UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549

 FORM 10-K

 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2024
 or
 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from to
 Commission file number 333-215435
 Cheniere Corpus Christi Holdings, LLC
 (Exact name of registrant as specified in its charter)

 Delaware
 47-1929160

 (State or other jurisdiction of incorporation or organization)
 (I.R.S. Employer Identification No.)

 845 Texas Avenue, Suite 1250
 Houston, Texas 77002
 (Address of principal executive offices) (Zip Code)
 ( 713) 375-5000
 (Registrant's telephone number, including area code)

 Securities registered pursuant to Section 12(b) of the Act:

 Title of each class
 Trading Symbol
 Name of each exchange on which registered

 None
 None
 None

 Securities registered pursuant to Section 12(g) of the Act: None
 The registrant meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No
 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No
 Note: The registrant is a voluntary filer not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934. However, the registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.
 Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes No
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

 Large accelerated filer

 Accelerated filer

 Non-accelerated filer

 Smaller reporting company

 Emerging growth company

 If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
 Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
 If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
 Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b).
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
 The aggregate market value of the voting and non-voting common equity held by non-affiliates: Not applicable
 Indicate the number of shares outstanding of the issuer's classes of common stock, as of the latest practicable date: Not applicable
 Documents incorporated by reference: None

 CHENIERE CORPUS CHRISTI HOLDINGS, LLC

 Items 1. and 2. Business and Properties

 Item 1A. Risk Factors

 Item 1B. Unresolved Staff Comments

 Item 1C. Cybersecurity

 Item 3. Legal Proceedings

 Item 4. Mine Safety Disclosure

 Item 5. Market for Registrant's Common Equity, Related Member Matters and Issuer Purchases of Equity Securities

 Item 6. [Reserved]

 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

 Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 Item 8. Financial Statements and Supplementary Data

 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 Item 9A. Controls and Procedures

 Item 9B. Other Information

 Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections

 Item 10. Managers, Executive Officers and Company Governance

 Item 11. Executive Compensation

 Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters

 Item 13. Certain Relationships and Related Transactions, and Manager Independence

 Item 14. Principal Accountant Fees and Services

 Item 15. Exhibits and Financial Statement Schedules

 Item 16. Form 10-K Summary

 Signatures

 i

 DEFINITIONS

 As used in this annual report, the terms listed below have the following meanings:

 Common Industry and Other Terms

 ASU
 Accounting Standards Update

 Bcf
 billion cubic feet

 Bcf/yr
 billion cubic feet per year

 Bcfe
 billion cubic feet equivalent

 DAT
 delivered at terminal

 DOE
 U.S. Department of Energy

 EPC
 engineering, procurement and construction

 ESG
 environmental, social and governance

 FASB
 Financial Accounting Standards Board

 FERC
 Federal Energy Regulatory Commission

 FID
 final investment decision

 FOB
 free-on-board

 FTA countries
 countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas

 GAAP
 generally accepted accounting principles in the United States

 Henry Hub
 the final settlement price (in U.S. dollars per MMBtu) for the New York Mercantile Exchange's Henry Hub natural gas futures contract for the month in which a relevant cargo's delivery window is scheduled to begin

 IPM agreements
 integrated production marketing agreements in which the gas producer sells to us gas on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs

 LNG
 liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state

 MMBtu
 million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit

 mtpa
 million tonnes per annum

 non-FTA countries
 countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted

 SEC
 U.S. Securities and Exchange Commission

 SOFR
 Secured Overnight Financing Rate

 SPA
 LNG sale and purchase agreement

 TBtu
 trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit

 Tcf
 trillion cubic feet

 Train
 an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG

 Abbreviated Legal Entity Structure

 The following diagram depicts our abbreviated legal entity structure as of December 31, 2024, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:

 Unless the context requires otherwise, references to 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.

 CAUTIONARY STATEMENT
 REGARDING FORWARD-LOOKING STATEMENTS

 This annual report contains certain statements that are, or may be deemed to be, "forward-looking statements." All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are "forward-looking statements." Included among "forward-looking statements" are, among other things:
 • statements regarding our expected receipt of cash distributions from our subsidiaries;
 • statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction facility, pipeline facility 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 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 pipelines, including the financing of such 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 relating to our goals, commitments and strategies in relation to environmental matters;
 • 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; and
 • other factors described in Item 1A. Risk Factors in this Annual Report on Form 10-K.

 All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "achieve," "anticipate," "believe," "contemplate," "continue," "estimate," "expect," "intend," "plan," "potential," "predict," "project," "pursue," "target," the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only 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.

 ITEMS 1. AND 2. BUSINESS AND PROPERTIES

 General

 We are a Delaware limited liability company formed by Cheniere. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

 LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, converted back into natural gas (called "regasification") and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking, other industrial uses and back up for intermittent energy sources. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.

 We own and operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the "Corpus Christi LNG Terminal") through CCL, which has natural gas liquefaction facilities consisting of three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. We are constructing an expansion of the Corpus Christi LNG Terminal (the "Corpus Christi Stage 3 Project") consisting of seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. We also own and operate through CCP an approximately 21-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the "Corpus Christi Pipeline" and together with the existing assets at the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the "Liquefaction Project").

 Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows, and include 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 IPM agreements, in which a gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is primarily indexed to Henry Hub and generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and IPM agreements currently in effect, with approximately 16 years of weighted average remaining life as of December 31, 2024, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.

 We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold a significant land position at the Corpus Christi LNG Terminal, which provides opportunity for further liquefaction capacity expansion. In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the Natural Gas Act of 1938, as amended (the "NGA"), for an expansion adjacent to the Liquefaction Project consisting of two midscale Trains with an expected total production capacity of approximately 3 mtpa of LNG (the "Midscale Trains 8 & 9 Project"), for which a positive Environmental Assessment was received in June 2024. This expansion may be developed and constructed by an affiliate of ours outside of the Liquefaction Project. The development of the Midscale Trains 8 & 9 Project or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.

 Our Business Strategy

 Our primary business strategy is to develop, construct and operate assets to meet our long-term customers' energy demands. We plan to implement our strategy by:
 • safely, efficiently and reliably operating and maintaining our assets, including our Trains;
 • procuring natural gas and pipeline transport capacity to our facility;
 • commencing commercial delivery for our long-term SPA customers, of which we have initiated for 14 of 15 third party long-term SPA customers as of December 31, 2024;
 • completing our construction projects safely, on-time and on-budget;
 • maximizing the production of LNG to serve our customers and generating steady and stable revenues and operating cash flows;
 • further expanding and/or optimizing the Liquefaction Project by leveraging existing infrastructure;
 • maintaining a prudent and cost-effective capital structure; and
 • strategically identifying actionable and economic environmental solutions.

 Our Business

 We shipped our first LNG cargo in December 2018 and as of February 14, 2025, approximately 1,090 cumulative LNG cargoes totaling approximately 75 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

 Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Liquefaction Project and Expansion Projects

 The Liquefaction Project, as described above under the caption General, includes three Trains, three storage tanks, two marine berths and the construction of the Corpus Christi Stage 3 Project with seven midscale Trains. Additionally, in March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for the Midscale Trains 8 & 9 Project, for which a positive Environmental Assessment was received in June 2024. We expect to receive all remaining necessary regulatory approvals for the project in 2025.

 The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2024:

 Overall project completion percentage
 77.2%

 Completion percentage of:

 Engineering
 97.2%

 Procurement
 97.2%

 Subcontract work
 88.2%

 Construction
 42.6%

 Date of expected substantial completion
 1H 2025 - 2H 2026

 The following summarizes the volumes of natural gas for which we have received approvals from the FERC to site, construct and operate the Trains at the Liquefaction Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG Terminal through December 31, 2050:

 FERC Approved Volume
 DOE Approved Volume (1)

 (in Bcf/yr)
 (in mtpa)
 (in Bcf/yr)
 (in mtpa)

 Trains 1 through 3 of the Liquefaction Project:

 FTA countries
 875.16
 875.16

 Non-FTA countries
 875.16
 875.16

 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

 (1)Excludes 170 Bcf/yr to FTA countries authorized in July 2023 for the Midscale Trains 8 & 9 Project that is not effective until the date of first commercial export from the Midscale Trains 8 & 9 Project.

 Natural Gas Supply, Transportation and Storage

 CCL has secured natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements, including IPM agreements. Additionally, to ensure that CCL is able to transport and manage the natural gas feedstock to the Liquefaction Project, it has transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third parties and CCP.

 Major Customers

 Customers accounting for 10% or more of total consolidated revenues were as follows:

 Percentage of Total Revenues from External Customers

 2024
 2023
 2022

 Endesa Generaci n, S.A. (which subsequently assigned its SPA to Endesa S.A.) and Endesa S.A.

 20%
 22%
 21%

 PT Pertamina (Persero)

 13%
 15%
 14%

 Naturgy LNG GOM, Limited

 13%
 14%
 14%

 Trafigura Pte Ltd and affiliates

 *
 *
 10%

 * Less than 10%

 All of the above customers contribute to our LNG revenues through SPA contracts.

 Additional information regarding our customer contracts can be found in Liquidity and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 13—Segment Information and Customer Concentration of our Notes to Consolidated Financial Statements.

 Governmental Regulation

 The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.

 Federal Energy Regulatory Commission

 The design, construction, operation, maintenance and expansion of the Liquefaction Project, the export of LNG and the purchase and transportation of natural gas in interstate commerce through the Corpus Christi Pipeline are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. Under the NGA, the FERC's jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to

 natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.

 The FERC's authority to regulate interstate natural gas pipelines and the services that they provide generally includes regulation of:
 • rates and charges, and terms and conditions for natural gas transportation, storage and related services;
 • the certification and construction of new facilities and modification of existing facilities;
 • the extension and abandonment of services and facilities;
 • the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;
 • the acquisition and disposition of facilities;
 • the initiation and discontinuation of services; and
 • various other matters.

 Under the NGA, our pipeline is not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including its own marketing affiliate. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified the FERC's policy in this area expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area. On February 18, 2022, the FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for the FERC's decision-making process, modifying the standards that the FERC uses to evaluate applications to include, among other things, reasonably foreseeable greenhouse gas ("GHG") emissions that may be attributable to the project and the project's impact on environmental justice communities. On March 24, 2022, the FERC rescinded the Policy Statement, re-issued it as a draft and it remains pending. At this time, we do not expect it to have a material adverse effect on our operations.

 We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate granted by the FERC with the issuance of our Certificate of Public Convenience and Necessity to our marketing affiliates. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.
 In order to site, construct and operate the Liquefaction Project, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the "EPAct") amended Section 3 of the NGA to establish or clarify the FERC's exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency's authorities or responsibilities related to LNG terminals or those of a state acting under federal law.

 In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the Midscale Trains 8 & 9 Project, for which a positive Environmental Assessment was received in June 2024.

 The FERC's Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. The general principles of the FERC Standards of Conduct are: (1) independent functioning, which requires transmission function employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue preference due to the improper disclosure of non-public transmission function information. We have established the required policies, procedures and training to comply with the FERC's Standards of Conduct.

 All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC's jurisdiction under the NGA allows it to impose civil and criminal

 penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.5 million per day per violation, including any conduct that violates the NGA's prohibition against market manipulation.

 Several other governmental and regulatory approvals and permits are required throughout the life of the Liquefaction Project. In addition, our FERC orders require us to comply with certain ongoing conditions and reporting obligations and maintain other regulatory agency approvals throughout the life of the Liquefaction Project. For example, throughout the life of the Liquefaction Project, we are subject to regular reporting requirements to the FERC, the Department of Transportation's ("DOT") Pipeline and Hazardous Materials Safety Administration ("PHMSA") and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations has not materially affected our construction or operations.

 DOE Export Licenses

 The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG Terminal, as discussed in Liquefaction Project and Expansion Projects. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.

 Under Section 3 of the NGA, applications for exports of natural gas (including LNG) to FTA countries, which allow for national treatment for trade in natural gas, are "deemed to be consistent with the public interest" and shall be granted by the DOE without "modification or delay." FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations, which did not have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity for the year ended December 31, 2024. The DOE publicly released the updated analyses on December 17, 2024, and has solicited public comments on the analyses. On January 20, 2025, President Trump signed an Executive Order revoking the Biden Administration pause and extending the time for public comment. We do not expect the publication of the analyses to have a material effect on future DOE non-FTA export authorizations. The Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. See Liquefaction Project and Expansion Projects section above for FERC and DOE approved volumes on our existing Liquefaction Project.

 Pipeline and Hazardous Materials Safety Administration

 The Liquefaction Project is subject to regulation by PHMSA, who is authorized by the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation, maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.

 PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $273,000 per day per violation, with a maximum administrative civil penalty of approximately $2.7 million for any related series of violations.

 Other Governmental Permits, Approvals and Authorizations

 Construction and operation of the Liquefaction Project requires additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army Corps of Engineers ("USACE"), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the U.S. Environmental Protection Agency (the "EPA"), U.S. Department of Homeland Security, the Texas Commission on Environmental Quality ("TCEQ") and the Railroad Commission of Texas.

 The USACE issues its permits under the authority of the Clean Water Act ("CWA") (Section 404) and the Rivers and Harbors Act (Section 10). The EPA administers the Clean Air Act ("CAA") and has delegated authority to the TCEQ to issue the Title V Operating Permit and the Prevention of Significant Deterioration Permit. These two permits are issued by the TCEQ.

 Commodity Futures Trading Commission ("CFTC")

 The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in those markets. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act.
 As required by the Dodd-Frank Act, the CFTC and federal banking regulators also adopted rules requiring swap dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We qualify as a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

 Pursuant to the Dodd-Frank Act, the CFTC adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

 Environmental Regulation

 The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.

 Clean Air Act

 The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. However, we do not believe any such requirements will have a material adverse effect on our operations or the construction of our Liquefaction Project.

 On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants ("NESHAP") Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant ("HAP") emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that the construction and operation of our Liquefaction Project will be materially and adversely affected by such regulatory actions.

 We are supportive of regulations reducing GHG emissions over time. Since 2009, the EPA has promulgated and finalized multiple GHG emissions regulations related to reporting and reductions of GHG emissions from our facilities. On December 2, 2023, the EPA issued final rules to reduce methane and volatile organic compounds ("VOC") emissions from

 new, existing and modified emission sources in the oil and gas sector. These regulations require monitoring of methane and VOC emissions at our compressor stations. We do not believe such regulations will have a material adverse effect on our operations, financial condition or results of operations.

 From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. On August 16, 2022, President Biden signed H.R. 5376 (P.L. 117-169), the Inflation Reduction Act of 2022 ("IRA") which includes a charge on methane emissions above a certain methane intensity threshold for facilities that report their GHG emissions under the EPA's Greenhouse Gas Emissions Reporting Program Part 98 regulations. The charge started at $900 per metric ton of methane in 2024, increased to $1,200 per metric ton in 2025, and is increasing to $1,500 per metric ton in 2026 and beyond. On November 12, 2024, the EPA finalized a rule to impose and collect the methane emissions charge authorized under the IRA. We do not believe the methane charge will have a material adverse effect on our operations, financial condition or results of operations.
 The timing, extent and impact of these rules and other Biden Administration initiatives remain uncertain as the Trump Administration has undertaken steps to delay their implementation, and to review, repeal and potentially replace them.
 Coastal Zone Management Act ("CZMA")

 The siting and construction of the Liquefaction Project within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.
 Clean Water Act

 The Liquefaction Project is subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Texas, by the TCEQ). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.

 Resource Conservation and Recovery Act ("RCRA")

 The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.
 Protection of Species, Habitats and Wetlands

 Various federal and state statutes, such as the Endangered Species Act, the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If our Liquefaction Project adversely affects a protected species or its habitat, we may be required to develop and follow a plan to remediate those impacts. In that case, siting, construction or operations may be delayed or restricted and cause us to incur increased costs.

 It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe such regulatory actions will have a material adverse effect on our operations or the construction of our Liquefaction Project.

 Market Factors and Competition

 Market Factors

 Our ability to enter into additional long-term SPAs to underpin the development of additional Trains or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the extent of energy security needs in the European Union and elsewhere, the rate of fuel switching from coal, nuclear or oil to natural gas and other overarching factors such as global economic growth and the pace of any transition from fossil-based systems of energy production and consumption to alternative energy sources. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community's appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.

 We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Market participants around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Currently, significant amounts of money are being invested across Europe and Asia 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 75 mtpa of import capacity over the near-term to secure access to LNG and displace Russian gas imports. In India, there are more than 5,600 kilometers of gas pipelines under construction to expand the gas distribution network and increase access to natural gas. And in China, billions of U.S. dollars have already been invested and hundreds of billions of U.S. dollars are expected to be further invested all along the natural gas value chain to enable growth and decrease harmful emissions. Furthermore, some of the existing integrated liquefaction facilities outside of the U.S. have been experiencing issues related to reduced feed gas as a result of depleting upstream resources. Global supply contributions from these plants have been decreasing and LNG supply growth is expected to help support these shortages.

 As a result of these dynamics, we expect natural gas and LNG to continue to play an important role in satisfying energy demand going forward. In its forecast published in the third quarter of 2024, Wood Mackenzie Limited ("WoodMac") forecasted that global demand for LNG would increase by approximately 61%, from approximately 418 mtpa, or 20.1 Tcf, in 2023, to 675 mtpa, or 32.4 Tcf, in 2040 and by approximately 65% to 691 mtpa or 33.1 Tcf in 2050. WoodMac also forecasted LNG production from existing operational facilities and new facilities already under construction would be able to supply the market with approximately 532 mtpa in 2040, declining to 463 mtpa in 2050. This could result in a market need for construction of an additional approximately 142 mtpa of LNG production by 2040 and about 227 mtpa by 2050. As a cleaner burning fuel with lower emissions than coal or liquid fuels in power generation, we expect natural gas and LNG to play a central role in balancing grids, serving as back up for intermittent energy sources and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project, as well as our proposed expansion is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

 As described above under the caption General, we have limited exposure to oil price movements as we have contracted a significant portion of our LNG production capacity under long-term SPAs and IPM agreements, which are structured to generate fixed fees in addition to variable fees indexed to Henry Hub or international LNG pricing. Refer to General for further discussion of our long-term agreements.

 Competition

 Despite the long term nature of our SPAs, when CCL needs to replace or amend any existing SPA or enter into new SPAs, CCL will compete with other natural gas liquefaction projects throughout the world primarily on the basis of price per contracted volume of LNG at that time, as well as attributes such as commercial innovation, reliable production and customer-focused operations to provide flexible and tailored solutions to LNG buyers. Our competition includes our affiliate Sabine Pass Liquefaction, LLC ("SPL"), which operates six Trains at a natural gas liquefaction facility in Cameron Parish, Louisiana (the "SPL Project"). Revenues associated with any incremental volumes of the Liquefaction Project sold outside of CCL's long-term SPAs, including those made available to Cheniere Marketing International LLP ("Cheniere Marketing"), will also be subject to market-based price competition.

 Corporate Responsibility

 As described in Market Factors and Competition, we expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Our vision is to provide clean, secure and affordable energy to the world. This vision underpins our focus on responding to the world's shared energy challenges — expanding the global supply of clean, secure and affordable energy, improving air quality, reducing emissions and supporting the transition to a lower-carbon future. Our approach to corporate responsibility is guided by our Climate and Sustainability Principles: Transparency, Science, Supply Chain and Operational Excellence. In August 2024, we published Energy Secured, Benefits Delivered, our fifth Corporate Responsibility ("CR") report, which details our approach and progress on ESG matters. Our CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K.

 Cheniere's climate strategy is to measure and mitigate emissions so that it may better position its LNG supplies to remain competitive in a lower carbon future and provide energy, economic and environmental security to its customers across the world. To maximize the environmental benefits of our LNG, we believe it is important to develop our climate goals and strategies based on an accurate and holistic assessment of the emissions profile of our LNG, accounting for all steps in the supply chain.

 Consequently, Cheniere has collaborated with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment ("LCA") models, quantification, monitoring, reporting and verification ("QMRV") of GHG emissions and other research and development projects. Cheniere also co-founded and sponsored the Energy Emissions Modeling and Data Lab ("EEMDL"), a multidisciplinary research and education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition, Cheniere commenced providing Cargo Emissions Tags ("CE Tags") to its long-term customers in June 2022, and in October 2022 joined the Oil and Gas Methane Partnership ("OGMP") 2.0, the United Nations Environment Programme's ("UNEP") flagship oil and gas methane emissions reporting and mitigation initiative. To ensure transparency and rigor, Cheniere works with academics and scientists to publish methodologies and results in multiple peer-reviewed journals.

 Our total incremental expenditures related to climate initiatives, including capital expenditures, were not material to our Consolidated Financial Statements during the years ended December 31, 2024, 2023 and 2022. However, as governments consider and implement actions to reduce GHG emissions and the transition to a lower-carbon economy continues to evolve, as described in Market Factors and Competition, we expect the scope and extent of our future climate and sustainability initiatives to evolve accordingly. While we have not incurred material direct expenditures related to climate change, we are proactive in our management of climate risks and opportunities, including compliance with existing and future government regulations. We face certain business and operational risks associated with physical impacts from climate change, such as exposure to severe weather events or changes in weather patterns, in addition to transition risks. Please see Item 1A. Risk Factors for additional discussion.

 Subsidiaries

 Substantially all of our assets are held by our subsidiaries. We conduct most of our business through these subsidiaries, including the operation of our Liquefaction Project.

 Employees

 We have no employees. We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. See Note 11—Related Party Transactions of our Notes to Consolidated Financial Statements for a discussion of such services agreements with our affiliate entities. As of December 31, 2024, Cheniere and its subsidiaries had 1,714 full-time employees, including 505 employees who directly supported the Liquefaction Project.

 Available Information

 Our principal executive offices are located at 845 Texas Avenue, Suite 1250, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the

 Securities Exchange Act of 1934, as amended (the "Exchange Act"). These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers.

 ITEM 1A. RISK FACTORS

 The following are some of the important risk factors that could adversely affect our business, financial condition, results of operations or cash flows or have other adverse impacts, and could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

 The risk factors in this report are grouped into the following categories:
 • Risks Relating to Our Financial Matters;
 • Risks Relating to Our Operations and Industry; and
 • Risks Relating to Regulations.

 Risks Relating to Our Financial Matters

 An inability to source capital to supplement our available cash resources and existing credit facilities could cause us to have inadequate liquidity and could materially and adversely affect us.

 As of December 31, 2024, we had $113 million of restricted cash and cash equivalents, $4.7 billion of available commitments under our credit facilities and $4.9 billion of total debt outstanding (before unamortized discount and debt issuance costs). We incur, and will incur, significant interest expense relating to financing the assets at the Corpus Christi LNG Terminal, and we anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the Corpus Christi Stage 3 Project as well as the Midscale Trains 8 & 9 Project if a positive FID is made. Our ability to fund our capital expenditures and refinance our indebtedness may depend on our ability to access additional project financing as well as the debt capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions' evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also may rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

 Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant customer fails to perform its contractual obligations for any reason.

 Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2024, we had SPAs with a total of 15 different third party customers.

 While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

 Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs upon the occurrence of certain events of force majeure.

 Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.

 Our use of derivative instruments, including our IPM agreements, to manage risks could adversely affect our earnings reported under GAAP and our liquidity.

 We use derivative instruments to manage our commodity-related price risk. The extent of our derivative position at any given time depends on our assessment of risks and related exposures for these commodities. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, our net income for the years ended December 31, 2024 and 2023 included gains of $1.0 billion and $5.8 billion, respectively, resulting from changes in the fair values of our derivatives (before tax and the impact of non-controlling interests), substantially all of which 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 respective commodity exchanges or over-the-counter arrangements, or the failure of a counterparty to perform in accordance with a contract. As of December 31, 2024 and 2023, we had collateral posted with counterparties by us of $5 million and $3 million, respectively, which are included in other current assets, net in our Consolidated Balance Sheets.

 Risks Relating to Our Operations and Industry

 Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us.

 Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our Liquefaction Project. In August 2020, we entered into an arrangement with our affiliate to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers from the other facility in the event operational conditions impact operations at the Corpus Christi LNG Terminal or at our affiliate's terminal. During the year ended December 31, 2021, four TBtu was loaded at our facilities for our affiliate pursuant to this agreement. Our risk of loss related to weather events or other disasters is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our Consolidated Financial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or interruption of operations at our terminal or related infrastructure, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of the Liquefaction Project or our other facilities. Our LNG terminal infrastructure and LNG facility located in or near Corpus Christi, Texas are designed in accordance with requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.

 Disruptions to the third party supply of natural gas to our pipeline and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 We depend upon third party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted. Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the risk factor Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

 Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including composition changes in the quality of feed gas received from third parties, non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of natural gas to our pipeline and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Our ability to complete development and/or construction of additional Trains, including the Midscale Trains 8 & 9 Project, will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.

 We continuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. As described further in Items 1. and 2. Business and Properties, we are currently developing the Midscale Trains 8 & 9 Project. The commercial development of an LNG facility takes a number of years and requires a substantial capital investment that is dependent on sufficient funding and commercial interest, among other factors.

 We will require significant additional funding to be able to commence construction of the Midscale Trains 8 & 9 Project, or any additional expansion projects, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development or construction of the Midscale Trains 8 & 9 Project, any additional Trains or any additional expansion projects, and we may not be able to complete our business plan, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Cost overruns and delays in the completion of our expansion projects, including the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Our investment decision on the Corpus Christi Stage 3 Project and any potential future expansion of LNG facilities, including the Midscale Trains 8 & 9 Project, relies on cost estimates developed initially through front end engineering and design studies. However, due to the size and duration of construction of an LNG facility, the actual construction costs may be significantly higher than our current estimates as a result of many factors, including but not limited to changes in scope and the ability of Bechtel Energy Inc. ("Bechtel") and our other contractors to execute successfully under their agreements. Although our major EPC contracts are fixed price, as construction progresses, we may decide or be forced to submit change orders to our contractor, including change orders to comply with existing or future environmental or other regulations. Any change orders could result in longer construction periods, higher construction costs, including increased commodity prices (particularly nickel and steel) and escalating labor costs, or both. Additionally, our SPAs generally provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Significant increases in the cost of a liquefaction project or significant construction delays could impact the commercial viability of the project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects. While historically we have not experienced cost overruns or construction delays that have had a significant adverse impact on our operations, factors giving rise to such events in the future may be outside of our control and could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

 The construction and operation of the Liquefaction Project are, and will be, subject to the inherent risks associated with these types of operations as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

 We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. Although losses incurred as a result of self insured risk have not been material historically, the occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 We are dependent on our EPC partners and other contractors for the successful completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project.

 Timely and cost-effective completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our EPC partners, including Bechtel, and our other contractors under their agreements. The ability of our EPC partners and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
 • design and engineer each Train to operate in accordance with specifications;
 • engage and retain third party subcontractors and procure equipment and supplies;

 • respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
 • attract, develop and retain skilled personnel, including engineers;
 • post required construction bonds and comply with the terms thereof;
 • manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
 • maintain their own financial condition, including adequate working capital.

 Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of EPC partners and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.
 Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Corpus Christi Stage 3 Project and any potential expansion projects, including the Midscale Trains 8 & 9 Project, or result in a contractor's unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
 • competitive liquefaction capacity in North America;
 • insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
 • insufficient LNG tanker capacity;
 • weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;
 • reduced demand and lower prices for natural gas;
 • increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
 • decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
 • cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
 • changes in supplies of, and prices for, alternative energy sources, which may reduce the demand for natural gas;
 • changes in regulatory, tax or other governmental policies regarding exported LNG, natural gas or alternative energy sources, which may reduce the demand for exported LNG and/or natural gas;
 • political conditions in customer regions;
 • sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;

 • adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and
 • cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

 Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect our LNG business and the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Failure of exported LNG to be a long term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Operations of the Liquefaction Project are dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from the United States and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.

 Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from non-U.S. markets or from our competitors' liquefaction facilities in the United States.

 As described in Market Factors and Competition in in Items 1. and 2. Business and Properties, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to alternative fossil fuel energy sources such as oil and coal. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy as such alternative sources emerge. Additionally, LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.
 As described in General in Items 1. and 2. Business and Properties, we have contracted through our SPAs and IPM agreements approximately 90% of the total anticipated production from the Liquefaction Project with approximately 16 years of weighted average remaining life as of December 31, 2024, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. However, as a result of the factors described above and other factors, the LNG we produce may not remain a long term competitive source of energy internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG from the United States could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 We face competition based upon the international market price for LNG.

 Our Liquefaction Project is subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our Liquefaction Project are diverse and include, among others:
 • increases in worldwide LNG production capacity and availability of LNG for market supply;

 • increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
 • increases in the cost to supply natural gas feedstock to our Liquefaction Project;
 • decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
 • decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
 • increases in capacity and utilization of nuclear power and related facilities; and
 • displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
 A cyber attack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Project, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.

 The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our pipeline and liquefaction operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Project. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should multiple of the third party pipelines which supply our Liquefaction Project suffer similar concurrent attacks, our Liquefaction Project may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A cyber attack involving our business or operational control systems or related infrastructure, or that of third parties pipelines with whom we do business, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.

 Outbreaks of infectious diseases, such as COVID-19, at our facilities could adversely affect our operations or business.

 Our facilities at the Corpus Christi LNG Terminal are critical infrastructure and continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases is unknown and 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 or business.

 We are entirely dependent on Cheniere for key personnel, and the unavailability of skilled workers or Cheniere's failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.

 As of December 31, 2024, Cheniere and its subsidiaries had 1,714 full-time employees, including 505 employees who directly supported the Liquefaction Project. We have contracted with subsidiaries of Cheniere to provide the personnel necessary for the construction and operation of the Liquefaction Project. We depend on Cheniere's subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is operating and developing, including, as further described in Market Factors and Competition in Items 1. and 2. Business Properties, the operation and construction of its liquefaction projects in Cameron Parish, Louisiana, for the time and expertise of Cheniere's personnel. Further, we and Cheniere face competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.

 Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our ability to engage, and Cheniere's ability to attract and retain, additional qualified personnel.

 A shortage in the labor pool of skilled workers, remoteness of our site locations, general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. Any increase in our operating costs could materially and adversely affect our business results.

 We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.

 We have agreements to compensate and to reimburse expenses of Cheniere's affiliates. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, SPL is currently operating the SPL Project and its affiliates are developing an expansion project adjacent to the SPL Project. Cheniere and its affiliates have entered into fixed price SPAs with third parties for the sale of LNG from the SPL Project and the adjacent expansion project, and may continue to enter into commercial arrangements with respect to this liquefaction facility that might otherwise have been entered into with respect to any of our future Trains.

 We have or will have numerous contracts and commercial arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements with one or more Cheniere-affiliated entities as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.
 We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.

 Risks Relating to Regulations

 Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, and operation of our pipeline and the export of LNG could impede operations and construction and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 The design, construction and operation of interstate natural gas pipelines, our LNG terminal, including the Liquefaction Project, the Midscale Trains 8 & 9 Project and other facilities, as well as the export of LNG are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.

 To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the three Trains and related facilities of the Liquefaction Project, as well as the seven midscale Trains and related facilities for the Corpus Christi Stage 3 Project as well as orders under Section 7 of the NGA authorizing the construction and operation of the Corpus Christi Pipeline. In March 2023, CCL and another subsidiary of Cheniere submitted an application with the FERC under the NGA for the Midscale Trains 8 & 9 Project, for which a positive Environmental Assessment from the FERC was received in June 2024. To date, the DOE has also issued orders under Section 4 of the NGA authorizing CCL to export domestically produced LNG. The Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipeline on land owned by third parties. If we were to lose these rights or be required to relocate our pipeline, our business could be materially and adversely affected.

 Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with or our inability to obtain and maintain existing or newly imposed approvals, permits and filings that may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to our operations could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
 Our Corpus Christi Pipeline and its FERC gas tariff are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.

 The Corpus Christi Pipeline is subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the "NGPA"). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by our Corpus Christi Pipeline must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any potential shipper with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our Corpus Christi Pipeline could be subject to substantial penalties and fines.

 In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.5 million per day for each violation.
 Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.

 Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.

 Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources, and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG terminal, marine berths and pipeline, including FERC, PHMSA, EPA and the United States Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, difficulty obtaining and maintaining permits from regulatory agencies or increased capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.

 The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. On December 2, 2023, the EPA issued final rules to reduce methane and VOC emissions from new, existing and modified emission sources in the oil and gas sector. These regulations require monitoring of methane and VOC emissions at our compressor stations. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that applied to our facilities beginning in calendar year 2024. On November 12, 2024, the EPA finalized a rule to impose and collect methane emissions charges authorized under the IRA. In addition, other international, federal and state initiatives may be considered in the future to address GHG emissions through treaty commitments, direct regulation, market-based

 regulations such as a GHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

 Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.

 In 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 beginning in 2022.
 Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from the Corpus Christi LNG Terminal or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national or international climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

 Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Consolidated Financial Statements for the years ended December 31, 2024, 2023 and 2022. Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction costs or restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

 Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.

 The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in "high or moderate consequence areas" where a leak or rupture could potentially do the most harm. As an operator, we are required to:
 • perform ongoing assessments of pipeline safety and compliance;
 • identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
 • improve data collection, integration and analysis;
 • repair and remediate the pipeline as necessary; and
 • implement preventative and mitigating actions.

 We are required to utilize pipeline integrity management programs that are intended to maintain pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety's rules and related regulations and orders, we could be subject to significant penalties and fines, which for certain violations can aggregate up to as high as $2.7 million.

 Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity.

 We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact. Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including those related to tariffs and duties, could affect our obligations, profitability and cash flows in the future. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. We continuously monitor and assess proposed tax legislation that could negatively impact our business.

 ITEM 1B. UNRESOLVED STAFF COMMENTS

 None.

 ITEM 1C. CYBERSECURITY

 Cyberattacks represent a potentially significant risk to the Company and our industry. We rely on subsidiaries of Cheniere through our service agreements with them, as further discussed in Note 11—Related Party Transactions of our Notes to Consolidated Financial Statements, and Cheniere's board of directors (the "Board"), which has oversight of our operations, to implement policies and procedures that are intended to manage and reduce this risk.

 Risk Management and Strategy

 As part of its broader approach to risk management, Cheniere's cybersecurity program is designed to follow an "identify, protect, detect, respond and recover" approach to cybersecurity that is based off of the National Institute of Standards and Technology Cybersecurity Framework ("CSF"). Cheniere's strategy also includes segmentation of corporate and operations networks, defense in depth and the least privileged access principle. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, Cheniere routinely evaluates opportunities to refine its cybersecurity program in order to mitigate operational network risks. Cheniere includes business continuity planning as a component of its strategy to help ensure critical systems are available to support the Company in the instance of a disruptive event. Cheniere also participates in various industry organizations to stay abreast of recent trends and developments.

 On an ongoing basis, Cheniere assesses its people, processes and technology and, when necessary, adjusts the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. Cheniere conducts regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance Cheniere's Cyber Incident Response Plan. To support these efforts, Cheniere has contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems and security maturity assessments of its corporate and operational networks. Cheniere maintains a training program to help its personnel identify and assist in mitigating cybersecurity and data security risks. Cheniere's employees and the members of the Board participate in annual training, user awareness campaigns and additional issue-specific training as needed. Cheniere also provides annual training for certain contractors who have access to its information technology networks.
 With respect to third party service providers, Cheniere's information security program includes conducting risk-based due diligence of certain service providers' information security programs prior to onboarding. Cheniere strives to contractually require third party service providers with access to its information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use Cheniere's data, including personal information, for purposes other than to provide services to them, except as required by applicable law. Cheniere also strives to negotiate contractual requirements which compel its service providers to notify them of information security incidents occurring on their systems which may affect Cheniere's systems or data, including personal information.

 During the year ended December 31, 2024, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition.

 Governance

 We rely on Cheniere's cybersecurity leadership team, which consists of its Director and Chief Information Security Officer, Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of Cheniere's cybersecurity governance, cyber risk management and security operations and are responsible for maintaining Cheniere's technology defense posture and program. As part of their governance and risk management responsibilities, these individuals oversee the efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents, including the systems deployed in our technology infrastructure to monitor for threats, perform security control testing and assessments, and incorporate threat intelligence into our day-to-day cybersecurity operations and strategic initiatives. They have decades of experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats.

 Risks that could affect us are an integral part of Cheniere's Board and Audit Committee deliberations throughout the year. Cybersecurity risks are integrated into Cheniere's enterprise risk assessment process, which is reviewed by Cheniere's Board at least annually. Cheniere's Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management's plan for mitigating these risks, while Cheniere's Audit Committee has been delegated the authority to oversee and periodically review the security of Cheniere's information technology systems and controls, including programs and defenses against cybersecurity threats. Cheniere's Audit Committee discusses with Cheniere's management its cybersecurity risk exposures and the steps Cheniere's management has taken to mitigate such exposures, including its risk assessment and risk management policies. On a quarterly basis, Cheniere's cybersecurity leadership team updates Cheniere's Audit Committee on the overall status of its cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity.

 For additional information about cybersecurity risks, see the risk A cyber attack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Project, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors.

 ITEM 3. LEGAL PROCEEDINGS

 We are, and 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.

 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED MEMBER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 Not applicable.

 ITEM 6. [Reserved]

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 Introduction

 The following discussion and analysis presents management's view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Discussion of items for the year ended December 31, 2022 and variance drivers between the year ended December 31, 2023 as compared to December 31, 2022 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, 2023.

 Our discussion and analysis includes the following subjects:
 • Overview
 • Overview of Significant Events
 • Market Environment
 • Results of Operations
 • Liquidity and Capital Resources
 • Summary of Critical Accounting Estimates
 • Recent Accounting Standards

 Overview

 We are a limited liability company formed by Cheniere to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We own the natural gas liquefaction and export facility located near Corpus Christi, Texas. For further discussion of our business, see Items 1. and 2. Business and Properties.

 Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreements currently in effect, with approximately 16 years of weighted average remaining life as of December 31, 2024, we have contracted approximately 90% of the total anticipated production from the Liquefaction Project. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. We believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our business in the future.

 Overview of Significant Events

 Our significant events since January 1, 2024 and through the filing date of this Form 10-K include the following:

 Strategic

 • In June 2024, a positive Environmental Assessment was received from the FERC relating to the Midscale Trains 8 & 9 Project. All remaining necessary regulatory approvals for the project are expected to be received in 2025.

 Operational

 • As of February 14, 2025, approximately 1,090 cumulative LNG cargoes totaling approximately 75 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
 • In December 2024, we achieved first LNG production from Train 1 of the Corpus Christi Stage 3 Project and in February 2025, the first cargo of LNG was produced from the Corpus Christi Stage 3 Project.

 Financial

 • In March 2024, Cheniere issued $1.5 billion aggregate principal amount of 5.650% Senior Notes due 2034 (the "2034 Cheniere Senior Notes"). In April 2024, the net proceeds, together with cash on hand, were used to retire the approximately $1.5 billion outstanding aggregate principal amount of our 5.875% Senior Secured Notes due 2025 (the "2025 CCH Senior Notes").
 • In July 2024, Fitch Ratings ("Fitch") upgraded our issuer credit rating to BBB+ from BBB with a stable outlook.
 • In October 2024, S&P Global Ratings ("S&P") changed the outlook of our senior secured debt rating to positive from stable.

 Market Environment

 The LNG market in 2024 remained relatively tight as a result of low supply capacity growth, strong demand outside Europe and continued geopolitical tensions. Global LNG imports registered a very modest growth in 2024, increasing by less than 4 mtpa year on year due to constrained supply from delays to projects under construction, Russian sanctions and a fallow period for new projects coming on-line. Consequently, a recovery in Asia's LNG consumption had to be satisfied at the expense of other regions. Asian demand increased significantly from 2023, adding over 20 mtpa of import year-over-year. The largest single country contribution to this growth came from China, which increased 6.8 mtpa year-over-year after a slowdown during the previous two years. Growth outside of Asia tightened the balances further this year by increasing the call on supply away from Europe. Egypt and Brazil propelled imports from the Middle East, North Africa and Latin America regions by 6.2 mtpa to a total of 25.5 mtpa in 2024. In contrast, Europe's imports declined 19% year-over-year, down approximately 22.7 mtpa, due to weak gas-fired power generation demand and sluggish growth in the industrial sector.

 These market conditions contributed to a strong spot price environment albeit annual spot prices in 2024 were overall lower than in the previous year. The TTF monthly settlement prices averaged $10.91/MMBtu in 2024, 20.5% lower than the 2023 average of $13.73/MMBtu. Similarly, the average settlement price for the Japan Korea Marker ("JKM") was $11.83/MMBtu in 2024, 26.6% lower than the 2023 average of $16.13/MMBtu. The Henry Hub benchmark also dropped from an average settlement price of $2.74/MMBtu in 2023 to $2.27/MMBtu in 2024, down 17.1% year-over-year.

 However, a drop in temperatures in Europe toward the end of 2024 and into the beginning of 2025 has resulted in faster drawdowns from underground storage and a rebound in spot prices relative to the third quarter. This, along with the expiry of the gas transit agreement between Russia and Ukraine on December 31, 2024, is likely to increase the call on LNG imports in the coming months in order to replenish European gas storage facilities to 90% capacity by November 1, as required by the EU each year.

 Results of Operations

 2024
 2023
 Variance

 Revenues

 LNG revenues
 $
 3,599
 $
 3,845
 $
 (246)

 1,281
 1,620
 (339)

 Total revenues
 4,880
 5,465
 (585)

 Operating costs and expenses (recoveries)

 Cost (recovery) of sales (excluding items shown separately below)
 1,184
 (3,178)
 4,362

 Cost of sales—affiliate
 (75)

 Operating and maintenance expense

 Operating and maintenance expense—affiliate

 Operating and maintenance expense—related party

 General and administrative expense

 General and administrative expense—affiliate
 (1)

 Depreciation and amortization expense

 Other operating costs and expenses

 Total operating costs and expenses (recoveries)
 2,457
 (1,901)
 4,358

 Income from operations
 2,423
 7,366
 (4,943)

 Other income (expense)

 Interest expense, net of capitalized interest
 (65)
 (217)

 Loss on modification or extinguishment of debt
 (3)
 (10)

 Other income, net
 (1)

 Total other expense
 (58)
 (216)

 Net income
 $
 2,365
 $
 7,150
 $
 (4,785)

 Volumes loaded and recognized from the Liquefaction Project

 (in TBtu)
 2024
 2023
 Variance

 Volumes loaded during the current period
 (3)

 Volumes loaded during the prior period but recognized during the current period
 —
 (3)

 Volumes loaded at our affiliate's facility
 —
 (5)

 Total volumes recognized in the current period
 (11)

 Net income

 Net income declined by $4.8 billion during the year ended December 31, 2024 as compared to the same period of 2023 and was primarily attributable to $4.8 billion of decreases in gains from changes in fair value of derivatives. The majority of the decrease was attributable to our IPM agreements where the associated gains that are primarily included in cost of sales decreased from $5.3 billion in 2023 to $1.3 billion in 2024, mainly due to the impact on fair value of the decline and sustained moderation of global LNG and gas price volatility and more subdued changes in the current period relative to the same period of 2023 as global gas prices and spreads narrowed as a result of market rebalancing. The remaining decrease in gains from changes in fair value of derivatives was primarily due to an unfavorable shift in long-term U.S. natural gas forward prices.

 The following is an additional discussion of the significant drivers of the variance in net income by line item:
 Revenues

 The $585 million decrease in revenues during the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to a $485 million decrease from lower pricing per MMBtu as a result of declining Henry Hub

 pricing and a $97 million decrease from lower production volume, primarily due to increased maintenance activities resulting from temporary composition changes in the quality of feed gas received from third parties following a freeze event in the Permian Basin in January 2024.
 Operating costs and expenses (recoveries)

 The increase in operating costs and expenses of $4.4 billion during the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to $4.8 billion of decreases in gains from changes in fair value of derivatives included in cost of sales, as described above under the caption Net income. The unfavorable variance between the comparable years was partially offset by $534 million of decreases in cost of natural gas feedstock, largely due to the decline and sustained moderation of global LNG and gas prices as well as lower U.S. natural gas prices during the year ended December 31, 2024 as compared to the same period of 2023.

 Other income (expense)

 The $158 million favorable variance between the years ended December 31, 2024 and 2023 was primarily attributable to a $152 million decrease in interest expense, net of capitalized interest, due to a $84 million decrease in overall interest costs resulting from debt reduction activities and a $68 million increase in the extent of interest costs qualifying for capitalization, given the higher carrying value of assets under construction.

 Significant factor affecting our results of operations

 Below is a significant factor that affects our results of operations.

 Gains and losses on derivative instruments

 Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements. For commodity derivative instruments, including those related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

 Liquidity and Capital Resources

 The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.

 Restricted cash and cash equivalents designated for the Liquefaction Project

 $

 Available commitments under our credit facilities (1):

 Term loan facility agreement (the "CCH Credit Facility")

 3,260

 Working capital facility agreement (the "CCH Working Capital Facility")

 1,390

 Total available commitments under our credit facilities
 4,650

 Total available liquidity
 $
 4,763

 (1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2024. See Note 9—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, 2024 will be driven by future sources of liquidity and future cash requirements, as further discussed under the caption Future Sources and Uses of Liquidity.

 Supplemental Guarantor Information

 Certain debt obligations of CCH (the "Guaranteed Obligations"), consisting of the 5.125% Senior Secured Notes due 2027, 3.700% Senior Secured Notes due 2029 and the series of Senior Secured Notes due 2039 with weighted average rate of 3.788% (collectively, the "Senior Secured Notes"), are jointly and severally guaranteed by each of our consolidated subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a "Guarantor" and collectively, the "Guarantors").

 The Guarantors' guarantees of such obligations 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 a Guarantor as an "unrestricted subsidiary" in accordance with the indentures governing the respective debt instruments (the "CCH Indentures"), (3) 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 CCH, whether at maturity of the respective debt instrument or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the Guarantors to enforce the guarantee.

 The Guaranteed Obligations contain affirmative and negative covenants that are customary for the respective debt instrument, including, with limited exceptions, restrictions on CCH's and the CCH Guarantors' ability to incur additional indebtedness and/or liens, enter into hedging arrangements and/or engage in transactions with affiliates. The Guaranteed Obligations also include events of default that are customary for the respective debt instrument, which are subject to customary grace periods and materiality standards.

 The rights of holders of the Guaranteed Obligations 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.

 The Guaranteed Obligations are CCH's senior secured obligations, ranking senior in right of payment to any and all of CCH's future indebtedness that is subordinated to the Guaranteed Obligations and equal in right of payment with CCH's other existing and future indebtedness that is senior and secured by the same collateral securing the Guaranteed Obligations. The obligations of CCH under the Guaranteed Obligations are secured by substantially all of the assets of CCH and the Guarantors, as well as by all membership interests in CCH and each of the Guarantors on a pari passu basis with the CCH Credit Facility and the CCH Working Capital Facility.
 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.

 Future Sources and Uses of Liquidity

 The following discussion of our future sources and uses of liquidity includes estimates that reflect management's assumptions and currently known market conditions and other factors as of December 31, 2024. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.

 Future Sources of Liquidity under Executed Contracts

 We are contractually entitled to significant future consideration contracted under our long-term SPAs that has not yet been recognized as revenue. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be significant to our future liquidity. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We have estimated revenues under agreements with terms dependent on project milestone dates based on the estimated dates as of December 31, 2024. The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2024 (in billions):

 Estimated Revenues Under Executed SPAs by Period (1) (2)

 2025
 2026 - 2029

 Thereafter
 Total

 LNG revenues (fixed fees)
 $
 2.1
 $
 11.9
 $
 34.4
 $
 48.4

 LNG revenues (variable fees) (3)
 2.8
 16.0
 53.8
 72.6

 Total
 $
 4.9
 $
 27.9
 $
 88.2
 $
 121.0

 (1)LNG revenues exclude revenues from contracts with original expected durations of one year or less. LNG revenues also exclude volumes produced from the commissioning of certain Corpus Christi Stage 3 Project Trains, as volumes related to commissioning are not recognized as revenues. We recognize proceeds from commissioning activities prior to the start of commercial operations as offsets to LNG terminal costs as a component of the testing phase of a Train's construction.
 (2)LNG revenues (including $0.9 billion and $1.6 billion of fixed fees and variable fees, respectively, from affiliates) exclude SPAs with Cheniere Marketing associated with IPM agreements, for which pricing is linked to international natural gas prices.
 (3)LNG revenues (variable fees) reflect the assumption of delivery of all contractual volumes, irrespective of any contractual right of non-delivery. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2024.

 Under our long-term SPAs, we have contracted approximately 90% of the total anticipated production through the mid-2030s from our liquefaction capacity that is currently in construction or operation. Under our SPAs, customers purchase LNG on either an FOB basis (delivered to the customer at the Corpus Christi LNG Terminal) or a DAT basis (delivered to the customer at their specified LNG receiving terminal) generally for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The variable fees under our SPAs were generally sized with the intention to cover the supply and transportation of natural gas and the liquefaction fuel consumed to produce the LNG to be sold under each such SPA, thus limiting our exposure to future U.S. natural gas price increases. 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 table above excludes SPAs with Cheniere Marketing under which we sell LNG produced from natural gas procured under our IPM agreements in effect at pricing linked to global gas market prices. The IPM agreements in effect, under which we pay for natural gas feedstock based on global gas prices less liquefaction fees and certain costs incurred by us, generates a take-or-pay style fixed liquefaction fee when viewed in conjunction with the associated SPAs. Over a remaining fixed term of 18 years, we expect to generate liquidity from the approximately 3,250 TBtu of LNG yet to be delivered under these SPAs as of December 31, 2024.
 Additional Future Sources of Liquidity

 Available Commitments under Credit Facilities

 As of December 31, 2024, we had $4.7 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, based on estimated project milestone dates as of December 31, 2024.

 Disciplined Accretive 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 June 2024, we received a positive Environmental Assessment from the FERC relating to the CCL Midscale Trains 8 & 9 Project, and we expect to receive all remaining necessary regulatory approvals for the project in 2025. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before a positive FID is made.

 Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts

 We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 2024 (in billions):

 Estimated Payments Due Under Executed Contracts by Period (1)

 2025
 2026 - 2029

 Thereafter
 Total

 Purchase obligations (2):

 Natural gas supply agreements excluding IPM agreements (3) (4)
 $
 2.5
 $
 8.0
 $
 5.2
 $
 15.7

 Natural gas transportation and storage service agreements (5)
 0.3
 1.1
 2.5
 3.9

 Capital expenditures
 1.3
 0.6
 —
 1.9

 Shipping and transportation-related services agreements (6)
 —
 1.2
 5.3
 6.5

 Other purchase obligations (7)
 0.1
 0.2
 1.2
 1.5

 Total
 $
 4.2
 $
 11.1
 $
 14.2
 $
 29.5

 (1)Agreements in force as of December 31, 2024 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2024.
 (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.
 (3)Natural gas supply agreements exclude IPM agreements, which, as described in Future Sources of Liquidity under Executed Contracts, are structured to generate a fixed margin when viewed in conjunction with the associated SPAs with Cheniere Marketing.
 (4)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2024. Natural gas supply agreements are presented net of $0.3 billion in contracted sales of natural gas as of December 31, 2024.
 (5)Natural gas transportation and storage services agreements include $1.0 billion in obligations to related parties.

 (6)Shipping and transportation-related services agreements are between CCL and Cheniere Marketing.
 (7)Other purchase obligations include $1.1 billion of purchase obligations to affiliates under services agreements.

 Natural Gas Supply, Transportation and Storage Service Agreements

 Excluding IPM agreements and unexercised extension options, we have secured approximately 4,080 TBtu of natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements with remaining fixed terms of up to 15 years. As of December 31, 2024, we have secured approximately 77% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2025, excluding the 11% of which has been secured under IPM agreements. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2025. As further described in the Future Sources of Liquidity under Executed Contracts section, the pricing structure of our SPAs often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.

 To ensure that we are able to transport natural gas feedstock to the Liquefaction Project, we have transportation precedent and other agreements to secure firm pipeline transportation capacity from CCP and other interstate and intrastate pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project.

 Capital Expenditures

 We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Project. The future capital expenditures included in the table above primarily consist of fixed costs under the Bechtel EPC contract for the Corpus Christi Stage 3 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity.

 Corpus Christi Stage 3 Project

 The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2024:

 Overall project completion percentage
 77.2%

 Completion percentage of:

 Engineering
 97.2%

 Procurement
 97.2%

 Subcontract work
 88.2%

 Construction
 42.6%

 Date of expected substantial completion
 1H 2025 - 2H 2026

 Additional Future Cash Requirements for Operations and Capital Expenditures

 Operational Services

 We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. As of December 31, 2024, Cheniere and its subsidiaries had 1,714 full-time employees, including 505 employees who directly supported the Liquefaction Project.

 Disciplined Accretive 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, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.

 Future Cash Requirements for Financing under Executed Contracts

 We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2024 (in billions):

 Estimated Payments Due Under Executed Contracts by Period (1)

 2025
 2026 - 2029

 Thereafter
 Total

 Debt
 $
 —
 $
 2.7
 $
 2.2
 $
 4.9

 Interest payments
 0.2
 0.7
 0.5
 1.4

 Total
 $
 0.2
 $
 3.4
 $
 2.7
 $
 6.3

 (1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2024. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.

 Debt

 As of December 31, 2024, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $4.9 billion and credit facilities with no outstanding loan balances. As of December 31, 2024, 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 9—Debt of our Notes to Consolidated Financial Statements.

 Interest

 As of December 31, 2024, our senior notes had a weighted average contractual interest rate of 4.10%. Borrowings under our credit facilities are indexed to SOFR. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.10% and 0.525%, subject to change based on our credit rating. Issued letters of credit under the CCH Working Capital Facility are subject to letter of credit fees ranging from 1.0% to 1.5%. We had $110 million aggregate amount of issued letters of credit under the CCH Working Capital Facility as of December 31, 2024.

 Additional Future Cash Requirements for Financing

 Capital Allocation Plan

 In June 2024, the board of directors of Cheniere approved an updated comprehensive long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including our senior notes.

 Sources and Uses of Cash

 The following table summarizes the sources and uses of our restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.

 2024
 2023

 Net cash provided by operating activities
 $
 1,771
 $
 1,765

 Net cash used in investing activities
 (1,830)
 (1,722)

 Net cash used in financing activities
 (3)
 (606)

 Net decrease in restricted cash and cash equivalents
 $
 (62)
 $
 (563)

 Operating Cash Flows

 The $6 million increase between the periods was primarily related to cash flows attributed to working capital, mainly due to differences in timing of payments to suppliers and cash collections from the sale of LNG cargoes.

 Investing Cash Flows

 Our investing net cash outflows in both periods primarily were for construction costs for the Corpus Christi Stage 3 Project, which were $1.5 billion during both the years ended December 31, 2024 and 2023, as well as for optimization and other site improvement projects. We expect to incur a proportional level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project.
 Financing Cash Flows

 The following table summarizes our financing activities (in millions):

 2024
 2023

 Repayments and repurchases of debt
 $
 —
 $
 (498)

 Contributions

 (400)
 (280)

 Other
 (18)
 (8)

 Net cash used in financing activities

 $
 (3)
 $
 (606)

 Repayments of Debt
 During the year ended December 31, 2023, we redeemed with cash on hand the remaining $498 million outstanding principal amount of our 7.000% Senior Secured Notes due 2024.

 Summary of Critical Accounting Estimates

 The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

 Fair Value of Level 3 Liquefaction Supply Derivatives

 All of our derivative instruments are recorded at fair value, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. We record changes in the fair value of our derivative positions through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. Valuation of our liquefaction supply derivative contracts is often developed through the use of internal models which includes significant unobservable inputs representing Level 3 fair value measurements as further described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.

 Our fair value estimates incorporate market participant-based assumptions pertaining to applicable contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.

 Additionally, the valuation of certain 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, 2024 and 2023 (in millions), which entirely consisted of liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.

 2024
 2023

 Favorable changes in fair value relating to instruments still held at the end of the period

 $
 $
 4,382

 The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our IPM agreements in effect during the years ended December 31, 2024 and 2023.
 The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2024 and 2023 amounted to an asset of $506 million and a liability of $502 million, respectively.

 The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as it relates to commodity prices impacting the valuation of our liquefaction supply derivatives, given the level of volatility to which such prices are subjected. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.

 Recent Accounting Standards

 For a summary of recently issued accounting standards, see Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.

 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 Marketing and Trading Commodity Price Risk

 We have commodity derivatives consisting of natural gas and power supply contracts for the commissioning and operation of the Liquefaction Project and Midscale Trains 8 & 9 Project, as well as the associated economic hedges (collectively, the "Liquefaction Supply Derivatives"). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):

 Fair Value
 Change in Fair Value
 Fair Value
 Change in Fair Value

 Liquefaction Supply Derivatives

 $
 $
 2,174
 $
 (460)
 $
 1,165

 See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.

 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 Management's Report to the Member of Cheniere Corpus Christi Holdings, LLC

 Report of Independent Registered Public Accounting Firm

 Consolidated Statements of Operations

 Consolidated Balance Sheets

 Consolidated Statements of Member's Equity

 Consolidated Statements of Cash Flows

 Notes to Consolidated Financial Statements

 Note 1—Organization and Nature of Operations

 Note 2—Summary of Significant Accounting Policies

 Note 3—Trade and Other Receivables, Net of Current Expected Credit Losses

 Note 4—Inventory

 Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation

 Note 6—Derivative Instruments

 Note 7—Other Non-current Assets, Net

 Note 8—Accrued Liabilities

 Note 9—Debt

 Note 10—Revenues

 Note 11—Related Party Transactions

 Note 12—Commitments and Contingencies

 Note 13—Segment Information and Customer Concentration

 Note 14—Supplemental Cash Flow Information

 MANAGEMENT'S REPORT TO THE MEMBER OF CHENIERE CORPUS CHRISTI HOLDINGS, LLC

 Management's Report on Internal Control Over Financial Reporting

 As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for 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 GAAP. 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, 2024, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.

 This annual report does not include an attestation report of Corpus Christi Holdings' registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by Corpus Christi Holdings' registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management's report in this annual report.

 Management's Certifications

 The certifications of Corpus Christi Holdings' Principal Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere Corpus Christi Holdings' Form 10-K.

 By:
 /s/ Zach Davis

 Zach Davis

 President and Chief Financial Officer
(Principal Executive and Financial Officer)

 Report of Independent Registered Public Accounting Firm

 To the Member and Managers of Cheniere Corpus Christi Holdings, LLC
 Cheniere Corpus Christi Holdings, LLC:
 Opinion on the Consolidated Financial Statements
 We have audited the accompanying consolidated balance sheets of Cheniere Corpus Christi Holdings, LLC and subsidiaries (the Company) as of December 31, 2024 and 2023, 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, 2024, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.
 Basis for Opinion
 These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
 Critical Audit Matter
 The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 Fair value of the level 3 liquefaction supply derivatives
 As discussed in Notes 2 and 6 to the consolidated financial statements, the Company recorded fair value of level 3 liquefaction supply derivatives of $506 million as of December 31, 2024, which included the fair value of IPM agreements. The IPM agreements are natural gas supply contracts for the operation of the liquefied natural gas facilities. The fair value of the IPM agreements is developed using internal models, including option pricing models. The models incorporate significant unobservable inputs, including future prices of energy units in unobservable periods and volatility.
 We identified the evaluation of the fair value of the level 3 liquefaction supply derivatives for certain IPM agreements as a critical audit matter. Specifically, complex auditor judgment and specialized skills and knowledge were required to evaluate the appropriateness and application of the option pricing model as well as the assumptions for future prices of energy units in unobservable periods and volatility.
 The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of liquefaction supply derivatives,

 including those under certain IPM agreements. This included controls related to the appropriateness and application of the option pricing model and the evaluation of assumptions for future prices of energy units in unobservable periods and volatility. We involved valuation professionals with specialized skills and knowledge who assisted in testing management's process for developing the fair value of certain IPM agreements by:
 • evaluating the design and testing the operating effectiveness of certain internal controls related to the appropriateness and application of the option pricing model
 • evaluating the appropriateness and application of the option pricing model by inspecting the contractual agreements and model documentation to determine whether the model is suitable for its intended use
 • evaluating the reasonableness of management's assumptions for future prices of energy units in unobservable periods and volatility by comparing to market data.

 /s/ KPMG LLP

 KPMG LLP

 We have served as the Company's auditor since 2015.

 Houston, Texas
 February 19, 2025

 CHENIERE CORPUS CHRISTI HOLDINGS, LLC
 CONSOLIDATED STATEMENTS OF OPERATIONS

 2024
 2023
 2022

 Revenues

 LNG revenues
 $
 3,599
 $
 3,845
 $
 6,336

 1,281
 1,620
 3,027

 Total revenues
 4,880
 5,465
 9,363

 Operating costs and expenses (recoveries)

 Cost (recovery) of sales (excluding items shown separately below)
 1,184
 ( 3,178)
 9,656

 Cost of sales—affiliate

 Operating and maintenance expense

 Operating and maintenance expense—affiliate

 Operating and maintenance expense—related party

 General and administrative expense

 General and administrative expense—affiliate

 Depreciation and amortization expense

 Other operating costs and expenses

 Total operating costs and expenses (recoveries)
 2,457
 ( 1,901)
 10,844

 Income (loss) from operations
 2,423
 7,366
 ( 1,481)

 Other income (expense)

 Interest expense, net of capitalized interest
 ( 65)
 ( 217)
 ( 432)

 Loss on modification or extinguishment of debt
 ( 3)
 ( 10)
 ( 37)

 Other income, net

 Total other expense
 ( 58)
 ( 216)
 ( 461)

 Net income (loss)
 $
 2,365
 $
 7,150
 $
 ( 1,942)

 The accompanying notes are an integral part of these consolidated financial statements.

 CONSOLIDATED BALANCE SHEETS

 2024
 2023

 ASSETS

 Current assets

 Restricted cash and cash equivalents
 $
 $

 Trade and other receivables, net of current expected credit losses

 Trade receivables—affiliate

 Advances to affiliates

 Inventory

 Current derivative assets

 Other current assets, net

 Total current assets

 Property, plant and equipment, net of accumulated depreciation
 16,254
 14,992

 Derivative assets
 1,805

 Other non-current assets, net

 Total assets
 $
 19,334
 $
 16,976

 LIABILITIES AND MEMBER'S EQUITY

 Current liabilities

 Accounts payable
 $
 $

 Accrued liabilities

 Accrued liabilities—related party

 Due to affiliates

 Current derivative liabilities

 Other current liabilities

 Other current liabilities—affiliate
 —

 Total current liabilities
 1,350
 1,225

 Long-term debt, net of unamortized discount and debt issuance costs
 4,830
 6,311

 Derivative liabilities

 Other non-current liabilities

 Other non-current liabilities—affiliate

 Total liabilities
 6,874
 8,444

 Commitments and contingencies (see Note 14)

 Member's equity

 12,460
 8,532

 Total liabilities and member's equity

 $
 19,334
 $
 16,976

 The accompanying notes are an integral part of these consolidated financial statements.

 CONSOLIDATED STATEMENTS OF MEMBER'S EQUITY

 Cheniere CCH HoldCo I, LLC
 Total Member's Equity

 Balance at December 31, 2021
 $
 1,281
 $
 1,281

 Contributions (excluding items shown separately below)

 2,182
 2,182

 Non-cash contribution of CCL Stage III entity from affiliate (see Note 14)

 ( 1,482)
 ( 1,482)

 Other non-cash contribution from affiliate (see Note 9)

 1,245
 1,245

 ( 200)
 ( 200)

 Net loss
 ( 1,942)
 ( 1,942)

 Balance at December 31, 2022
 1,084
 1,084

 Contributions (excluding item shown separately below)

 Non-cash contribution from affiliate (see Note 9)

 ( 280)
 ( 280)

 Net income
 7,150
 7,150

 Balance at December 31, 2023
 8,532
 8,532

 Contributions (excluding the item shown separately below)

 Non-cash contribution from affiliate (see Note 9)

 1,514
 1,514

 Non-cash asset contribution from Cheniere (see Note 11)

 ( 400)
 ( 400)

 Net income
 2,365
 2,365

 Balance at December 31, 2024
 $
 12,460
 $
 12,460

 The accompanying notes are an integral part of these consolidated financial statements.

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2024
 2023
 2022

 Cash flows from operating activities

 Net income (loss)
 $
 2,365
 $
 7,150
 $
 ( 1,942)

 Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 Depreciation and amortization expense

 Amortization of discount and debt issuance costs

 Loss on modification or extinguishment of debt

 Total losses (gains) on derivative instruments, net

 ( 985)
 ( 5,825)
 3,243

 Net cash provided by (used for) settlement of derivative instruments

 ( 14)
 ( 155)

 Interest expense relieved by parent

 Other

 Changes in operating assets and liabilities:

 Trade and other receivables
 ( 13)
 ( 68)

 Trade receivables—affiliate

 Inventory
 ( 9)
 ( 22)

 Other current assets
 ( 3)
 ( 65)

 Accounts payable and accrued liabilities
 ( 37)
 ( 347)

 Accrued liabilities—related party
 —
 —

 Total deferred revenue
 ( 18)
 ( 1)

 Other non-current assets
 ( 39)
 ( 39)
 ( 41)

 Other, net
 ( 2)
 ( 2)
 ( 1)

 Other, net—affiliate
 ( 52)

 Net cash provided by operating activities

 1,771
 1,765
 1,734

 Cash flows from investing activities

 Property, plant and equipment, net
 ( 1,810)
 ( 1,711)
 ( 981)

 Other
 ( 20)
 ( 11)

 Net cash used in investing activities

 ( 1,830)
 ( 1,722)
 ( 980)

 Cash flows from financing activities

 Proceeds from issuances of debt
 —
 —

 Repayments and repurchases of debt
 —
 ( 498)
 ( 2,419)

 Contributions
 2,182

 ( 400)
 ( 280)
 ( 200)

 Other
 ( 18)
 ( 8)
 ( 63)

 Net cash used in financing activities

 ( 3)
 ( 606)
 ( 60)

 Net increase (decrease) in restricted cash and cash equivalents

 ( 62)
 ( 563)

 Restricted cash and cash equivalents—beginning of period

 Restricted cash and cash equivalents—end of period
 $
 $
 $

 The accompanying notes are an integral part of these consolidated financial statements.

 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 NOTE 1— ORGANIZATION AND NATURE OF OPERATIONS

 We operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the "Corpus Christi LNG Terminal") through CCL, which has three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks and two marine berths. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the "Corpus Christi Stage 3 Project") consisting of seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG.

 Through our subsidiary CCP, we also own an approximately 21 -mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the "Corpus Christi Pipeline" and together with the existing assets at the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the "Liquefaction Project").

 We are pursuing an expansion project to provide additional liquefaction capacity, and we have commenced commercialization to support the additional liquefaction capacity associated with this potential expansion project. The development of this project or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

 We do not have employees and thus we have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. See Note 11—Related Party Transactions for additional details of the activity under these services agreements during the years ended December 31, 2024, 2023 and 2022.

 We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

 NOTE 2— SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 Basis of Presentation

 Our Consolidated Financial Statements have been prepared in accordance with GAAP. Our Consolidated Financial Statements include the accounts of CCH and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

 Estimates

 The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment and certain valuations including asset retirement obligations ("AROs"), each as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

 Fair Value Measurements

 Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.

 In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management's judgment, market participants would take into account in measuring fair value. We attempt to maximize our use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

 Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 6—Derivative Instruments.

 The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Refer to Note 9—Debt for our debt fair value estimates, including our estimation methods.

 Revenue Recognition

 Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer based on the delivery terms, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer, and consists of either an FOB or DAT basis. Each individual molecule of LNG is viewed as a separate performance obligation. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is not included in the transaction price.
 Sales generated during the commissioning phase of a Train, which includes test activities such as production and removal of LNG from storage, are offset against the cost of construction for the respective Train, as commissioning is necessary to test the facility and bring the asset to the condition necessary for its intended use. After substantial completion of a Train is achieved, fees received for LNG volumes produced are recognized as LNG revenues.

 For transactions where we receive consideration from the customer, we assess whether we are the principal or the agent in the arrangement. Arrangements where we have concluded that we act as a principal are presented within our Consolidated Statements of Operations on a gross basis, and arrangements where we have concluded that we act as an agent are presented within our Consolidated Statements of Operations on a net basis.

 See Note 10—Revenues for additional information regarding our LNG revenues.

 Restricted Cash and Cash Equivalents

 Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Our restricted cash and cash equivalents were primarily restricted for the payment of liabilities related to the Liquefaction Project as required under certain debt arrangements. 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.

 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 contract and payment terms, the counterparty's established credit rating and credit worthiness and other risks or available financial assurances. We calculate the allowance for credit losses under a probability of default method applied to pools of assets with similar risk characteristics, and reflect credit enhancements such as letters of credit and guarantees to the extent that such enhancements are contractually linked to the underlying asset and with the same counterparty. Quarterly, we evaluate whether

 our method continues to be appropriate based on historical collections and additional information as it becomes available and adjust our reserve as necessary. We record charges and reversals of current expected credit losses in our Consolidated Statements of Operations within the line item that corresponds to the nature of the underlying asset, primarily general and administrative expense.

 The following table reflects the changes in our current expected credit losses (in millions):

 2024
 2023
 2022

 Current expected credit losses, beginning of period

 $
 $
 $

 Charges (reversals), net
 —
 ( 1)

 Current expected credit losses, end of period

 $
 $
 $

 Inventory

 LNG, natural gas and other commodity inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or, for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.

 Property, Plant and Equipment

 Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities and costs that significantly extend the useful life or increase the functionality and/or capacity of an asset are capitalized. 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 LNG terminal construction 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.

 Generally, costs that benefit us more broadly than for a specific project are capitalized prior to a project meeting the criteria otherwise necessary for capitalization and typically include land and land acquisition costs and engineering design work.

 We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

 We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives, except land which is not depreciated. Refer to Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses.

 Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.

 We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2024, 2023 and 2022.

 Interest Capitalization

 We capitalize interest costs mainly during the construction period of our LNG terminal and related assets. Upon placing the underlying asset in service, these costs are depreciated over the estimated useful life of the corresponding assets for which interest costs were incurred, except for capitalized interest associated with land, which is not depreciated.

 Derivative Instruments

 We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement.

 We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2024, 2023 and 2022; therefore, the changes in the fair value of our derivative instruments are recorded in earnings.

 As described in Concentration of Credit Risk below, the use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty's nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees. Variation margins or other daily margining posted for exchange-traded transactions that are contractually characterized as settlement of the respective derivative position are netted against the respective derivative asset or liability positions.

 We have elected to report derivative assets and liabilities under master netting arrangements with the same counterparty on a net basis. Additionally, the fair value amounts recognized as cash collateral pledged or received, such as initial margins and other collateral that are not contractually characterized as settlement of the respective derivative positions, are offset against the fair value of derivatives executed with the same counterparty under a master netting arrangement. Collateral balances not offset against a derivative position are presented on our Consolidated Balance Sheets within other current assets, net. Derivative assets and liabilities not subject to master netting arrangements are presented net when we have a legally enforceable right and the intent to offset amounts with the same counterparty.

 See Note 6—Derivative Instruments for additional details about our derivative instruments.

 Concentration of Credit Risk

 Financial instruments that potentially subject us to a concentration of credit risk consist principally of (1) derivative instruments and (2) accounts receivable and contract assets related to our long-term SPAs, each discussed further above. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.

 The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivatives executed over-the-counter or through an exchange are subject to nominal credit risk as these transactions often require collateral that is returned to us (or to the counterparty) on or near the settlement date or are settled on a daily margin basis with investment grade financial institutions and are 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 for non-exchange traded transactions when the value of a derivative exceeds the pre-established credit limit with the counterparty. 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.

 Our contracted LNG sales are primarily under SPAs with terms exceeding 10 years. As of December 31, 2024, CCL had SPAs with initial terms of 10 or more years with a total of 15 third parties and had agreements with Cheniere Marketing International LLP ("Cheniere Marketing"). CCL is dependent on the respective customers' creditworthiness and their ability to perform under their respective agreements. While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

 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 commitment fees. Costs associated with entering into a line of credit or on undrawn funds are presented as an asset and classified as current or non-current, consistent with the respective credit facility. As of December 31, 2024 and 2023, all of such costs were classified as other non-current assets, net, 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 except in the case of our credit facilities, in which discounts, premiums and debt issuance costs are amortized on a straight-line basis over the contractual term.

 We classify debt on our Consolidated Balance Sheets based on contractual maturity, with the following exceptions:
 • We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.
 • We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.

 Asset Retirement Obligations

 We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

 Our Corpus Christi Pipeline is subject to regulations by the FERC for proper abandonment of a pipeline, including the disconnection of the pipeline from all sources and supplies of gas and other decommissioning costs. 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. For these reasons, we have not recorded an ARO associated with the Corpus Christi Pipeline.

 Recent Accounting Standards

 ASU 2023-07

 In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280), which we adopted on December 31, 2024. This guidance requires a public entity, including entities with a single reportable segment, to disclose significant segment expenses and other segment information on an annual and interim basis and provide in interim periods all

 disclosures about a reportable segment's profit or loss and assets that are currently required annually. Refer to Note 13—Segment Information and Customer Concentration for the required disclosures.

 ASU 2024-03

 In November 2024, the FASB issued ASU No. 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, as clarified by ASU No. 2025-01 in January 2025. This guidance requires disaggregated disclosures about certain income statement expense line items on an annual and interim basis. We continue to evaluate the impact of the provisions of this guidance on our disclosures, but plan to adopt this guidance prospectively and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2027.

 NOTE 3— 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):

 2024
 2023

 Trade receivables
 $
 $

 Other receivables

 Total trade and other receivables, net of current expected credit losses
 $
 $

 NOTE 4— INVENTORY

 Inventory consisted of the following (in millions):

 2024
 2023

 Materials
 $
 $

 LNG

 Natural gas

 Other

 Total inventory
 $
 $

 NOTE 5— PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

 Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

 2024
 2023

 LNG terminal

 Terminal and interconnecting pipeline facilities
 $
 13,406
 $
 13,333

 Land

 Construction-in-process
 4,846
 3,207

 Accumulated depreciation
 ( 2,306)
 ( 1,858)

 Total LNG terminal, net of accumulated depreciation
 16,248
 14,984

 Fixed assets

 Fixed assets

 Accumulated depreciation
 ( 22)
 ( 22)

 Total fixed assets, net of accumulated depreciation

 Property, plant and equipment, net of accumulated depreciation
 $
 16,254
 $
 14,992

 Depreciation expense was $ 455 million, $ 448 million and $ 444 million during the years ended December 31, 2024, 2023 and 2022, respectively.

 LNG Terminal Costs

 LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and 50 years, as follows:

 Components
 Useful life (years)

 LNG storage tanks

 Natural gas pipeline facilities

 Marine berth, electrical, facility and roads

 Water pipelines

 Liquefaction processing equipment
 6 - 50

 Other
 10 - 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 6— DERIVATIVE INSTRUMENTS

 We have 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 and expansion project, as well as the associated economic hedges (collectively, the "Liquefaction Supply Derivatives").

 The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis, distinguished by the fair value hierarchy levels prescribed by GAAP (in millions):

 Fair Value Measurements as of

 Quoted Prices in Active Markets
(Level 1)
 Significant Other Observable Inputs
(Level 2)
 Significant Unobservable Inputs
(Level 3)
 Total
 Quoted Prices in Active Markets
(Level 1)
 Significant Other Observable Inputs
(Level 2)
 Significant Unobservable Inputs
(Level 3)
 Total

 Liquefaction Supply Derivatives asset (liability)

 $
 —
 $
 $
 $
 $
 $
 $
 ( 502)
 $
 ( 460)

 We value the Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, which incorporates observable commodity price curves, when available, and other relevant data.

 We include a significant portion of the Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.

 In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market

 participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. Our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

 The Level 3 fair value measurements of our natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of December 31, 2024:

 Net Fair Value Asset

 Valuation Approach
 Significant Unobservable Input
 Range of Significant Unobservable Inputs / Weighted Average (1)

 Liquefaction Supply Derivatives
 $ 506
 Market approach incorporating present value techniques
 Henry Hub basis spread

 $( 2.005) - $ 0.557 / $( 0.209)

 Option pricing model
 International LNG pricing spread, relative to Henry Hub (2)

 91 % - 410 % / 195 %

 (1) Unobservable inputs were weighted by the relative fair value of the instruments.
 (2) Spread contemplates U.S. dollar-denominated pricing.

 Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of the Liquefaction Supply Derivatives.

 The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):

 2024
 2023

 2022

 Balance, beginning of period
 $
 ( 502)
 $
 ( 6,205)
 $
 ( 1,221)

 Realized and change in fair value gains (losses) included in net income (loss) (1):

 Included in cost of sales, existing deals (2)
 4,383
 ( 1,492)

 Included in cost of sales, new deals (3)
 ( 1)
 ( 2,172)

 Purchases and settlements:

 Purchases (4)
 —
 —
 ( 1,938)

 Settlements (5)
 1,321

 Transfers out of level 3 (6)
 —
 —
 —

 Balance, end of period
 $
 $
 ( 502)
 $
 ( 6,205)

 Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period

 $
 $
 4,382
 $
 ( 3,664)

 (1) Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.
 (2) Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
 (3) Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
 (4) Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period.
 (5) Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.
 (6) Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

 Liquefaction Supply Derivatives

 We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of December 31, 2024, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence or accelerate upon the satisfaction of certain events or development of infrastructure to support natural gas gathering and transport.

 The forward notional amount for the Liquefaction Supply Derivatives was approximately 7,003 TBtu and 7,774 TBtu as of December 31, 2024 and 2023, respectively, inclusive of amounts under contracts with unsatisfied contractual conditions, and exclusive of extension options that were uncertain to be taken as of both December 31, 2024 and 2023.
 The following table shows the effect and location of the Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations (in millions):

 Gain (Loss) Recognized in Consolidated
 Statements of Operations

 Consolidated Statements of Operations Location (1)

 2024
 2023
 2022

 LNG revenues
 $
 ( 3)
 $
 ( 5)
 $

 Cost (recovery) of sales
 5,830
 ( 3,246)

 (1) Does not include the realized value associated with the Liquefaction Supply Derivatives that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

 The following table shows the fair value and location of the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):

 Fair Value Measurements as of

 Consolidated Balance Sheets Location

 Current derivative assets
 $
 $

 Derivative assets
 1,805

 Total derivative assets
 1,826

 Current derivative liabilities
 ( 635)
 ( 455)

 Derivative liabilities
 ( 652)
 ( 847)

 Total derivative liabilities
 ( 1,287)
 ( 1,302)

 Derivative asset (liability), net
 $
 $
 ( 460)

 Consolidated Balance Sheets Presentation

 The following table reconciles the fair value of our derivative assets and liabilities on a gross basis, by contract, to net amounts as presented on our Consolidated Balance Sheets after offsetting for any balances with the same counterparty under master netting arrangements or other relevant netting criteria under GAAP that are met (in millions):

 Liquefaction Supply Derivatives

 Gross assets
 $
 2,836
 $
 1,184

 Offsetting amounts
 ( 1,010)
 ( 342)

 Net assets
 $
 1,826
 $

 Gross liabilities
 $
 ( 1,326)
 $
 ( 1,349)

 Offsetting amounts

 Net liabilities
 $
 ( 1,287)
 $
 ( 1,302)

 We had collateral balances that were recorded within other current assets, net, and not netted on our Consolidated Balance Sheets, of $ 5 million and $ 3 million as of December 31, 2024 and 2023, respectively.

 NOTE 7— OTHER NON-CURRENT ASSETS, NET

 Other non-current assets, net consisted of the following (in millions):

 2024
 2023

 Contract assets, net of current expected credit losses
 $
 $

 Advances to service providers

 Debt issuance costs and deferred commitment fees, net of accumulated amortization

 Other

 Total other non-current assets, net
 $
 $

 NOTE 8— ACCRUED LIABILITIES

 Accrued liabilities consisted of the following (in millions):

 2024
 2023

 Natural gas purchases
 $
 $

 Liquefaction Project costs

 Interest costs and related debt fees

 Other accrued liabilities

 Total accrued liabilities
 $
 $

 NOTE 9— DEBT

 Debt consisted of the following (in millions):

 2024
 2023

 Senior Secured Notes:

 5.875 % due 2025 (the "2025 CCH Senior Notes")

 $
 —
 $
 1,491

 5.125 % due 2027

 1,201
 1,201

 3.700 % due 2029

 1,125
 1,125

 3.788 % weighted average rate due 2039 (1)

 2,539
 2,539

 Total Senior Secured Notes
 4,865
 6,356

 Term loan facility agreement (the "CCH Credit Facility")

 —
 —

 Working capital facility agreement (the "CCH Working Capital Facility")

 —
 —

 Total debt
 4,865
 6,356

 Unamortized discount and debt issuance costs
 ( 35)
 ( 45)

 Total long-term debt, net of unamortized discount and debt issuance costs
 $
 4,830
 $
 6,311

 (1) Includes notes that amortize based on a fixed amortization schedule as set forth in their respective indentures.

 Senior Secured Notes
 The Senior Secured Notes, are jointly and severally guaranteed by our subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a "CCH Guarantor" and collectively, the "CCH Guarantors"). The Senior Secured Notes are our senior secured obligations, ranking senior in right of payment to any and all of our future indebtedness that is subordinated to the Senior Secured Notes and equal in right of payment with our other existing and future indebtedness that is senior and secured by the same collateral securing the Senior Secured Notes. The Senior Secured Notes are secured by a first-priority security interest in substantially all of our and the CCH Guarantors' assets. We may, at any time, redeem all or part of the Senior Secured Notes at specified prices set forth in the respective indentures governing the Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. The series of Senior Secured Notes due in 2039 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.

 Contributions from Cheniere for Extinguishment of Senior Secured Notes

 During the year ended December 31, 2024, Cheniere fully retired $ 1.5 billion outstanding aggregate principal amount of our 2025 CCH Senior Notes. During the year ended December 31, 2023, Cheniere repurchased $ 400 million of certain series of our Senior Secured Notes on the open market, which were subsequently cancelled by us. Additionally, Cheniere paid interest on our behalf that was due at the time of the respective debt repayments of $ 23 million and $ 2 million during the years ended December 31, 2024 and 2023, respectively. Additionally, we recorded a non-cash charge through equity of $ 4 million during the year ended December 31, 2023 associated with the debt extinguishments.

 The aforementioned debt extinguishment activities by Cheniere on our behalf were in accordance with the Equity Contribution Agreements, as noted in Note 11—Related Party Transactions, and recorded as net contributions from Cheniere to us, for which we paid no consideration, within our Consolidated Statements of Member's Equity.

 Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2024 (in millions):

 Years Ending December 31,
 Principal Payments

 2025
 $
 —

 2026
 —

 2027
 1,277

 2028

 2029
 1,299

 Thereafter
 2,166

 Total
 $
 4,865

 Credit Facilities

 Below is a summary of our credit facilities outstanding as of December 31, 2024 (in millions):

 CCH Credit Facility (1)

 CCH Working Capital Facility (2)

 Total facility size
 $
 3,260
 $
 1,500

 Less:

 Outstanding balance
 —
 —

 Letters of credit issued
 —

 Available commitment
 $
 3,260
 $
 1,390

 Priority ranking
 Senior secured
 Senior secured

 Interest rate on available balance (3)
 SOFR plus credit spread adjustment of 0.1 %, plus margin of 1.5 % or base rate plus 0.5 %

 SOFR plus credit spread adjustment of 0.1 %, plus margin of 1.0 % - 1.5 % or base rate plus 0.0 % - 0.5 %

 Commitment fees on undrawn balance (3)
 0.525 %

 0.10 % - 0.20 %

 Letter of credit fees (3)
 N/A

 1.0 % - 1.5 %

 Maturity date
 (4)
 June 15, 2027

 (1) Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by Cheniere CCH Holdco I, our direct parent company, of its 100% ownership of our limited liability company interests.
 (2) Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the CCH Guarantors, as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the Senior Secured Notes and the CCH Credit Facility.
 (3) The margin on the interest rate, the commitment fees and the letter of credit fees are subject to change based on the applicable entity's credit rating.
 (4)The CCH Credit Facility matures the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project.

 Restrictive Debt Covenants

 The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries' ability to make certain 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 and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

 As of December 31, 2024, we were in compliance with all covenants related to our debt agreements.

 Interest Expense

 Total interest expense, net of capitalized interest, consisted of the following (in millions):

 2024
 2023
 2022

 Total interest cost
 $
 $
 $

 Capitalized interest
 ( 174)
 ( 106)
 ( 33)

 Total interest expense, net of capitalized interest
 $
 $
 $

 Fair Value Disclosures

 The following table shows the carrying amount and estimated fair value of our senior notes (in millions):

 Carrying
Amount
 Estimated
Fair Value (1)
 Carrying
Amount
 Estimated
Fair Value (1)

 Senior Secured Notes

 $
 4,865
 $
 4,441
 $
 6,356
 $
 5,961

 (1) As of both December 31, 2024 and 2023, $ 1.7 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of the fair value of our senior notes was classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

 The estimated fair value of our credit facilities approximates the principal amount outstanding because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

 NOTE 10— REVENUES

 The following table represents a disaggregation of revenue earned (in millions):

 2024
 2023
 2022

 Revenues from contracts with customers

 LNG revenues (excluding net derivative gain (loss) below)

 $
 3,602
 $
 3,850
 $
 6,335

 1,281
 1,620
 3,027

 Total revenues from contracts with customers
 4,883
 5,470
 9,362

 Net derivative gain (loss) (see Note 6)

 ( 3)
 ( 5)

 Total revenues
 $
 4,880
 $
 5,465
 $
 9,363

 LNG Revenues

 We have numerous SPAs with third party customers for the sale of LNG on an FOB basis (delivered to the customer at the Corpus Christi LNG Terminal) or a DAT basis (delivered to the customer at their specified LNG receiving terminal). Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115 % of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 11—Related Party Transactions for additional information regarding these agreements.

 Contract Assets and Liabilities

 The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):

 2024
 2023

 Contract assets, net of current expected credit losses
 $
 $

 Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. The change in contract assets between the years ended December 31, 2024 and 2023 was primarily attributable to differences between the timing of revenue recognition and the receipt of consideration related to delivery of LNG under certain SPAs.
 The following table reflects the changes in our contract liabilities, which are included in other current liabilities and other non-current liabilities on our Consolidated Balance Sheets (in millions):

 Year Ended December 31, 2024

 Deferred revenue, beginning of period
 $

 Cash received but not yet recognized in revenue

 Revenue recognized from prior period deferral
 ( 24)

 Deferred revenue, end of period
 $

 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. The change in deferred revenue as of December 31, 2024 and 2023 is 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:

 Unsatisfied Transaction Price (in billions)
 Weighted Average Recognition Timing (years) (1)
 Unsatisfied Transaction Price (in billions)
 Weighted Average Recognition Timing (years) (1)

 LNG revenues (2)
 $
 47.5
 $
 49.5

 0.9
 1.0

 Total revenues
 $
 48.4
 $
 50.5

 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
 (2) We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the transaction price above when the conditions have been met and consideration is not otherwise constrained from ultimate pricing and receipt.

 The following potential future sources of revenue are omitted from the table above under exemptions we have elected: (1) all performance obligations that are part of a contract that has an original expected duration of one year or less and (2) substantially all variable consideration under our SPAs 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.

 The following table summarizes the percentage of variable consideration earned under contracts with customers included in the table above:

 2024
 2023

 LNG revenues
 %
 %

 %
 %

 NOTE 11— RELATED PARTY TRANSACTIONS

 Below is a summary of our related party transactions, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):

 2024
 2023
 2022

 SPAs and Letter Agreements with Cheniere Marketing (1)

 $
 1,281
 $
 1,620
 $
 2,993

 Contracts for Sale and Purchase of Natural Gas and LNG with other affiliates (2)
 —
 —

 Total LNG revenues—affiliate
 1,281
 1,620
 3,027

 Cost of sales—affiliate

 Contracts for Sale and Purchase of Natural Gas and LNG (2)

 Cheniere Marketing Agreements (1) (3)

 —

 Total cost of sales—affiliate

 Operating and maintenance expense—affiliate

 Services Agreements (4)

 Land Agreements
 —
 —

 Total operating and maintenance expense—affiliate

 Operating and maintenance expense—related party

 Natural Gas Transportation Agreements (5)

 General and administrative expense—affiliate

 Services Agreements (4)

 (1)CCL primarily sells LNG to 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, 2024 and 2023, CCL had $ 190 million and $ 213 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing.
 (2) CCL has an agreement with Sabine Pass Liquefaction, LLC ("SPL") that allows the parties to sell and purchase natural gas with each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. As of December 31, 2024 and 2023, CCL did not have any accounts receivable—affiliate outstanding under these agreements with SPL.

 (3) CCL and Cheniere Marketing have 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 12 % of Henry Hub plus a fixed fee for the shipping services provided. Deliveries under the SSAs commenced in 2023.
 (4) We do not have employees and thus our subsidiaries have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements are primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2024 and 2023, we had $ 180 million and $ 116 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.
 (5) CCL is party to natural gas transportation agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. CCL recorded accrued liabilities—related party of $ 3 million and $ 1 million as of December 31, 2024 and 2023 with this related party.
 Assets and liabilities arising from the agreements with affiliates and other related parties referenced in the above table are classified as affiliate and related party, respectively, on our Consolidated Balance Sheets.

 Disclosures relating to future consideration under revenue contracts with affiliates is included in Note 10—Revenues.

 During the year ended December 31, 2024, Cheniere sold certain physical assets to a related party to support future natural gas transportation services to be provided to us involving such assets. Cheniere then contributed to us $ 34 million of other non-current assets obtained in the transaction.

 Other Agreements

 State Tax Sharing Agreements

 CCL and CCP each have a state tax sharing agreement with Cheniere. Under these agreements, Cheniere has agreed to prepare and file all state and local tax returns which each of the entities and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, each of the respective entities will pay to Cheniere an amount equal to the state and local tax that each of the entities would be required to pay if its state and local tax liability were calculated on a separate company basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreements. The agreements for both CCL and CCP were effective for tax returns due on or after May 2015.

 Equity Contribution Agreements

 We have equity contribution agreements with Cheniere and certain of its subsidiaries (the "Equity Contribution Agreements") pursuant to which Cheniere agreed to contribute any of our Senior Secured Notes that Cheniere has repurchased to us for no consideration. During the years ended December 31, 2024 and 2023, Cheniere repurchased a total of $ 1.5 billion and $ 400 million, respectively, of certain series of our Senior Secured Notes, which were immediately contributed under the Equity Contribution Agreements to us from Cheniere and cancelled by us.

 NOTE 12— COMMITMENTS AND CONTINGENCIES

 Commitments

 We have various future contractual commitments which do not meet the definition of a liability as of December 31, 2024 and thus are not recognized as liabilities in our Consolidated Financial Statements. Executed contracts containing such future commitments include agreements for capital expenditures, natural gas transportation and storage services, goods and services necessary to operate our Liquefaction Project and letters of credit.
 CCL has a lump sum turnkey contract with Bechtel Energy Inc. ("Bechtel") for the engineering, procurement and construction of the Corpus Christi Stage 3 Project. As of December 31, 2024, the total contract price of the EPC contract was approximately $ 6.0 billion, inclusive of amounts incurred under change orders, of which we had approximately $ 1.9 billion remaining obligations under this contract.

 Environmental and Regulatory Matters

 The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.
 Legal Proceedings

 We are, and 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, 2024, 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 13— SEGMENT INFORMATION AND CUSTOMER CONCENTRATION

 We have determined that we operate as a single operating and reportable segment. We have contracts with subsidiaries of Cheniere for operations, maintenance and management services, and the executive team of our affiliates that oversees us is organized by function, rather than legal entity or discrete financial data oversight, with no business component managers reporting to the chief operating decision maker ("CODM"), who is our president and chief financial officer. The CODM regularly analyzes financial and operational data on a single basis of segmentation at the consolidated level, consistent with our integrated service offering, in order to allocate resources and assess performance.

 The measure of profit and loss regularly provided to the CODM that is most consistent with GAAP is net income (loss), as presented in our Consolidated Statements of Operations. This measure contributes to the CODM's assessment of performance and resource allocation, which includes monitoring of budget versus actual results, establishing compensation and deciding on capital allocation priorities. Significant expenses regularly provided to the CODM, and included in the measure of profit and loss, are cost (recovery) of sales, operating and maintenance expense and general and administrative expense, as reported in our Consolidated Statements of Operations. Included in the measure of profit and loss is a significant noncash item of changes in the fair value of our derivative instruments, which was $ 1.0 billion of gains, $ 5.8 billion of gains and $ 3.1 billion of losses for the years ended December 31, 2024, 2023 and 2022, respectively. Interest income was $ 10 million, $ 9 million and $ 3 million for the years ended December 31, 2024, 2023 and 2022, respectively, which is included in interest and dividend income on our Consolidated Statements of Operations.

 The measure of segment assets is reported on our Consolidated Balance Sheets as total assets. Substantially all of our tangible long-lived assets, which consist of property, plant and equipment, are located in the United States. Total expenditures for additions to long-lived assets is reported on our Consolidated Statements of Cash Flows.

 The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

 Percentage of Total Revenues from
External Customers
 Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers

 2024
 2023
 2022
 2024
 2023

 Customer A
 20 %
 22 %
 21 %
 *
 13 %

 Customer B
 13 %
 15 %
 14 %
 *
 *

 Customer C
 13 %
 14 %
 14 %
 *
 *

 Customer D
 *
 *
 *
 51 %
 48 %

 Customer E
 *
 *
 10 %
 *
 *

 * Less than 10%

 The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

 Revenues from External Customers

 2024
 2023
 2022

 Spain
 $
 1,161
 $
 1,355
 $
 2,192

 France

 Singapore
 1,248

 Ireland

 Indonesia

 United States

 Other countries
 —

 Total
 $
 3,599
 $
 3,845
 $
 6,336

 NOTE 14— SUPPLEMENTAL CASH FLOW INFORMATION

 The following table provides supplemental disclosure of substantive cash flow information (in millions):

 2024
 2023
 2022

 Cash paid during the period for interest on debt, net of amounts capitalized
 $
 $
 $

 Non-cash investing and financing activities:

 Unpaid purchases of property, plant and equipment (1)

 Contributions from Cheniere for extinguishment of Senior Secured Notes
 (see Note 9) (1)

 1,491
 1,217

 Conveyance of other non-current assets from Cheniere for infrastructure support (see Note 11)

 —

 Contribution of CCL Stage III entity from Cheniere
 —
 —
 1,482

 (1) Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.

 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 None.

 ITEM 9A. CONTROLS AND PROCEDURES

 Evaluation of Disclosure Controls and Procedures

 Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

 Based on their evaluation as of the end of the fiscal year ended December 31, 2024, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.

 During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 Management's Report on Internal Control Over Financial Reporting

 Our Management's Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements and is incorporated herein by reference.

 ITEM 9B. OTHER INFORMATION

 None.

 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 Not applicable.

 ITEM 10. MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE

 Omitted pursuant to Instruction I of Form 10-K.

 ITEM 11. EXECUTIVE COMPENSATION

 Omitted pursuant to Instruction I of Form 10-K.

 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED MEMBER MATTERS

 Omitted pursuant to Instruction I of Form 10-K.

 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND MANAGER INDEPENDENCE

 Omitted pursuant to Instruction I of Form 10-K.

 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees billed by KPMG LLP for professional services rendered for 2024 and 2023 (in millions):

 Fiscal 2024

 Fiscal 2023

 Audit Fees
 $
 $

 Audit Fees—Audit fees for 2024 and 2023 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 2024 and 2023.

 Tax Fees—There were no tax fees in 2024 and 2023.

 Other Fees—There were no other fees in 2024 and 2023.

 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, 2024 and 2023.

 ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 (a) Financial Statements and Exhibits

 (1) Financial Statements—Cheniere Corpus Christi Holdings, LLC:

 Management's Report to the Member of Cheniere Corpus Christi Holdings, LLC

 Report of Independent Registered Public Accounting Firm

 Consolidated Statements of Operations

 Consolidated Balance Sheets

 Consolidated Statements of Member's Equity

 Consolidated Statements of Cash Flows

 Notes to Consolidated Financial Statements

 (2) Financial Statement Schedules:

 All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included in the consolidated financial statements and accompanying notes included in this Form 10-K.

 (3) Exhibits:

 Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:

 • should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

 • may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;

 • may apply standards of materiality that differ from those of a reasonable investor; and

 • were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.

 Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.

 Form

 3.1
 Certificate of Formation of the Company

 CCH
 S-4
 3.1

 3.2
 Certificate of Correction to Certificate of Formation of the Company

 CCH
 S-4
 3.2

 3.3
 Amended and Restated Limited Liability Company Agreement of the Company

 CCH
 S-4
 3.3

 3.4
 Certificate of Formation of CCL

 CCH
 S-4
 3.4

 3.5
 Amended and Restated Limited Liability Company Agreement of CCL

 CCH
 S-4
 3.5

 Form

 3.6
 Certificate of Formation of Corpus Christi Pipeline GP, LLC

 CCH
 S-4
 3.6

 3.7
 Certificate of Correction to Certificate of Formation of Corpus Christi Pipeline GP, LLC

 CCH
 S-4
 3.7

 3.8
 Amended and Restated Limited Liability Company Agreement of Corpus Christi Pipeline GP, LLC

 CCH
 S-4
 3.8

 3.9
 Certificate of Limited Partnership of CCP

 CCH
 S-4
 3.9

 3.10
 Certificate of Amendment to Certificate of Limited Partnership of CCP

 CCH
 S-4
 3.10

 3.11
 Amended and Restated Agreement of Limited Partnership of CCP

 CCH
 S-4
 3.11

 4.1
 Indenture, dated as of May 18, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee

 4.1
 5/18/2016

 4.2
 First Supplemental Indenture, dated as of December 9, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee

 4.1
 12/9/2016

 4.3
 Second Supplemental Indenture, dated as of May 19, 2017, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as trustee

 CCH
 4.1
 5/19/2017

 4.4
 Form of 5.125% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.3 above)

 CCH
 4.1
 5/19/2017

 4.5
 Third Supplemental Indenture, dated September 6, 2019, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee

 CCH
 4.1
 9/12/2019

 4.6
 Indenture, dated as of September 27, 2019, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and the Bank of New York Mellon, as trustee

 CCH
 4.1
 9/30/2019

 4.7
 Form of 4.80% Senior Secured Note due December 31, 2039 (Included as Exhibit A-1 to Exhibit 4.6 above)

 CCH
 4.1
 9/30/2019

 4.8
 Indenture, dated as of October 17, 2019, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee

 CCH
 4.1
 10/18/2019

 4.9
 Form of 3.925% Senior Secured Note due December 31, 2039 (Included as Exhibit A to Exhibit 4.8 above)

 CCH
 4.1
 10/18/2019

 4.10
 Fourth Supplemental Indenture, dated as of November 13, 2019, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee

 CCH
 4.1
 11/13/2019

 4.11
 Form of 3.700% Senior Secured Note due 2029 (Included as Exhibit A-1 to Exhibit 4.10 above)

 CCH
 4.1
 11/13/2019

 4.12
 Fifth Supplemental Indenture, dated as of August 24, 2021, among the Company, as issuer, CCL, CCP, and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee

 CCH
 4.1
 8/24/2021

 4.13
 Form of 2.742% Senior Secured Note due 2039 (Included as Exhibit A-1 to Exhibit 4.12 above)

 CCH
 4.1
 8/24/2021

 4.14
 Indenture, dated as of August 20, 2020, among the Company, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee

 CCH
 4.1
 8/21/2020

 4.15
 Form of 3.52% Senior Secured Note due 2039 (Included as Exhibit A-1 to Exhibit 4.14 above)

 CCH
 4.1
 8/21/2020

 10.1
 Amended and Restated Pledge Agreement, dated May 22, 2018, among Cheniere CCH HoldCo I, LLC and Soci t G n rale as Security Trustee

 CCH
 10.4
 5/24/2018

 10.2
 Amended and Restated Equity Contribution Agreement, dated May 22, 2018, among the Company and Cheniere

 CCH
 10.5
 5/24/2018

 Form

 10.3
 Second Amended and Restated Term Loan Facility Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, the lenders party thereto from time to time and Soci t G n rale as the Term Loan Facility Agent

 CCH
 10.1

 10.4
 First Amendment to Second A&R Term Loan Facility Agreement, dated April 19, 2024

 CCH
 10.2

 10.5
 Second Amended and Restated Common Terms Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, Soci t G n rale, as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, and Soci t G n rale as Intercreditor Agent, and any other facility lenders party thereto from time to time

 CCH
 10.3

 10.6
 First Amendment to Second A&R Common Terms Agreement, dated April 19, 2024

 CCH
 10.3

 10.7
 Second Amended and Restated Common Security and Account Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, the Senior Creditor Group Representatives, Soci t G n rale as the Intercreditor Agent, Soci t G n rale as Security Trustee and Mizuho Bank, Ltd as the Account Bank

 CCH
 10.4

 10.8
 First Amendment to Second A&R Common Security and Account Agreement, dated April 19, 2024

 CCH
 10.4

 10.9
 Second Amended and Restated Working Capital Facility Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, the lenders party thereto from time to time, the issuing banks party thereto from time to time, the swing line lenders party thereto from time to time, The Bank of Nova Scotia as Working Capital Facility Agent and Soci t G n rale as Security Trustee

 CCH
 10.2

 10.10
 First Amendment to Second A&R Working Capital Facility Agreement, dated April 19, 2024

 CCH
 10.5

 10.11
 Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL Stage III and Bechtel Energy Inc

 CEI
 10.1
 5/4/2022

 10.12
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL Stage III and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Maintaining Elevated Ground Flare Option, dated March 28, 2022, (ii) the Change Order CO-00002 Package 7 Pre-Investment of Trains 8 and 9 (Without Site Work), dated April 29, 2022 and (iii) the Change Order CO-00003 Modifications to Insurance Language, dated June 13, 2022 (Portions of this exhibit have been omitted.)

 CCH
 10.6
 8/4/2022

 10.13
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00004 Currency Conversion, dated June 27, 2022, (ii) the Change Order CO-00005 Fuel Adjustment, dated July 15, 2022, (iii) the Change Order CO-00006 Removal of Laydown Yard Scope Option, dated August 2, 2022, (iv) the Change Order CO-00007 Removal of Air Bridges Scope Option, dated August 22, 2022, (v) the Change Order CO-00008 Acid Gas Flare K/O Drum, dated August 16, 2022, and (vi) the Change Order CO-00009 Package 7A (Without Site Work), dated August 16, 2022 (Portions of this exhibit have been omitted.)

 CCH
 10.1

 Form

 10.14
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-000010 Insurance Provisional Sum Interim Adjustment, dated September 13, 2022 and (ii) the Change Order CO-000011 Package 6 Descope and Transfer to Owner, dated September 14, 2022 (Portions of this exhibit have been omitted.)

 CCH
 10.10
 2/23/2023

 10.15
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction Stage III, LLC and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00012 Chart License Fee Provisional Sum Closure, dated September 16, 2022, (ii) the Change Order CO-00013 HRU Nozzles and Block Headers, dated September 21, 2022, (iii) the Change Order CO-00014 Addition of Nitrogen Receiver, dated December 13, 2022, (iv) the Change Order CO-00015 Package 6 Feed Gas Pipeline Interfaces, dated December 14, 2022, (v) the Change Order CO-00016 Old Sherwin Building Security, dated November 23, 2022, (vi) the Change Order CO-00017 Remote Monitoring Diagnostic for Mixed Refrigerant (MR) Compressors, dated December 14, 2022, (vii) the Change Order CO-00018 EFG Package #1, dated January 9, 2023, (viii) the Change Order CO-00019 Q3 2022 Commodity Price Rise and Fall (ATT MM), dated January 17, 2023, (ix) the Change Order CO-00020 ICSS Vendor Selection and EPC Warranty (Yokogawa), dated September 21, 2022 and (x) the Change Order CO-00021 Laydown Development Package, dated February 6, 2023 (Portions of this exhibit have been omitted.)

 CCH
 10.1
 5/2/2023

 10.16
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction, LLC and Bechtel Energy, Inc.: (i) the Change Order CO-00022 Refrigerant Storage Packages 1 and 2, dated February 13, 2023, (ii) the Change Order CO-00023 EFG Package #2, dated February 21, 2023, (iii) the Change Order CO-00024 Defrost Improvements (Cold Box), dated February 23, 2023, (iv) the Change Order CO-00025 Miscellaneous Design Improvements, dated February 23, 2023, (v) the Change Order CO-00026 EFG Package #3, dated February 23, 2023, (vi) the Change Order CO-00027 Addition of 86 Lockout Relay on Transformers, dated February 14, 2023, (vii) the Change Order CO-00028 Additional Duct Banks, dated September 15, 2022, (viii) the Change Order CO-00029 2022 FERC Support Hours Interim Adjustment, dated March 13, 2023, (ix) the Change Order CO-00030 Drainage Blanket (A Street), dated April 6, 2023, (x) the Change Order CO-00031 Refrigerant Storage Interface Package #3, dated April 7, 2023, (xi) the Change Order CO-00032 Q4 2022 Commodity Price Rise and Fall (ATT MM), dated April 24, 2023, (xii) the Change Order CO-00033 Lift Owner-Provided Dewar System (Nitrogen Receiver Facility), dated March 1, 2022, (xiii) the Change Order CO-00034 HAZOP Package #1 - Addition of Flame Arrestors for Oil Mist Eliminator Vent, dated April 25, 2023 and (xiv) the Change Order CO-00035 EFG Package #4 (Water Pipeline Pipe Bridge), dated May 19, 2023 (Portions of this exhibit have been omitted.)

 CCH
 10.1
 8/3/2023

 Form

 10.17
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00036 Payment Milestone Updates (Schedule C-1), dated June 19, 2023, (ii) the Change Order CO-00037 Geotechnical Soils Investigation Period & Security Division of Responsibility Change, dated June 20, 2023, (iii) the Change Order CO-00038 Power Monitoring System (ETAP HMI), dated June 29, 2023 and (iv) the Change Order CO-00039 EFG Firewater Connection, dated June 30, 2023 (Portions of this exhibit have been omitted.)

 CCH
 10.1
 11/2/2023

 Form

 10.18
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00040 Q1 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (ii) the Change Order CO-00041 Q2 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (iii) the Change Order CO-00042 HAZOP Package #2 – Additional IPL (Pressure Transmitter Across the Strainer), dated July 5, 2023, (iv) the Change Order CO-00043 Total Condensate Flowmeter on Three (3) Inch Condensate Line, dated August 31, 2023, (v) the Change Order CO-00044 FERC Package #1 ISA 84 (Accommodation for Two Hundred and Fifty (250) Fire and Gas Detectors), dated August 31, 2023, (vi) the Change Order CO-00045 Increase LNG Rundown Line Check Valve Bypass Size to Six (6) Inches, dated August 31, 2023, (vii) the Change Order CO-00046 Add Manual Bypass Valves Around 31XV-13071, dated September 13, 2023, (viii) the Change Order CO-00047 Relocate Existing 16" Process Water Line and Provide Tie-In, dated September 8, 2023, (ix) the Change Order CO-00048 Future HRU Bypass Tie-In and Thermowell Updates, dated September 12, 2023, (x) the Change Order CO-00049 Butterfly Valves for Flare Drums, dated September 5, 2023, (xi) the Change Order CO-00050 Condensate Shroud on Condensate Rundown Line (Blue Engineering Report), dated September 12, 2023, (xii) the Change Order CO-00051 EFG Package #5 (138KV Feeder Cable), dated September 8, 2023, (xiii) the Change Order CO-00052 Defect Correction Period for Cementitious Fireproofing, dated August 7, 2023, (xiv) the Change Order CO-00053 Chart Transition Joint Spares, dated October 5, 2023, (xv) the Change Order CO-00054 CCL Tank(s) "A" and "C" Tie-In Study & Long Lead Item Purchases, dated September 19, 2023, (xvi) the Change Order CO-00055 FERC Package #2 Firewater Layout, dated September 13, 2023, (xvii) the Change Order CO-00056 HAZOP Package #3 – Stainless Steel C And D Pass Piping / Two Temperature Transmitters per Train, dated February 14, 2023, (xviii) the Change Order CO-00057 HAZOP Package #4 ("Phase Two Items"), dated October 10, 2023, (xix) the Change Order CO-00058 E-HAZOP Package #1 ("LV MCC Ride Through"), dated September 8, 2023, (xx) the Change Order CO-00059 Level Transmitter on Stand Pipe Inside Liquefaction Cold Boxes, dated October 13, 2023, (xxi) the Change Order CO-00060 Small Spill Containment (Additional Curbs), dated July 5, 2023, (xxii) the Change Order CO-00061 Remote Input/Output (RIO) Junction Box Grounding, dated October 10, 2023, (xxiii) the Change Order CO-00062 Geomembrane Liner and Geocell for Laydown 6 Channel, dated August 31, 2023, (xxiv) the Change Order CO-00063 Phased Surfacing of Permanent Plant Roads, dated August 7, 2023, (xxv) the Change Order CO-00064 Provisional Sum Interim Adjustment - Schedule KK-1 12-Month COVID Countermeasures, dated July 24, 2023, (xxvi) the Change Order CO-00065 Modification to FTZ Zone Site (Exhibit A of Attachment LL), dated August 3, 2023, (xxvii) the Change Order CO-00066 Attachment B (Contract Deliverables), dated June 2, 2023, (xxviii) the Change Order CO-00067 Sheet Pile Joint Sealing 310Q02 Sump, dated October 5, 2023, (xxix) the Change Order CO-00068 E-HAZOP Package #2 ("Phase One Items"), dated October 19, 2023, (xxx) the Change Order CO-00069 Package 6 Feed Gas Pipeline and Pig Receiver DMM, dated August 3, 2023, (xxxi) the Change Order CO-00070 Dry Flare Knockout Drum Spill Pad Drain Specification Change, dated October 5, 2023, (xxxii) the Change Order CO-00071 Viewing Platform Piles, dated October 18, 2023, (xxxiii) the Change Order CO-00072 Site Plan Update Package #1 – Re-Route Contractor'S Utility Water & Nitrogen Pipelines and Provide Power & Fiber Cables To Nitrogen Tie-In Point, dated November 2, 2023, (Portions of this exhibit have been omitted.)

 CCH
 10.14
 2/21/2024

 Form

 10.19
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00073 Amendment to Add Provisional Sums for the Performance and Attendance Bonus (PAB) and Saturday Work Shift Program, dated November 6, 2023, (ii) the Change Order CO-00074 Q3 2023 Commodity Price Rise and Fall Adjustment (Final Attachment MM Adjustment), dated November 6, 2023, (iii) the Change Order CO-00075 Surcharge Fill Material Transportation, dated October 11, 2023, (iv) the Change Order CO-00076 FERC Package #3 Firewall Layout (310R18), dated November 6, 2023, (v) the Change Order CO-00077 Site Plan Update Package #2 - Re-route Heavy Haul Road, dated November 2, 2023, (vi) the Change Order CO-00078 Firewater Loop Interconnect with CCL Stage 1 and CCL Stage 2, dated December 6, 2023, (vii) the Change Order CO-00079 Refrigerant Loading Manifold Design Changes, dated December 6, 2023, (viii) the Change Order CO-00080 CCL Tank(s) "A" and "C" Tie-in Long Lead Item Purchases Package #2, dated January 26, 2024, (ix) the Change Order CO-00081 CCL Tank(s) "A" and "C" Tie-in Bridging Engineering (Through 29-Mar-2024), dated February 8, 2024, (x) the Change Order CO-00082 ISA 84 Owner Requested Changes, dated January 24, 2024, (xi) the Change Order CO-00083 HAZOP Package #5 ("Phase Three Items"), dated October 19, 2023, (xii) the Change Order CO-00084 CCL Tank(s) "A" and "C" Long-Lead Item Purchases Package #3, dated March 4, 2024, (xiii) the Change Order CO-00085 Site Plan Update Package #3 - Fencing, dated January 17, 2024 (Portions of this exhibit have been omitted.)

 10.1
 5/3/2024

 10.20
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00086 CCL Tanks "A" and "C" Engineering, Procurement and Construction, dated March 15, 2024, (ii) the Change Order CO-00087 HAZOP Package #6 ("Phase Four Items"), dated January 1, 2024, (iii) the Change Order CO-00088 FERC & PHMSA (DOT) Support Hours (Through to Period 24-Dec-2023), dated February 2, 2024, and (iv) the Change Order CO-00089 30PK-3301A/B/C Firewater Pump Protection - Blast Analysis, Design and Calculation Report, dated May 7, 2024 (Portions of this exhibit have been omitted.)

 10.1

 10.21
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00090 30PK-3301 A/B/C Firewater Pump Protection - Detailed Design and Partial Procurement of Blast Resistant Doors, dated June 11, 2024, (ii) the Change Order CO-00091 30PK-3301 A/B/C Firewater Pump Protection - Purchase and Installation of Retrofit Steel, dated July 30, 2024, and (iii) the Change Order CO-00092 Intermediate Work Platform for the Tank(s) "A" and "C" Finger Rack, dated July 31, 2024 (Portions of this exhibit have been omitted.)

 10.1
 10/31/2024

 Form

 10.22*
 Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00093 Local Temperature Indication at LNG Rundown Line, dated September 23, 2024, (ii) the Change Order CO-00094 Tie-In Connection for Future Isopentane Injection, dated October 21, 2024, (iii) the Change Order CO-00095 Flame Detection Coverage Package #1, dated October 21, 2024, (iv) the Change Order CO-00096 Metering Telemetry in GIS Substation, dated November 13, 2024, (v) the Change Order CO-00097 Sifting and Sorting Operations, dated October 1, 2024, and (vi) the Change Order CO-000-98 Acceleration Program Provisional Sum, dated December 20, 2024 (Portions of this exhibit have been omitted.)

 10.23
 Operation and Maintenance Agreement, dated as of May 13, 2015, among Cheniere LNG O&M Services, LLC and CCL

 CCH
 S-4
 10.14

 10.24
 Operation and Maintenance Agreement, dated as of May 13, 2015, among Cheniere LNG O&M Services, LLC and CCP

 CCH
 S-4
 10.15

 10.25
 LNG Sale and Purchase Agreement (FOB), dated April 1, 2014, between CCL (Seller) and Endesa Generaci n, S.A. (Buyer)

 10.1
 4/2/2014

 10.26
 LNG Sale and Purchase Agreement (FOB), dated April 7, 2014, between CCL (Seller) and Endesa S.A. (Buyer)

 10.1
 4/8/2014

 10.27
 Assignment and Amendment Agreement, dated April 7, 2014, among Endesa Generaci n S.A., Endesa S.A. and CCL

 10.3
 5/1/2014

 10.28
 Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated July 23, 2015, between Endesa S.A. (Buyer) and CCL (Seller)

 10.9
 10/30/2015

 10.29
 Amendment No. 2 of LNG Sale and Purchase Agreement (FOB), dated July 23, 2015, between Endesa S.A. (Buyer) and CCL (Seller)

 10.10
 10/30/2015

 10.30
 Letter agreement regarding change from LIBOR to SOFR, dated May 18, 2023, to LNG Sale and Purchase Agreement, dated April 1, 2014, between CCL and Endesa S.A. (assignee of Endesa Generacion S.A.), as amended

 CCH
 10.2
 8/3/2023

 10.31
 Letter agreement regarding change from LIBOR to SOFR, dated May 18, 2023, to LNG Sale and Purchase Agreement, dated April 7, 2014, between CCL and Endesa S.A., as amended

 CCH
 10.3
 8/3/2023

 10.32
 Amended and Restated LNG Sale and Purchase Agreement (FOB), dated March 20, 2015, between CCL (Seller) and PT Pertamina (Persero) (Buyer)

 10.5
 4/30/2015

 10.33
 Amendment No. 1, dated February 4, 2016, to Amended and Restated LNG Sale and Purchase Agreement (FOB) between CCL and PT Pertamina (Persero), dated March 20, 2015

 CCH
 S-4
 10.22

 10.34
 Amendment No. 2 of Amended and Restated LNG Sale and Purchase Agreement, dated June 27, 2019, between CCL and PT Pertamina (Persero)

 CCH
 10.1
 11/1/2019

 10.35
 LNG Sale and Purchase Agreement (FOB), dated June 2, 2014, between CCL (Seller) and Gas Natural Fenosa LNG SL (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)

 10.1
 6/2/2014

 10.36
 Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 27, 2018, between CCL (Seller) and Gas Natural Fenosa LNG GOM, Limited (Buyer)

 CCH
 10.5
 5/4/2018

 10.37
 Second Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated June 15, 2022, between CCL and Cheniere Marketing International LLP

 CCH
 10.6

 10.38
 LNG Sale and Purchase Agreement (EOG Early IPM), dated December 30, 2019, between CCL (Seller) and Cheniere Marketing International LLP (Buyer)

 CCH
 10.34
 2/25/2020

 Form

 10.39
 Letter Agreement regarding changes to the EOG Early IPM SPA, dated November 1, 2022, between CCL and Cheniere Marketing International LLP

 CCH
 10.50

 10.40
 Letter agreement regarding change from LIBOR to SOFR, dated June 26, 2023, to LNG Sale and Purchase Agreement (EOG Early IPM) between CCL and Cheniere Marketing International LLP, dated December 30, 2019, as amended

 CCH
 10.4
 8/3/2023

 10.41
 LNG Sale and Purchase Agreement (ARC), dated June 15, 2022, between CCL Stage III and Cheniere Marketing International LLP

 CCH
 10.50

 10.42
 Letter Agreement regarding changes to the ARC IPM SPA, dated November 1, 2022, between CCL and Cheniere Marketing International LLP

 CCH
 10.40

 10.43
 LNG Sale and Purchase Agreement (Apache Corporation), dated June 15, 2022, between CCL and Cheniere Marketing International LLP

 CCH
 10.20

 10.44
 LNG Sale and Purchase Agreement (EOG Resources, Inc.), dated June 15, 2022, between CCL and Cheniere Marketing International LLP

 CCH
 10.30

 10.45
 Letter agreement, dated May 2, 2022, regarding the Amended and Restated LNG Sale and Purchase Agreement (FOB), dated November 28, 2014, between CCL and Cheniere Marketing International LLP

 CCH
 10.10
 5/4/2022

 10.46
 Amended and Restated Shipping Services Agreement in relation to the CPC SPA, dated October 28, 2024, between CCL and Cheniere Marketing (Portions of this exhibit have been omitted.)

 CCH
 10.2
 10/31/2024

 10.47
 Amended and Restated Shipping Services Agreement in relation to the Foran SPA, dated October 28, 2024 between CCL and Cheniere Marketing (Portions of this exhibit have been omitted.)

 CCH
 10.3
 10/31/2024

 10.48
 Amended and Restated Shipping Services Agreement in relation to the Orlen SPA, dated October 28, 2024 between CCL and Cheniere Marketing (Portions of this exhibit have been omitted.)

 CCH
 10.4
 10/31/2024

 21.1
 Subsidiaries of the Company

 CCH
 21.1
 2/23/2023

 22.1*
 List of Issuers and Guarantor Subsidiaries

 31.1*
 Certification by President and Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

 32.1**
 Certification by President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 101.INS*

 101.SCH*

 101.CAL*

 101.DEF*

 101.LAB*

 101.PRE*

 104*

 (1)
 Exhibits are incorporated by reference to reports of Cheniere (SEC File No. 001-16383) and CCH (SEC File No. 333-215435), as applicable.

 *
 Filed herewith.

 **
 Furnished herewith.

 (c) Financial statements of affiliates whose securities are pledged as collateral

 All financial statements have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.

 ITEM 16. FORM 10-K SUMMARY

 None.

 SIGNATURES

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 CHENIERE CORPUS CHRISTI HOLDINGS, LLC

 By:
 /s/ Zach Davis

 Zach Davis

 President and Chief Financial Officer
(Principal Executive and Financial Officer)

 Date:
 February 19, 2025

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 Signature
 Title
 Date

 /s/ Zach Davis
 Manager, President and Chief Financial Officer
(Principal Executive and Financial Officer)
 February 19, 2025

 Zach Davis

 /s/ David Slack
 Chief Accounting Officer
(Principal Accounting Officer)
 February 19, 2025

 David Slack