||||||||||
| Distributions | (200) | (1,163) | ||||||||||||
| Net cash used in financing activities | $ | (60) | $ | (1,210) | ||||||||||
Debt Issuances and Related Financing Costs
The following table shows the issuances of debt, including intra-year borrowings (in millions):
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||
| 3.72% weighted average rate Senior Secured Notes due 2039 | $ | — | $ | 750 | ||||||||||||||||
| CCH Credit Facility | 440 | — | ||||||||||||||||||
| CCH Working Capital Facility | — | 400 | ||||||||||||||||||
| Total proceeds from issuances of debt | $ | 440 | $ | 1,150 | ||||||||||||||||
During the years ended December 31, 2022 and 2021, we paid debt issuance costs and other financing costs of $44 million and$4 million, respectively, related to the $2.4 billion prepaymentdebt issuances above and amendment of outstanding borrowings undercredit facilities during the 2015 CCH Credit Facility in connection withrespective periods.
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Debt Repayments and Related Extinguishment Costs
The following table shows the issuancerepayments of debt, including intra-year repayments (in millions):
| Year Ended December 31, | ||||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||
| CCH Credit Facility | $ | (2,169) | $ | (898) | ||||||||||||||||
| CCH Working Capital Facility | (250) | (290) | ||||||||||||||||||
| Total repayments of debt | $ | (2,419) | $ | (1,188) | ||||||||||||||||
During the 2024 CCH Senior Notesyears ended December 31, 2022 and the 2025 CCH Senior Notes.2021, we paid debt modification or extinguishment costs of $19 millionand$5 million, respectively, related to these repayments.
During the year ended December 31, 20162022, we received cash capital contributions of $2.2 billion from Cheniere, primarily used to a net gainredeem our outstanding debt, and during the yearyears ended December 31, 2017. The increase in 2017 was primarily due2022 and 2021 we made cash distributions of $200 million and $1.2 billion, respectively, to a favorable shift in the long-term forward LIBOR curve between the periods, which was partially offset by a $13.0 million loss in May 2017 upon the settlement of interest rate swaps associated with approximately $1.4 billion of commitments that were terminated under the 2015 CCH Credit Facility.Cheniere.
Summary of Critical Accounting Estimates
The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments, 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 derivative instruments are recorded at fair value.value, other than certain derivatives for which we have elected to apply accrual accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. We record changes in the fair value of our derivative positions through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. 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.
Additionally, the valuation of certain physical liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2022 and 2021 (in millions), which entirely consisted of physical liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the marketplace, market transactionsend of each respective period.
| Year Ended December 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Unfavorable changes in fair value relating to instruments still held at the end of the period | $ | (3,664) | $ | (1,276) | ||||||||||
The unfavorable changes on instruments held at the end of both years are primarily attributed to significant appreciation in estimated forward international LNG commodity curves on our IPM agreements during the years ended December 31, 2022 and other relevant data.2021.
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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.
Marketing and Trading Commodity Price Risk
We have entered into commodity derivatives consisting of natural gas supply contracts to secure natural gas feedstock for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in thousands)millions):
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||
| Fair Value | Change in Fair Value | Fair Value | Change in Fair Value | ||||||||||||||||||||
| Liquefaction Supply Derivatives | $ | (6,278) | $ | 1,684 | $ | (1,212) | $ | 186 | |||||||||||||||
| 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
36
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, 2017,2022, 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/ | |||||||
| President and Chief Financial Officer (Principal Executive and Financial Officer) | ||||||||
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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, 20172022 and 2016,2021, 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, 2017,2022, and the related notes and financial statement schedule II (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, 20172022 and 2016,2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2022, 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 physical liquefaction supply derivatives
As discussed in Notes 2 and 8 to the consolidated financial statements, the Company recorded fair value of level 3 physical liquefaction supply derivatives of $(6,205) million, as of December 31, 2022. The physical liquefaction supply derivatives consist of natural gas supply contracts for the operation of the liquefied natural gas facility. The fair value of the level 3 physical liquefaction supply derivatives is developed using internal models that incorporate significant unobservable inputs.
We identified the evaluation of the fair value of the level 3 physical liquefaction supply derivatives as a critical audit matter. Specifically, there is subjectivity in certain assumptions used to estimate the fair value, including assumptions for future prices of energy units for unobservable periods and liquidity.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of the level 3 physical liquefaction supply derivatives. This included controls related to the assumptions for significant unobservable inputs and the fair value
38
model. For a selection of level 3 liquefaction supply derivatives, we involved valuation professionals with specialized skills and knowledge who assisted in:
•evaluating the future prices of energy units for observable periods by comparing to market data, including quoted or published forward prices
•developing independent fair value estimates and comparing the independently developed estimates to the Company’s fair value estimates.
In addition, we evaluated the Company’s assumptions for future prices of energy units for unobservable periods and liquidity by comparing them to market or third-party data, including adjustments for third party quoted transportation prices.
| /s/ KPMG LLP | ||
| KPMG LLP | ||
We have served as the Company’s auditor since 2015.
Houston, Texas
February 20, 201822, 2023
39
CHENIERE CORPUS CHRISTI HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||
| LNG revenues | $ | 6,336 | $ | 3,907 | $ | 2,046 | |||||||||||||||||||||||
| LNG revenues—affiliate | 3,027 | 1,887 | 483 | ||||||||||||||||||||||||||
| Total revenues | 9,363 | 5,794 | 2,529 | ||||||||||||||||||||||||||
| Operating costs and expenses | |||||||||||||||||||||||||||||
| Cost of sales (excluding items shown separately below) | 9,656 | 4,326 | 901 | ||||||||||||||||||||||||||
| Cost of sales—affiliate | 103 | 50 | 30 | ||||||||||||||||||||||||||
| Cost of sales—related party | — | 146 | 114 | ||||||||||||||||||||||||||
| Operating and maintenance expense | 458 | 423 | 347 | ||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | 121 | 106 | 90 | ||||||||||||||||||||||||||
| Operating and maintenance expense—related party | 9 | 9 | 6 | ||||||||||||||||||||||||||
| General and administrative expense | 8 | 7 | 7 | ||||||||||||||||||||||||||
| General and administrative expense—affiliate | 38 | 28 | 20 | ||||||||||||||||||||||||||
| Depreciation and amortization expense | 445 | 420 | 342 | ||||||||||||||||||||||||||
| Other | 6 | 2 | 1 | ||||||||||||||||||||||||||
| Total operating costs and expenses | 10,844 | 5,517 | 1,858 | ||||||||||||||||||||||||||
| Income (loss) from operations | (1,481) | 277 | 671 | ||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (432) | (447) | (365) | ||||||||||||||||||||||||||
| Loss on modification or extinguishment of debt | (37) | (9) | (9) | ||||||||||||||||||||||||||
| Interest rate derivative gain (loss), net | 2 | (1) | (233) | ||||||||||||||||||||||||||
| Other income (expense), net | 6 | — | (1) | ||||||||||||||||||||||||||
| Total other expense | (461) | (457) | (608) | ||||||||||||||||||||||||||
| Net income (loss) | $ | (1,942) | $ | (180) | $ | 63 | |||||||||||||||||||||||
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, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| ASSETS | ||||||||||||||
| Current assets | ||||||||||||||
| Restricted cash and cash equivalents | $ | 738 | $ | 44 | ||||||||||
| Trade and other receivables, net of current expected credit losses | 348 | 280 | ||||||||||||
| Accounts receivable—affiliate | 240 | 315 | ||||||||||||
| Advances to affiliate | 132 | 128 | ||||||||||||
| Inventory | 178 | 156 | ||||||||||||
| Current derivative assets | 12 | 17 | ||||||||||||
| Margin deposits | 76 | 13 | ||||||||||||
| Other current assets | 18 | 15 | ||||||||||||
| Total current assets | 1,742 | 968 | ||||||||||||
| Property, plant and equipment, net of accumulated depreciation | 13,673 | 12,607 | ||||||||||||
| Debt issuance and deferred financing costs, net of accumulated amortization | 40 | 7 | ||||||||||||
| Derivative assets | 7 | 37 | ||||||||||||
| Other non-current assets, net | 225 | 145 | ||||||||||||
| Total assets | $ | 15,687 | $ | 13,764 | ||||||||||
| LIABILITIES AND MEMBER’S EQUITY | ||||||||||||||
| Current liabilities | ||||||||||||||
| Accounts payable | $ | 85 | $ | 119 | ||||||||||
| Accrued liabilities | 901 | 631 | ||||||||||||
| Accrued liabilities—related party | 1 | 1 | ||||||||||||
| Current debt, net of discount and debt issuance costs | 495 | 366 | ||||||||||||
| Due to affiliates | 43 | 35 | ||||||||||||
| Current derivative liabilities | 1,374 | 668 | ||||||||||||
| Other current liabilities | 1 | 1 | ||||||||||||
| Total current liabilities | 2,900 | 1,821 | ||||||||||||
| Long-term debt, net of discount and debt issuance costs | 6,698 | 9,986 | ||||||||||||
| Derivative liabilities | 4,923 | 638 | ||||||||||||
| Other non-current liabilities | 78 | 38 | ||||||||||||
| Other non-current liabilities—affiliate | 4 | — | ||||||||||||
| Member’s equity | 1,084 | 1,281 | ||||||||||||
| Total liabilities and member’s equity | $ | 15,687 | $ | 13,764 | ||||||||||
| 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 | ) | ||
41
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, 2019 | $ | 2,418 | $ | 2,418 | |||||||
| Contributions | 145 | 145 | |||||||||
| Distributions | (2) | (2) | |||||||||
| Net income | 63 | 63 | |||||||||
| 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 CCL Stage III entity) | 2,182 | 2,182 | |||||||||
| (1,482) | (1,482) | ||||||||||
| Non-cash contribution from affiliate | 1,245 | 1,245 | |||||||||
| Distributions | (200) | (200) | |||||||||
| Net loss | (1,942) | (1,942) | |||||||||
| Balance at December 31, 2022 | $ | 1,084 | $ | 1,084 | |||||||
| 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.
42
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)millions)
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
| Net income (loss) | $ | (1,942) | $ | (180) | $ | 63 | |||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization expense | 445 | 420 | 342 | ||||||||||||||
| Amortization of discount and debt issuance costs | 20 | 24 | 20 | ||||||||||||||
| Loss on modification or extinguishment of debt | 37 | 9 | 9 | ||||||||||||||
| Total losses on derivative instruments, net | 3,243 | 1,241 | 261 | ||||||||||||||
| Total gains on derivatives, net—related party | — | (11) | 1 | ||||||||||||||
| Net cash used for settlement of derivative instruments | (155) | (107) | (174) | ||||||||||||||
| Other | 33 | 3 | 4 | ||||||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||||
| Trade and other receivables, net of current expected credit losses | (68) | (84) | (138) | ||||||||||||||
| Accounts receivable—affiliate | 76 | (273) | 15 | ||||||||||||||
| Advances to affiliate | (58) | 14 | (11) | ||||||||||||||
| Inventory | (22) | (62) | (18) | ||||||||||||||
| Margin deposits | (63) | (8) | — | ||||||||||||||
| Accounts payable and accrued liabilities | 184 | 468 | 63 | ||||||||||||||
| Accrued liabilities—related party | — | (14) | 11 | ||||||||||||||
| Due to affiliates | 7 | 9 | 5 | ||||||||||||||
| Deferred revenue | 42 | 35 | — | ||||||||||||||
| Other, net | (44) | (60) | (56) | ||||||||||||||
| Other, net—affiliate | (1) | — | (1) | ||||||||||||||
| Net cash provided by operating activities | 1,734 | 1,424 | 396 | ||||||||||||||
| Cash flows from investing activities | |||||||||||||||||
| Property, plant and equipment | (981) | (238) | (790) | ||||||||||||||
| Other | 1 | (2) | (6) | ||||||||||||||
| Net cash used in investing activities | (980) | (240) | (796) | ||||||||||||||
| Cash flows from financing activities | |||||||||||||||||
| Proceeds from issuances of debt | 440 | 1,150 | 1,050 | ||||||||||||||
| Repayments of debt | (2,419) | (1,188) | (797) | ||||||||||||||
| Debt issuance and deferred financing costs | (44) | (4) | (8) | ||||||||||||||
| Debt extinguishment costs | (19) | (5) | — | ||||||||||||||
| Contributions | 2,182 | — | 145 | ||||||||||||||
| Distributions | (200) | (1,163) | — | ||||||||||||||
| Net cash used in financing activities | (60) | (1,210) | 390 | ||||||||||||||
| Net increase (decrease) in restricted cash and cash equivalents | 694 | (26) | (10) | ||||||||||||||
| Restricted cash and cash equivalents—beginning of period | 44 | 70 | 80 | ||||||||||||||
| Restricted cash and cash equivalents—end of period | $ | 738 | $ | 44 | $ | 70 | |||||||||||
| 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.
43
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS
CCL Stage III, CCL and CCP received approval from FERC in November 2019 to site, construct and operate the Corpus Christi Texas,Stage 3 Project. In March 2022, CCL Stage III issued limited notice to proceed to Bechtel Energy Inc. (“Bechtel”) to commence early engineering, procurement and site works. In June 2022, Cheniere’s board of directors made a 23-milepositive 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 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. Refer to Note 3—CCL Stage III Contribution and Merger for additional information on the Contribution and Merger of CCL Stage III.
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 Liquefaction Facility,existing operational Trains, midscale Trains, storage tanks and marine berths, the “Liquefaction Project”) through wholly owned subsidiaries CCL and CCP, respectively. The.
We have increased available liquefaction capacity at our Liquefaction Project is being developed in stagesas a result of debottlenecking and other optimization projects. We hold a significant land position at the Corpus Christi LNG Terminal which provides opportunity for upfurther liquefaction capacity expansion. In September 2022, CCH and another subsidiary of Cheniere entered the pre-filing review process with the FERC under the National Environmental Policy Act for an expansion adjacent to threethe Liquefaction Project consisting of two midscale Trains with an expected aggregate nominaltotal 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 Bcfe3 mtpa of LNG. The development of this site or other projects, including infrastructure projects in support of natural gas supply 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 1LNG demand, will require, among other things, acceptable commercial and 2, two LNG storage tanks, one complete marine berth andfinancing arrangements before we make 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 tank and the completion of the second partial berth. 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.positive FID.
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.
Use of 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 thefair value measurements of derivatives and other instruments useful lives of property, plant and equipment derivative instruments,and asset retirement obligations (“AROs”), income taxes including valuation allowances for deferred tax assets and fair value measurements.as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability.liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.
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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for 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. Debt fair values, as disclosed in Note 11—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs.
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 consistsand cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and will not become available to us as cash and cash equivalents. We have been presented restricted cash 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.
Trade and other receivables and contract assets are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Consolidated Statements of Operations. As of both December 31, 2022 and 2021, we had current expected credit losses of zeroon our trade and other receivables, and as of December 31, 2022 and 2021, we had current expected credit losses of $4 million and $3 million, respectively, on our non-current contract assets.
Inventory
LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or, for LNG Activitiescertain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.
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.
45
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to 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.
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 isare 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. During the year ended December 31, 2017, we recognized $5.5 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey.
We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2016 or 2015.2022, 2021 and 2020.
Interest Capitalization
We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon placing the underlying asset in service, these costs are transferred out of construction-in-process into the respective in-service asset category and depreciated over the estimated useful life of the corresponding assets, except for capitalized interest associated with land, which is not depreciated.
Regulated Natural Gas Pipelines
The Corpus Christi Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as deferred
Items that may influence our assessment are:
•inability to recover cost increases due to rate caps and rate case moratoriums;
•inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;
•excess capacity;
46
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
•increased competition and discounting in the markets we serve; and
•impacts of ongoing regulatory initiatives in the natural gas industry.
Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines.pipeline. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines arepipeline is placed in service.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from interest rate.rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception.exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intendintent to net settle, derivative assets and liabilities are reported on a net basis.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of restricted cash.derivative instruments and accounts receivable related to our long-term SPAs, as discussed further below. 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. Our interest rateCertain of our commodity derivative instrumentstransactions are placedexecuted 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 whom we believe are acceptable credit risks.institutions. Collateral deposited for such contracts is recorded within margin deposits. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.
CCL has entered into eight fixed price long-term SPAs generally with terms of at least 20 years with seven unaffiliated15 third parties.parties and have entered into 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.
47
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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. Gains and losses on the extinguishment or modification of debt are recorded in gains and lossesloss on themodification or extinguishment of debt on our Consolidated Statements of Operations.
•We classify term debt that is contractually due within one year as long-term debt if management has the intent and deferred financing costsability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.
•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are amortized to interest expense or property, plantissued based on facts and equipment over the termcircumstances existing as of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on early extinguishment of debt.balance sheet date.
Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement 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.
Income Taxes
We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. TheAccordingly, no provision or liability for federal or state income taxes taxes payable and deferred income tax balances have been recorded as if we had filed all tax returns on a separate return basis from Cheniere. Deferred tax assets and liabilities areis included in ourthe accompanying Consolidated Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable.Statements.
Business Segment
Our liquefaction and pipeline business at the Corpus Christi LNG terminalTerminal represents a single reportable segment. Our chief operating decision maker reviews the financial results of CCH in total when evaluating financial performance and for purposes of allocating resources.
48
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Recent Accounting Standards
ASU 2020-04
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts expected to arise from the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.
We had interest rate swaps and various credit facilities indexed to LIBOR, as further described in Note 8—Derivative Instruments and Note 11—Debt, respectively. In June 2022, we amended our credit facilities to bear interest at a variable rate per annum based on SOFR as a result of the expected LIBOR transition. Since adoption of the standard, we elected to apply the optional expedients as applicable to certain modified facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.
NOTE 3—RESTRICTED CASHCCL STAGE III CONTRIBUTION AND MERGER
The Contribution was accounted for as a common control transaction as the assets and haveliabilities were transferred between entities under Cheniere’s control. As a result, the net liability transfer was recognized as a contribution in our Consolidated Statement of Member’s Equity and at the historical basis of Cheniere on June 15, 2022 in our Consolidated Balance Sheets. The Contribution has been presented separately from cashprospectively 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.
The net liabilities of CCL Stage III contributed to us and cash equivalentsrecognized on our Consolidated Balance Sheets. As of December 31, 2017 and 2016, restricted cashSheets on June 15, 2022 consisted of the following (in thousands)millions):
| June 15, 2022 | ||||||||
| ASSETS | ||||||||
| Property, plant and equipment, net of accumulated depreciation | $ | 441 | ||||||
| Derivatives assets | 112 | |||||||
| Other non-current assets, net | 19 | |||||||
| Total assets | $ | 572 | ||||||
| LIABILITIES | ||||||||
| Current liabilities | ||||||||
| Accounts payable | $ | 3 | ||||||
| Due to affiliates | 1 | |||||||
| Total current liabilities | 4 | |||||||
| Derivative liabilities | 2,050 | |||||||
| Total net liabilities contributed | $ | (1,482) | ||||||
Amended and Restated Debt Agreements
In June 2022, in connection with the FID with respect to the Corpus Christi Stage 3 Project referenced above, CCH amended and restated its term loan credit facility (the “CCH Credit Facility”) and its working capital facility (“CCH Working Capital Facility”) to, among other things, (1) increase the commitments to approximately $4.0 billion and $1.5 billion for the
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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| Current restricted cash | ||||||||
| Liquefaction Project | $ | 226,559 | $ | 197,201 | ||||
| Non-current restricted cash | ||||||||
| Liquefaction Project | $ | — | $ | 73,339 | ||||
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. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.
As of December 31, 2022 and 2021, we had $738 million and $44 million of restricted cash and cash equivalents, respectively, as required by the above agreement, of which $498 million as of December 31, 2022 related to the cash contributed from Cheniere for the redemption of the remaining outstanding principal balance of the 7.000% Senior Notes due 2024 (the “2024 CCH Senior Notes”) in January 2023.
NOTE 4—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, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Trade receivables | $ | 319 | $ | 256 | ||||||||||
| Other receivables | 29 | 24 | ||||||||||||
| Total trade and other receivables, net of current expected credit losses | $ | 348 | $ | 280 | ||||||||||
NOTE 6—INVENTORY
Inventory consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Materials | $ | 92 | $ | 88 | ||||||||||
| LNG | 53 | 45 | ||||||||||||
| Natural gas | 31 | 21 | ||||||||||||
| Other | 2 | 2 | ||||||||||||
| Total inventory | $ | 178 | $ | 156 | ||||||||||
NOTE 7—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION
Property, plant and equipment, net consistsof accumulated depreciation consisted of the following (in millions):
| December 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| LNG terminal | ||||||||||||||
| Terminal and interconnecting pipeline facilities | $ | 13,299 | $ | 13,222 | ||||||||||
| Site and related costs | 302 | 294 | ||||||||||||
| Construction-in-process | 1,486 | 66 | ||||||||||||
| Accumulated depreciation | (1,421) | (981) | ||||||||||||
| Total LNG terminal, net of accumulated depreciation | 13,666 | 12,601 | ||||||||||||
| Fixed assets | ||||||||||||||
| Fixed assets | 26 | 23 | ||||||||||||
| Accumulated depreciation | (19) | (17) | ||||||||||||
| Total fixed assets, net of accumulated depreciation | 7 | 6 | ||||||||||||
| Property, plant and equipment, net of accumulated depreciation | $ | 13,673 | $ | 12,607 | ||||||||||
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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows depreciation expense and offsets to LNG terminal costs (in millions):
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||
| Depreciation expense | $ | 444 | $ | 419 | $ | 341 | ||||||||||||||||||||||||||
| Offsets to LNG terminal costs (1) | — | 143 | 32 | |||||||||||||||||||||||||||||
(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.
LNG Terminal Costs
LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal costsassets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and fixed assets,50 years, as follows (in thousands):follows:
| 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 | ||||
| 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 5—8—DERIVATIVE INSTRUMENTS
We have entered into the following derivative instruments that are reported at fair value:instruments:
•interest rate swaps (“CCH Interest Rate Derivatives”) to protect againsthedge the exposure to volatility of future cash flows and hedgein a portion of the variable-ratefloating-rate interest payments on our credit facility (the “2015 CCH Credit Facility”Facility, which expired in May 2022, and previously, to hedge against changes in interest rates that could impact anticipated future issuances of debt by CCH (the “Interest Rate Forward Start Derivatives” and, collectively with the CCH Interest Rate Derivatives, the “Interest Rate Derivatives”), which were settled in August 2020; and
•commodity derivatives consisting of natural gas and power supply contracts, including those under our IPM agreements, for the development, commissioning and operation of the Liquefaction Project (“Liquefactionand associated economic hedges (collectively, “Liquefaction Supply Derivatives”).
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.process, in which case such changes are capitalized.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
| Fair Value Measurements as of | |||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||
| Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||||||||||||||||||||||||||||||
| Interest Rate Derivatives liability | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (40) | $ | — | $ | (40) | |||||||||||||||||||||||||||||||
| Liquefaction Supply Derivatives asset (liability) | (54) | (19) | (6,205) | (6,278) | 5 | 4 | (1,221) | (1,212) | |||||||||||||||||||||||||||||||||||||||
We valuevalued our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.
| 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 | ) | |||
We include a market-based approach incorporating presentsignificant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value techniques, as needed, and is developed through the use of internal models which may be impacted by inputs that areincorporate significant unobservable in the marketplace.
The Level 3 fair value measurements of natural gas positions within our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio.and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of December 31, 2017:
2022:
Net Fair Value Liability (in | Valuation Approach | Significant Unobservable Input | Range of Significant Unobservable Inputs | |||||||||||||||||||||||
| Liquefaction Supply Derivatives | $ | Market approach incorporating present value techniques | $ | |||||||||||||||||||||||
| Option pricing model | International LNG pricing spread, relative to Henry Hub (2) | 73% - 532% / 157% | ||||||||||||||||||||||||
(2)Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Liquefaction Supply Derivatives.
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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows the changes in the fair value of our Level 3 Liquefaction Supply Derivatives (in millions):
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2022 | 2021 (1) | 2020 | ||||||||||||||||||||||||||||||
| Balance, beginning of period | $ | (1,221) | $ | 12 | $ | 35 | ||||||||||||||||||||||||||
| Realized and change in fair value gains (losses) included in net income (2): | ||||||||||||||||||||||||||||||||
| Included in cost of sales, existing deals (3) | (1,492) | (1,276) | 28 | |||||||||||||||||||||||||||||
| Included in cost of sales, new deals (4) | (2,172) | — | — | |||||||||||||||||||||||||||||
| Purchases and settlements: | ||||||||||||||||||||||||||||||||
| Purchases (5) | (1,938) | 9 | — | |||||||||||||||||||||||||||||
| Settlements (6) | 618 | 34 | (58) | |||||||||||||||||||||||||||||
| Transfers in and/or out of level 3 | ||||||||||||||||||||||||||||||||
| Transfers into level 3 (7) | — | — | 7 | |||||||||||||||||||||||||||||
| Balance, end of period | $ | (6,205) | $ | (1,221) | $ | 12 | ||||||||||||||||||||||||||
| Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period | $ | (3,664) | $ | (1,276) | $ | 28 | ||||||||||||||||||||||||||
(1)Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 13—Related Party Transactions.
(2)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.
(3)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
(4)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
(5)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 period and continuing to exist at the end of the period. For further discussion of IPM agreements that were novated to us during the period, see Note 3—CCL Stage III Contribution and Merger.
(6)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.
(7)Transferred into level 3 as a result of unobservable 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 ourthose derivative contracts with the same counterparty are reportedand the unconditional contractual right of set-off on a net basis, as all counterparty derivative contracts provide for net settlement.basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we evaluate our own abilitywill be unable to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide forWe incorporate both our own nonperformance risk and the unconditional rightrespective counterparty’s nonperformance risk in fair value measurements depending on the position of set-off for all derivative assets and liabilities with a given counterparty in the event of default.
Interest Rate Derivatives
We previously entered into the following Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on our Consolidated Balance Sheets (in thousands):the CCH Credit Facility, which expired in May 2022:
| Notional Amounts | ||||||||||||||||||||||||||||||||
| December 31, 2022 | December 31, 2021 | Weighted Average Fixed Interest Rate Paid | Variable Interest Rate Received | |||||||||||||||||||||||||||||
| CCH Interest Rate Derivatives | $— | $4.5 billion | 2.30% | One-month LIBOR | ||||||||||||||||||||||||||||
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| 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 | $ | — | $ | — | ||||||
Contents
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows the effect and location of our Interest Rate Derivatives on our Consolidated Statements of Operations (in millions):
| Gain (Loss) Recognized in Consolidated Statements of Operations | ||||||||||||||||||||||||||||||||||||||
| Consolidated Statements of Operations Location | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||||||||
| CCH Interest Rate Derivatives | Interest rate derivative gain (loss), net | $ | 2 | $ | (1) | $ | (138) | |||||||||||||||||||||||||||||||
| CCH Interest Rate Forward Start Derivatives | Interest rate derivative gain (loss), net | — | — | (95) | ||||||||||||||||||||||||||||||||||
Liquefaction Supply Derivatives
CCL holds Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The terms of the Liquefaction Supply Derivatives range up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.
The forward notional amount for our Liquefaction Supply Derivatives was approximately 8,532 TBtu and 2,915 TBtu as of December 31, 2022 and 2021, respectively.
The following table shows the effect and location of our 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, | |||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||
| LNG revenues | $ | 1 | $ | 4 | $ | (1) | ||||||||||||||||||||||||||
| Cost of sales | (3,246) | (1,244) | (27) | |||||||||||||||||||||||||||||
| Cost of sales—related party (2) | — | 11 | (1) | |||||||||||||||||||||||||||||
(1)Does not include the value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(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 a net basisthe Consolidated Balance Sheets
The following table shows the fair value and location of our derivative instruments on our Consolidated Balance Sheets (in millions):
| December 31, 2022 | |||||||||||||||||||||||
| CCH Interest Rate Derivatives | Liquefaction Supply Derivatives (1) | Total | |||||||||||||||||||||
| Consolidated Balance Sheets Location | |||||||||||||||||||||||
| Current derivative assets | $ | — | $ | 12 | $ | 12 | |||||||||||||||||
| Derivative assets | — | 7 | 7 | ||||||||||||||||||||
| Total derivative assets | — | 19 | 19 | ||||||||||||||||||||
| Current derivative liabilities | — | (1,374) | (1,374) | ||||||||||||||||||||
| Derivative liabilities | — | (4,923) | (4,923) | ||||||||||||||||||||
| Total derivative liabilities | — | (6,297) | (6,297) | ||||||||||||||||||||
| Derivative liability, net | $ | — | $ | (6,278) | $ | (6,278) | |||||||||||||||||
| December 31, 2021 | |||||||||||||||||||||||
| CCH Interest Rate Derivatives | Liquefaction Supply Derivatives (1) | Total | |||||||||||||||||||||
| Consolidated Balance Sheets Location | |||||||||||||||||||||||
| Current derivative assets | $ | — | $ | 17 | $ | 17 | |||||||||||||||||
| Derivative assets | — | 37 | 37 | ||||||||||||||||||||
| Total derivative assets | — | 54 | 54 | ||||||||||||||||||||
| Current derivative liabilities | (40) | (628) | (668) | ||||||||||||||||||||
| Derivative liabilities | — | (638) | (638) | ||||||||||||||||||||
| Total derivative liabilities | (40) | (1,266) | (1,306) | ||||||||||||||||||||
| Derivative liability, net | $ | (40) | $ | (1,212) | $ | (1,252) | |||||||||||||||||
(1)Does not include collateral posted with counterparties by us of $76 million and $13 million as described above. of December 31, 2022 and 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets. Includes a natural gas supply contract that we had with a related party. This agreement ceased to be considered a related party agreement as of November 1, 2021.
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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Consolidated Balance Sheets Presentation
The following table shows the fair value of our derivatives outstanding on a gross and net basis (in thousands):millions) for our derivative instruments that are presented on a net basis on our Consolidated Balance Sheets:
| CCH Interest Rate Derivatives | Liquefaction Supply Derivatives | |||||||||||||||||||
| As of December 31, 2022 | ||||||||||||||||||||
| Gross assets | $ | — | $ | 19 | ||||||||||||||||
| Offsetting amounts | — | — | ||||||||||||||||||
| Net assets | $ | — | $ | 19 | ||||||||||||||||
| Gross liabilities | $ | — | $ | (6,622) | ||||||||||||||||
| Offsetting amounts | — | 325 | ||||||||||||||||||
| Net liabilities | $ | — | $ | (6,297) | ||||||||||||||||
| As of December 31, 2021 | ||||||||||||||||||||
| Gross assets | $ | — | $ | 76 | ||||||||||||||||
| Offsetting amounts | — | (22) | ||||||||||||||||||
| Net assets | $ | — | $ | 54 | ||||||||||||||||
| Gross liabilities | $ | (40) | $ | (1,295) | ||||||||||||||||
| Offsetting amounts | — | 29 | ||||||||||||||||||
| Net liabilities | $ | (40) | $ | (1,266) | ||||||||||||||||
| 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 | ) | |||||||
NOTE 6—9—OTHER NON-CURRENT ASSETS, NET
Other non-current assets, net consisted of the following (in millions):
| December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Contract assets, net of current expected credit losses | $ | 142 | $ | 103 | |||||||
| Advances and other asset conveyances to third parties to support LNG terminal | 62 | 24 | |||||||||
| Operating lease assets | 6 | 4 | |||||||||
| Information technology service prepayments | 3 | 3 | |||||||||
| Tax-related payments and receivables | 3 | 2 | |||||||||
| Other | 9 | 9 | |||||||||
| Total other non-current assets, net | $ | 225 | $ | 145 | |||||||
NOTE 10—ACCRUED LIABILITIES
| December 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Natural gas purchases | $ | 597 | $ | 531 | ||||||||||
| Interest costs and related debt fees | 150 | 7 | ||||||||||||
| Liquefaction Project costs | 103 | 43 | ||||||||||||
| Other accrued liabilities | 51 | 50 | ||||||||||||
| Total accrued liabilities | $ | 901 | $ | 631 | ||||||||||
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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
| 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 | ||||
NOTE 7—11—DEBT
| December 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Senior Secured Notes: | ||||||||||||||
| 2024 CCH Senior Notes (1) | $ | 498 | $ | 1,250 | ||||||||||
| 5.875% due 2025 | 1,491 | 1,500 | ||||||||||||
| 5.125% due 2027 (2) | 1,271 | 1,500 | ||||||||||||
| 3.700% due 2029 (2) | 1,361 | 1,500 | ||||||||||||
| 3.751% weighted average rate due 2039 (2) | 2,633 | 2,721 | ||||||||||||
| Total Senior Secured Notes | 7,254 | 8,471 | ||||||||||||
| CCH Credit Facility | — | 1,728 | ||||||||||||
| CCH Working Capital Facility (3) | — | 250 | ||||||||||||
| Total debt | 7,254 | 10,449 | ||||||||||||
| Current portion of long-term debt | (495) | (117) | ||||||||||||
| Short-term debt | — | (250) | ||||||||||||
| Unamortized discount and debt issuance costs, net | (61) | (96) | ||||||||||||
| Total long-term debt, net of discount and debt issuance costs | $ | 6,698 | $ | 9,986 | ||||||||||
(1)In January 2023, we redeemed the remaining outstanding principal balance of the 2024 CCH Senior Notes with cash that was contributed to us from Cheniere prior to December 31, 2022. Therefore, the outstanding principal balance redeemed was classified as current portion of long-term debt as of December 31, 2022 net of discount and debt issuance costs of $3 million.
(2)Subsequent to December 31, 2022 and through February 16, 2023, Cheniere executed bond repurchases totaling $322 million, inclusive of CCH’s Senior Secured Notes due 2027, 2029 and 2039 on the open market, which were immediately contributed to us from Cheniere and cancelled by us.
(3)The CCH Working Capital Facility is classified as short-term debt.
Senior Notes
CCH Senior Secured Notes
The senior secured notes due between 2024 and 2039, with a weighted average interest rate of 4.64% (“CCH 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 CCH 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 CCH 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 CCH Senior Secured Notes. The CCH 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 CCH Senior Secured Notes at specified prices set forth in the respective indentures governing the CCH Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption.
Cancellation of CCH Senior Secured Notes Contributed from Cheniere
During the year ended December 31, 2022, Cheniere repurchased a total of $1,217 million of our outstanding debt, consisting of $465 million of our Senior Secured Notes due 2025, 2027, 2029 and 2039 on the open market and $752 million of our Senior Secured Notes due 2024, with all of such repurchases immediately contributed to us from Cheniere for no consideration, and cancelled by us. It was determined that for accounting purposes, Cheniere repurchased the bonds on our behalf as a principal as opposed to as an agent, and thus the debt extinguishment was accounted for as an extinguishment directly with Cheniere.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
| 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 | ||||
The total contribution from Cheniere of $1,238 million 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 based on current construction schedules, on our outstanding debt at December 31, 20172022 (in thousands)millions):
| Years Ending December 31, | Principal Payments | |||||||
| 2023 | $ | 498 | ||||||
| 2024 | — | |||||||
| 2025 | 1,491 | |||||||
| 2026 | — | |||||||
| 2027 | 1,354 | |||||||
| Thereafter | 3,911 | |||||||
| Total | $ | 7,254 | ||||||
| Years Ending December 31, | Principal Payments | |||
| 2018 | $ | — | ||
| 2019 | — | |||
| 2020 | — | |||
| 2021 | — | |||
| 2022 | 2,484,737 | |||
| Thereafter | 4,250,000 | |||
| Total | $ | 6,734,737 | ||
Credit Facilities
Below is a summary of our credit facilities outstanding as of December 31, 20172022 (in thousands)millions):
| 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 | ||||||
| CCH Credit Facility (1) (2) | CCH Working Capital Facility (2) (3) | |||||||||||||
| Total facility size | $ | 3,260 | $ | 1,500 | ||||||||||
| Less: | ||||||||||||||
| Outstanding balance | — | — | ||||||||||||
| Letters of credit issued | — | 178 | ||||||||||||
| Available commitment | $ | 3,260 | $ | 1,322 | ||||||||||
| Priority ranking | Senior secured | Senior secured | ||||||||||||
| Interest rate on available balance (4) | 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 (4) | 0.525% | 0.10% - 0.20% | ||||||||||||
| Maturity date | (5) | June 15, 2027 | ||||||||||||
Our obligations under the 2015 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 HoldCoHoldco I of its limited liability company interests in us.
(4)The margin on the interest rate and the commitment fees are subject to change based on the applicable entity’s credit rating.
(5)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.
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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 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, 2017,2022, 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 thousands)millions):
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||||||||||||||
| Total interest cost | $ | 465 | $ | 473 | $ | 484 | |||||||||||||||||||||||
| Capitalized interest, including amounts capitalized as an allowance for funds used during construction | (33) | (26) | (119) | ||||||||||||||||||||||||||
| Total interest expense, net of capitalized interest | $ | 432 | $ | 447 | $ | 365 | |||||||||||||||||||||||
| 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 | ||||||
Fair Value Disclosures
The following table shows the carrying amount and estimated fair value of our debt (in thousands)millions):
| 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 | ||||||||||||
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||
| Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||||||||||||
| Senior notes — Level 2 (1) | $ | 5,283 | $ | 5,014 | $ | 6,500 | $ | 7,095 | ||||||||||||||||||
| Senior notes — Level 3 (2) | 1,971 | 1,738 | 1,971 | 2,227 | ||||||||||||||||||||||
(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
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, | ||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||
| Revenues from contracts with customers | ||||||||||||||||||||||||||||||||
| LNG revenues (1) | $ | 6,335 | $ | 3,903 | $ | 2,047 | ||||||||||||||||||||||||||
| LNG revenues—affiliate | 3,027 | 1,887 | 483 | |||||||||||||||||||||||||||||
| Total revenues from contracts with customers | 9,362 | 5,790 | 2,530 | |||||||||||||||||||||||||||||
| Net derivative gain (loss) (2) | 1 | 4 | (1) | |||||||||||||||||||||||||||||
| Total revenues | $ | 9,363 | $ | 5,794 | $ | 2,529 | ||||||||||||||||||||||||||
LNG Sale and Purchase Agreements
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2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We didnot have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2022 and 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.
LNG Revenues
We have entered into numerous SPAs with third party customers for the second SPA (the “Amended Cheniere Marketing Foundation SPA”), as determined by CCL in each contract year, in each casesale of LNG on a FOB (delivered to the customer at the Corpus Christi LNG Terminal) or DAT (delivered to the customer at their LNG receiving terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee of $3.00 per MMBtu of LNG plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. Under the Cheniere Marketing Base SPA, Cheniere Marketing may, without charge, elect to suspend deliveries of cargoes (other than commissioning cargoes) scheduled for any month under the applicable annual delivery program by providing specified notice in advance.
Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, either at the Corpus Christi LNG Terminal or at the customer’s LNG receiving terminal, based on the terms of the contract, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the contract was terminatednegotiated. 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 January 2018.the transaction price.
Contract Assets and $5.5 millionLiabilities
The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):
| December 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Contract assets, net of current expected credit losses | $ | 144 | $ | 104 | ||||||||||
Contract assets represent our right to consideration for transferring goods or services to the yearscustomer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the year ended December 31, 2017, 2016 and 2015, respectively, under the services agreements below.
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The following table reflects the changes in our contract liabilities, which we classify as other non-current liabilities on our Consolidated Balance Sheets (in millions):
| Year Ended December 31, 2022 | ||||||||||||||
| Deferred revenue, beginning of period | $ | 35 | ||||||||||||
| Cash received but not yet recognized in revenue | 76 | |||||||||||||
| Revenue recognized from prior period deferral | (35) | |||||||||||||
| 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. Changes in deferred revenue during the years ended December 31, 2022 and 2021 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.
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, 2022 | December 31, 2021 | |||||||||||||||||||||||||
| Unsatisfied Transaction Price (in billions) | Weighted Average Recognition Timing (years) (1) | Unsatisfied Transaction Price (in billions) | Weighted Average Recognition Timing (years) (1) | |||||||||||||||||||||||
| LNG revenues | $ | 50.9 | 10 | $ | 31.7 | 9 | ||||||||||||||||||||
| LNG revenues—affiliate | 1.2 | 8 | 1.1 | 10 | ||||||||||||||||||||||
| Total revenues | $ | 52.1 | $ | 32.8 | ||||||||||||||||||||||
(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Additionally, we have excluded variable consideration related to contracts where there is uncertainty that one or both of the parties will achieve certain milestones. Approximately 70% and 58% of our LNG revenues from contracts included in the table above during the years ended December 31, 2022 and 2021, respectively, were related to variable consideration received from customers. Approximately 86% of our LNG revenues—affiliate from contracts included in the table above during the year ended December 31, 2022 were related to variable consideration received from customers. Noneof our LNG revenues—affiliates from the contract included in the table above were related to variable consideration received from customers during the year ended December 31, 2021.
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.
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NOTE 13—RELATED PARTY TRANSACTIONS
Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations (in millions):
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||
| LNG revenues—affiliate | ||||||||||||||||||||||||||||||||
| Cheniere Marketing Agreements (1) | $ | 2,993 | $ | 1,837 | $ | 468 | ||||||||||||||||||||||||||
| Contracts for Sale and Purchase of Natural Gas and LNG (2) | 34 | 50 | 15 | |||||||||||||||||||||||||||||
| Total LNG revenues—affiliate | 3,027 | 1,887 | 483 | |||||||||||||||||||||||||||||
| Cost of sales—affiliate | ||||||||||||||||||||||||||||||||
| Contracts for Sale and Purchase of Natural Gas and LNG (2) | 103 | 19 | 30 | |||||||||||||||||||||||||||||
| Cheniere Marketing Agreements (1) (3) | — | 31 | — | |||||||||||||||||||||||||||||
| Total cost of sales—affiliate | 103 | 50 | 30 | |||||||||||||||||||||||||||||
| Cost of sales—related party | ||||||||||||||||||||||||||||||||
| Natural Gas Supply Agreement (4) | — | 146 | 114 | |||||||||||||||||||||||||||||
| Operating and maintenance expense—affiliate | ||||||||||||||||||||||||||||||||
| Services Agreements (5) | 120 | 105 | 89 | |||||||||||||||||||||||||||||
| Land Agreements (6) | 1 | 1 | 1 | |||||||||||||||||||||||||||||
| Total operating and maintenance expense—affiliate | 121 | 106 | 90 | |||||||||||||||||||||||||||||
| Operating and maintenance expense—related party | ||||||||||||||||||||||||||||||||
| Natural Gas Transportation Agreements (7) | 9 | 9 | 6 | |||||||||||||||||||||||||||||
| General and administrative expense—affiliate | ||||||||||||||||||||||||||||||||
| Services Agreements (5) | 38 | 28 | 20 | |||||||||||||||||||||||||||||
(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, 2022 and 2021, CCL had $223 million and $314 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing.
(2)CCL has an agreement with Sabine Pass Liquefaction, LLC 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, 2022 and 2021, CCL had $16 million and $1 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing.
(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 will commence in 2023.
(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
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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 related expenses, a monthly fee equalcosts. As of December 31, 2022 and 2021, we had $132 million and $128 million of advances to 3% of the capital expenditures incurred in the previous month and a fixed monthly fee of $375,000 for services with respect to such Train.
(6)CCL has agreements with Cheniere Land Holdings, LLC, (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, to lease approximately 60 acres ofrent, obtain easements and license to enter the land owned by Cheniere Land HoldingsCLH for the Liquefaction Facility. The total annual lease payment, paidProject.
(7)CCL is party to natural gas transportation agreements with a related party in advance upon 30 daysthe ordinary course of business for the operation of the effective dateLiquefaction Project. CCL recorded accrued liabilities—related party of the respective leases, is $0.4$1 million as of both December 31, 2022 and 2021 with this related party.
We had $43 million and the terms of the agreements range from three$35 million due to five years. We recorded $0.3 million, $0.1 million and zero of lease expense related to these agreements as operating and maintenance expense—affiliate for the years ended December 31, 2017, 2016 and 2015, respectively. We had $0.2 million and $0.1 millionaffiliates as of December 31, 20172022 and 2016,2021, respectively, under agreements with affiliates as described above.
Disclosure of prepaid expensefuture consideration under revenue contracts with affiliates is included in Note 12—Revenues. Additionally, disclosure of future contractual obligations with affiliates and related to this agreementparties is included in other current assets—affiliate.Note 14—Commitments and Contingencies.
State Tax Sharing Agreements
CCL hasand 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 CCLeach 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, CCLeach of the respective entities will pay to Cheniere an amount equal to the state and local tax that CCLeach of the entities would be required to pay if CCL’sits 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 fromboth CCL under this agreement; therefore, Cheniere has not demanded any such payments from CCL. The agreement isand CCP were effective for tax returns due on or after May 2015.
We entered into equity contribution agreements with Cheniere and certain of its subsidiaries (the “Equity Contribution Agreements”) pursuant to which Cheniere agreed to contribute any of CCH’s Senior Secured Notes that Cheniere has repurchased to CCH. During the year ended December 31, 2022, Cheniere repurchased a total of $465 million of the outstanding principal amount of CCH’s Senior Secured Notes due 2025, 2027, 2029 and 2039 on the open market, which were immediately contributed under the Equity Contribution Agreements to us from Cheniere and cancelled by us.
Arrangement with ADCC Pipeline, LLC
In June 2022, Cheniere acquired a 30% equity interest in ADCC Pipeline, LLC and its wholly owned subsidiary (collectively, “ADCC Pipeline”) through its wholly owned subsidiary Cheniere ADCC Investments, LLC. ADCC Pipeline will develop, construct and operate an approximately 42-mile natural gas pipeline project (the “ADCC Pipeline Project”) connecting the Agua Dulce natural gas hub to the CCL Project. Cheniere currently has a state tax sharingfuture commitment of up to approximately $93 million to fund its equity interest, which commitment is subject to a condition precedent that has not yet been satisfied. CCL is party to a natural gas transportation agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returnsADCC Pipeline in the ordinary course of business for the operation of the CCL Project, with an initial term of 20 years with extension rights, which CCP and Cheniere are required to file on a combined basis and to timely paywill commence upon the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CCP will pay to Cheniere an amount equal tocompletion of the state and local tax that CCP would be required to pay if CCP’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CCP underADCC Pipeline Project.
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NOTE 9—INCOME TAXES
| 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 | |
Commitments
We have various contractualcommitments under executed contracts that include unconditional purchase obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contractscommitments which do not meet the definition of a liability as of December 31, 2017,2022 and thus are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.
CCL has a lump sum turnkey contractscontract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of three Trains and related facilities for the LiquefactionCorpus Christi Stage 3 Project. The total contract price of the EPC contract for Stage 2 or the Liquefaction Project was amended and restated in December 31, 2017. The EPC contract prices for Stage 1 of the Liquefaction Project and Stage 2 of the Liquefaction Project areis approximately $7.8$5.4 billion, and $2.4 billion, respectively, reflecting amounts incurred under change orders through December 31, 2017. 2022. As of December 31, 2022, we had approximately $3.9 billion remaining under this contract.
Natural Gas Supply, Transportation and Storage Service Agreements
CCL has physical natural gas supply contracts to secure natural gas feedstock for the rightLiquefaction Project. The remaining terms of these contracts range up to terminate each15 years.
Additionally, CCL has natural gas transportation and storage service agreements for the Liquefaction Project. The initial terms of the EPCnatural gas transportation agreements range up 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The initial term of the natural gas storage service agreements ranges up to five years.
As of December 31, 2022, CCL’s obligations under natural gas supply, transportation and storage service agreements for its convenience,contracts in which case Bechtel willconditions precedent were met or are currently expected to be paid the portionmet were as follows (in billions):
| Years Ending December 31, | Payments Due to Third Parties (1) | Payments Due to Related Party (1) | |||||||||
| 2023 | $ | 4.4 | $ | — | |||||||
| 2024 | 4.1 | — | |||||||||
| 2025 | 3.6 | — | |||||||||
| 2026 | 3.2 | 0.1 | |||||||||
| 2027 | 3.4 | 0.1 | |||||||||
| Thereafter | 24.1 | 0.8 | |||||||||
| Total | $ | 42.8 | $ | 1.0 | |||||||
(1)Pricing of the contract pricenatural gas supply contracts is variable based on market commodity basis prices adjusted for basis spread, and pricing of IPM agreements is variable based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2022. Some of our contracts may not have been negotiated as part of arranging financing for the work performed plus costs reasonably incurred by Bechtel on accountunderlying 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 $0.2 billion with third parties and $7.5 billion with affiliates. See Note 13—Related Party Transactions for additional information regarding such terminationagreements.
Environmental and demobilization. If the EPC contract for Stage 1 of theRegulatory Matters
The Liquefaction Project is terminated, Bechtelsubject 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 also be paidnot have a lump summaterial adverse effect on our results of up to $30.0 million depending on the termination date. If the amended and restated EPC contract for Stage 2operations, financial condition or cash flows.
64
Contents
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In the opinion of management, as of December 31, 2017,2022, 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 12—SUPPLEMENTAL CASH FLOW INFORMATION15—CUSTOMER CONCENTRATION
The following table provides supplemental disclosureshows external customers with revenues of cash flow information (in thousands):10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:
| Percentage of Total Revenues from External Customers | Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers | |||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, | December 31, | |||||||||||||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | 2022 | 2021 | ||||||||||||||||||||||||||||||||||||||||
| Customer A | 21% | 21% | 31% | 17% | * | |||||||||||||||||||||||||||||||||||||||
| Customer B | 14% | 16% | 16% | * | * | |||||||||||||||||||||||||||||||||||||||
| Customer C | 14% | 15% | 14% | * | * | |||||||||||||||||||||||||||||||||||||||
| Customer D | * | * | * | 33% | 31% | |||||||||||||||||||||||||||||||||||||||
| Customer E | * | * | —% | * | 11% | |||||||||||||||||||||||||||||||||||||||
| Customer F | 10% | * | —% | * | * | |||||||||||||||||||||||||||||||||||||||
| 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 | — | ||||||||
* Less than 10%
The balancefollowing table shows revenues from external customers attributable to the country in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $274.3 million, $145.6 million and $81.1 million aswhich 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 December 31, 2017, 2016 and 2015 respectively.business. Substantially all of our long-lived assets are located in the United States.
| Revenues from External Customers | |||||||||||||||||
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Spain | $ | 2,192 | $ | 1,432 | $ | 1,001 | |||||||||||
| Singapore | 1,248 | 694 | 134 | ||||||||||||||
| France | 940 | 423 | 136 | ||||||||||||||
| Indonesia | 889 | 618 | 336 | ||||||||||||||
| Ireland | 868 | 599 | 285 | ||||||||||||||
| United States | 199 | 141 | 154 | ||||||||||||||
| Total | $ | 6,336 | $ | 3,907 | $ | 2,046 | |||||||||||
65
CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NOTE 13—RECENT ACCOUNTING STANDARDS16—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides a brief descriptionsupplemental disclosure of recent accounting standards that had not been adopted by uscash flow information (in millions):
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Cash paid during the period for interest on debt, net of amounts capitalized | $ | 280 | $ | 423 | $ | 345 | |||||||||||
| Right-of-use assets obtained in exchange for new operating lease liabilities | 3 | — | — | ||||||||||||||
| Non-cash investing activity: | |||||||||||||||||
| Transfers of property, plant and equipment in exchange for other non-current assets | 17 | — | 2 | ||||||||||||||
| Contributions of assets from affiliates | 7 | — | — | ||||||||||||||
| Non-cash financing activity: | |||||||||||||||||
| 1,217 | — | — | |||||||||||||||
| (1,482) | — | — | |||||||||||||||
The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $70 million, $20 million and $86 million as of December 31, 2017:2022, 2021 and 2020, respectively.
66
| 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 | ||||||||||
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 Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 31, 2017,2022, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements on page 38and is incorporated herein by reference.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
67
PART III
ITEM 10. MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE
Omitted pursuant to Instruction I of Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to Instruction I of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS
Omitted pursuant to Instruction I of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE
Omitted pursuant to Instruction I of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG LLP, served as our independent auditor for the fiscal years ended December 31, 2017 and 2016.Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees paid tobilled by KPMG LLP for professional services rendered for 20172022 and 20162021 (in thousands)millions):
| Fiscal 2017 | Fiscal 2016 | |||||||
| Audit Fees | $ | 1,050 | $ | 1,070 | ||||
| Tax Fees | 89 | 29 | ||||||
| Total | $ | 1,139 | $ | 1,099 | ||||
| Fiscal 2022 | Fiscal 2021 | |||||||||||||
| Audit Fees | $ | 1 | $ | 1 | ||||||||||
Audit Fees—Audit fees for 20172022 and 20162021 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 20172022 and 2016.2021.
Tax Fees—TaxThere were no tax fees for 2017in 2022 and 2016 were for tax consultation services with respect to a sales and use tax analysis for the Liquefaction Project.2021.
Other Fees—There were no other fees in 20172022 and 2016.2021.
Auditor Pre-Approval Policy and Procedures
We are not a public company and we are not listed on any stock exchange. As a result, we are not required to, and do not, have an independent audit committee, a financial expert or a majority of independent directors. The audit committee of Cheniere has approved all audit and non-audit services to be provided by the independent accountants and the fees for such services during the fiscal years ended December 31, 20172022 and 2016.2021.
68
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:
(3) Exhibits:
Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:
•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
•may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;
•may apply standards of materiality that differ from those of a reasonable investor; and
•were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 3.1 | 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 | ||||||||||||||||||||||||||||
69
| 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 | 5/18/2016 | ||||||||||||||||||||||||||||
| 4.3 | Cheniere | 8-K | 4.1 | 12/9/2016 | ||||||||||||||||||||||||||||
| 4.4 | Cheniere | 8-K | 4.1 | 12/9/2016 | ||||||||||||||||||||||||||||
| 4.5 | CCH | 8-K | 4.1 | 5/19/2017 | ||||||||||||||||||||||||||||
| 4.6 | CCH | 8-K | 4.1 | 5/19/2017 | ||||||||||||||||||||||||||||
| 4.7 | CCH | 8-K | 4.1 | 9/12/2019 | ||||||||||||||||||||||||||||
| 4.8 | CCH | 8-K | 4.1 | 9/30/2019 | ||||||||||||||||||||||||||||
| 4.9 | CCH | 8-K | 4.1 | 9/30/2019 | ||||||||||||||||||||||||||||
| 4.10 | CCH | 8-K | 4.1 | 10/18/2019 | ||||||||||||||||||||||||||||
| 4.11 | CCH | 8-K | 4.1 | 10/18/2019 | ||||||||||||||||||||||||||||
| 4.12 | CCH | 8-K | 4.1 | 11/13/2019 | ||||||||||||||||||||||||||||
| 4.13 | CCH | 8-K | 4.1 | 11/13/2019 | ||||||||||||||||||||||||||||
| 4.14 | CCH | 8-K | 4.1 | 8/24/2021 | ||||||||||||||||||||||||||||
| 4.15 | CCH | 8-K | 4.1 | 8/24/2021 | ||||||||||||||||||||||||||||
| 4.16 | CCH | 8-K | 4.1 | 8/21/2020 | ||||||||||||||||||||||||||||
| 4.17 | CCH | 8-K | 4.1 | 8/21/2020 | ||||||||||||||||||||||||||||
70
71
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.10* | Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-000010 Insurance Provisional Sum Interim Adjustment, dated September 13, 2022 and (ii) the Change Order CO-000011 Package 6 Descope and Transfer to Owner, dated September 14, 2022 (Portions of this exhibit have been omitted) | |||||||||||||||||||||||||||||||
| 10.11 | CCH | S-4 | 10.14 | 1/5/2017 | ||||||||||||||||||||||||||||
| 10.12 | CCH | S-4 | 10.15 | 1/5/2017 | ||||||||||||||||||||||||||||
| 10.13 | Cheniere | 8-K | 10.1 | 4/2/2014 | ||||||||||||||||||||||||||||
| 10.14 | Cheniere | 8-K | 10.1 | 4/8/2014 | ||||||||||||||||||||||||||||
| 10.15 | Cheniere | 10-Q | 10.3 | 5/1/2014 | ||||||||||||||||||||||||||||
| 10.16 | Cheniere | 10-Q | 10.9 | 10/30/2015 | ||||||||||||||||||||||||||||
| 10.17 | Cheniere | 10-Q | 10.10 | 10/30/2015 | ||||||||||||||||||||||||||||
| 10.18 | Cheniere | 10-Q | 10.5 | 4/30/2015 | ||||||||||||||||||||||||||||
| 10.19 | CCH | S-4 | 10.22 | 1/5/2017 | ||||||||||||||||||||||||||||
| 10.20 | CCH | 10-Q | 10.1 | 11/1/2019 | ||||||||||||||||||||||||||||
| 10.21 | Cheniere | 8-K | 10.1 | 6/2/2014 | ||||||||||||||||||||||||||||
| 10.22 | CCH | 10-Q | 10.5 | 5/4/2018 | ||||||||||||||||||||||||||||
| 10.23 | CCH | 8-K | 10.6 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.24 | CCH | 10-K | 10.34 | 2/25/2020 | ||||||||||||||||||||||||||||
| 10.25 | CCH | 10-Q | 10.50 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.26 | CCH | 8-K | 10.50 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.27 | CCH | 10-Q | 10.40 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.28 | CCH | 10-Q | 10.20 | 11/3/2022 | ||||||||||||||||||||||||||||
72
| Exhibit No. | Incorporated by Reference (1) | |||||||||||||||||||||||||||||||
| Description | Entity | Form | Exhibit | Filing Date | ||||||||||||||||||||||||||||
| 10.29 | CCH | 10-Q | 10.30 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.30 | CCH | 10-Q | 10.10 | 5/4/2022 | ||||||||||||||||||||||||||||
| 10.31 | CCH | 8-K | 10.70 | 6/22/2022 | ||||||||||||||||||||||||||||
| 10.32 | CCH | 10-Q | 10.60 | 11/3/2022 | ||||||||||||||||||||||||||||
| 10.33 | CCH | 10-Q | 10.70 | 11/3/2022 | ||||||||||||||||||||||||||||
| 21.1* | ||||||||||||||||||||||||||||||||
| 22.1 | CCH | S-4 | 22.1 | 7/14/2020 | ||||||||||||||||||||||||||||
| 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) | |||||||||||||||||||||||||||||||
| as applicable. | ||||||
| Filed herewith. | ||||||
| Furnished herewith. | |||||
(c) Financial statements of affiliates whose securities are pledged as collateral — See Index to Financial Statements on page S-1.
73
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
(in millions)
| Balance at beginning of period | Charged to costs and expenses | Charged to other accounts | Deductions | Balance at end of period | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | |||||||||||||||||||||||||||||
| Current expected credit losses on receivables and contract assets | $ | 3 | $ | 1 | $ | — | $ | — | $ | 4 | |||||||||||||||||||
| Year Ended December 31, 2021 | |||||||||||||||||||||||||||||
| Current expected credit losses on receivables and contract assets | $ | 2 | $ | 1 | $ | — | $ | — | $ | 3 | |||||||||||||||||||
| Year Ended December 31, 2020 | |||||||||||||||||||||||||||||
| Current expected credit losses on receivables and contract assets | $ | — | $ | 2 | $ | — | $ | — | $ | 2 | |||||||||||||||||||
74
(in millions)
ITEM 16. FORM 10-K SUMMARY
None.
75
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 | |||||||||||
| President and Chief Financial Officer (Principal Executive and Financial Officer) | |||||||||||
| Date: | February | ||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| 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 | ||||
| Signature | Title | |||||||||||||
| 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 | |
| Date | |||||||||
| /s/ Zach Davis | Manager, President and Chief Financial Officer (Principal Executive and Financial Officer) | February 22, 2023 | |||||||
| Manager | ||||||||
| 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 | $ | — | $ | — | |||
| 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 | ||||
| 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 | ) | $ | — | |||
| Year Ended December 31, | ||||||||
| 2017 | 2016 | 2015 | ||||||
| Non-cash capital contribution for conveyance of asset from affiliate | — | 143 | — | |||||
| Corey Grindal | ||||||||
| /s/ David Slack | Chief Accounting Officer (Principal Accounting Officer) | February 22, 2023 | ||||||
| David Slack |
76
| 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 | $ | — | $ | — | ||||