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, 2025

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

TABLE OF CONTENTS

PART I
Items 1. and 2. Business and Properties	4
Item 1A. Risk Factors	13
Item 1B. Unresolved Staff Comments	24
Item 1C. Cybersecurity	24
Item 3. Legal Proceedings	25
Item 4. Mine Safety Disclosure	25
PART II
Item 5. Market for Registrant’s Common Equity, Related Member Matters and Issuer Purchases of Equity Securities	26
Item 6. [Reserved]	26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	38
Item 8. Financial Statements and Supplementary Data	39
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	65
Item 9A. Controls and Procedures	65
Item 9B. Other Information	65
Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections	65
PART III
Item 10. Managers, Executive Officers and Company Governance	66
Item 11. Executive Compensation	66
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters	66
Item 13. Certain Relationships and Related Transactions, and Manager Independence	66
Item 14. Principal Accountant Fees and Services	66
PART IV
Item 15. Exhibits and Financial Statement Schedules	67
Item 16. Form 10-K Summary	76
Signatures	77

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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
DAP	delivered at place, which requires the buyer to take delivery at one or more designated receiving terminals
DOE	U.S. Department of Energy
EPC	engineering, procurement and construction
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FID	final investment decision
FOB	free-on-board, which requires the buyer to take delivery at seller's export terminal
FTA countries	countries with which the U.S. has a free trade agreement providing for national treatment for trade in natural gas
GAAP	generally accepted accounting principles in the U.S.
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
International Climate Change-Related Policies	value-chain accountability and sectoral decarbonization standards, including EU Methane Emissions Regulation, FuelEU Maritime Regulation, International Maritime Organization's Net Zero Framework and Corporate Sustainability Due Diligence Directive
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
NGA	Natural Gas Act of 1938, as amended
non-FTA countries	countries with which the U.S. 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

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Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2025, 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.

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

•statements regarding our expected receipt of cash distributions from our subsidiaries;

•statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction 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 or pipelines, including the financing of such Trains or 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.

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PART I

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 (primarily methane) in liquid form and is a cleaner dispatchable fuel for power generation. 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 and other industrial uses.

We own 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 with total expected production capacity of over 30 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which over 9 mtpa was under construction and the remainder was in operation as of December 31, 2025. The Corpus Christi LNG Terminal also has 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 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”).

The projects under construction at the Corpus Christi LNG Terminal include:

•a project consisting of seven midscale Trains that is expected to add total production capacity of over 10 mtpa of LNG once fully completed (the “Corpus Christi Stage 3 Project”), with over 4 mtpa under construction and the remainder in operation from the first four midscale Trains that have reached substantial completion as of December 31, 2025; and

•a project consisting of two additional midscale Trains that is expected to add total production capacity of approximately 5 mtpa of LNG once fully completed, inclusive of estimated debottlenecking opportunities (the “Midscale Trains 8 & 9 Project” and together with the existing assets at the Corpus Christi LNG Terminal, the Corpus Christi Stage 3 Project and the Corpus Christi Pipeline, the “Liquefaction Project”), which was under construction as of December 31, 2025. Cheniere’s board of directors made a positive FID with respect to the Midscale Trains 8 & 9 Project on June 17, 2025, and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 18, 2025. Upon FID of the Midscale Trains 8 & 9 Project in June 2025, the related EPC contract was novated to CCL from another subsidiary of Cheniere that was developing the project, and the related assets recognized by the subsidiary were contributed to CCL. Non-FTA export authorization on the Midscale Trains 8 & 9 Project is pending with the DOE.

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, 2025, we have contracted through third parties approximately 75% of the total anticipated production from the Liquefaction Project through the mid-2030s, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. Additionally, there are SPAs that Cheniere Marketing currently holds that are expected to be novated to us in the future. LNG produced by the Liquefaction Project that is not contracted under long-term contracts is available for Cheniere Marketing, Cheniere’s integrated marketing function, pursuant to an SPA it has with us.

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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. The development of any future expansions, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, regulatory approvals and 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, and continuing to fulfill all commercial commitments to, our long-term SPA customers;

•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 20, 2026, over 1,340 cumulative LNG cargoes totaling over 90 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, has over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 4 mtpa under construction from the Corpus Christi Stage 3 Project and approximately 5 mtpa under construction from the Midscale Trains 8 & 9 Project and the remainder in operation as of December 31, 2025. The Liquefaction Project also includes three storage tanks and two marine berths.

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project as of December 31, 2025:

	Corpus Christi Stage 3 Project	Midscale Trains 8 & 9 Project
Overall project completion percentage	94.1%	31.8%
Completion percentage of:
Engineering	99.6%	75.5%
Procurement	100.0%	47.3%
Subcontract work	95.1%	29.0%
Construction	84.7%	0.2%
Date of expected substantial completion	1H 2026 - 2H 2026	2H 2028

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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 (1)		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	17	875.16	17
Non-FTA countries	875.16	17	875.16	17
Corpus Christi Stage 3 Project:
FTA countries	582.14	11.45	582.14	11.45
Non-FTA countries	582.14	11.45	582.14	11.45

(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, which was approved by the FERC in March 2025.

In addition, following the pre-filing in July 2025, in February 2026, we and another subsidiary of Cheniere filed an application with the FERC under the NGA for authorization to site, construct and operate a further expansion of the Corpus Christi LNG Terminal in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “Expansion Project”).

Natural Gas Supply, Transportation and Storage

CCL has secured a portion of its expected 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 from contracts with external customers were as follows:

	Percentage of Total Revenues from Contracts with External Customers
	Year Ended December 31,
	2025	2024	2023
Endesa Generación, S.A. (which subsequently assigned its SPA to Endesa S.A.) and Endesa S.A.	19%	20%	22%
PT Pertamina (Persero)	13%	13%	14%
Naturgy LNG GOM, Limited	13%	13%	14%

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.

Business Seasonality

Our results are affected by production levels, timing of our maintenance activities and the resulting availability of volumes. Therefore, operating profit may not be generated evenly throughout the year. Weather variations, including temperature, have an impact on LNG output at our Liquefaction Project. Our Liquefaction Project is capable of relatively higher production volumes during the cooler months as compared to the summer months. We typically perform our scheduled major

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maintenance activities at our site during shoulder months in the second and third quarters in order to mitigate the impact to our annual operating results.

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. As further described in Risks Relating to Regulations within Item 1A. Risk Factors, these rigorous regulatory requirements are built into 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 and the 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 abandonment of facilities; and

•various other matters.

Under the NGA, interstate pipelines are not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including the company’s own affiliates. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require NGA Section 3 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. On March 24, 2022, the FERC rescinded the Policy Statement and re-issued it as a draft. On September 12, 2025, the FERC issued an order terminating the proceeding to consider updates to the 1999 Policy Statement.

We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate granted by the FERC. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation.

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.

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In March 2025, we received authorization from the FERC under the NGA to site, construct and operate the Midscale Trains 8 & 9 Project. In December 2025, we and another subsidiary of Cheniere filed an application with the FERC to increase the LNG production capacity of the previously-authorized Corpus Christi Stage 3 Project and Midscale Trains 8 & 9 Project by approximately 5 mtpa, which remains pending at the FERC. Following the pre-filing in July 2025, in February 2026, we and another subsidiary of Cheniere filed an application with the FERC under the NGA for authorization to site, construct and operate the Expansion Project in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities.

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) non-discrimination, which requires transmission providers to treat all transmission customers, affiliated and non-affiliated, on a not unduly discriminatory basis, and to not make or grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage; (2) independent functioning, which requires transmission function employees to function independently of marketing function employees; (3) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (4) 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 the imposition of civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC thereunder up to approximately $1.6 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. As part of its review of applications for export of LNG to non-FTA countries, the DOE publishes a Notice of Application in the Federal Register 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. The Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE. 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

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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

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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 reasonable regulations reducing methane emissions over time. Since 2009, the EPA has promulgated and finalized multiple greenhouse gas (“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 waste emissions 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 One Big Beautiful Bill Act (“OBBBA”), signed by President Trump on July 4, 2025, delays the imposition of the methane emissions charge until calendar year 2034. 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 U.S., including discharges of wastewater and storm water runoff and fill/discharges into waters of the U.S. 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

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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. Significant amounts of money have been invested recently and continue to be invested across Europe and Asia in natural gas projects. In Europe alone, over 50 mtpa of regasification capacity has been added since 2022 with more planned over the next few years to secure access to LNG and displace Russian natural gas imports. In India, over 8,000 kilometers of pipelines have started commissioning in the past several years and there are more than 9,000 kilometers of natural gas pipelines under construction to expand the natural gas distribution network and increase access to natural gas. And in China, hundreds of billions of U.S. dollars have been and 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 2025, Wood Mackenzie Limited (“WoodMac”) forecasted that global demand for LNG would increase by approximately 64%, from approximately 410 mtpa, or 19.7 Tcf, in 2024, to 671 mtpa, or 32.2 Tcf, in 2040 and by approximately 67% to 685 mtpa or 32.9 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 568 mtpa in 2040, declining to about 472 mtpa in 2050. This could result in a market need for construction of an additional approximately 104 mtpa of LNG production by 2040 and about 212 mtpa by 2050. As a cleaner dispatchable fuel for power generation, we expect natural gas and LNG to play a central role in balancing grids and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project, 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 and other competing fuels 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-

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focused operations to provide flexible and tailored solutions to LNG buyers. We will compete with other natural gas liquefaction projects throughout the world, including our affiliate, Sabine Pass Liquefaction, LLC (“SPL”), primarily on the basis of price. 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, will also be subject to market-based price competition. Refer to Item 1A. Risk Factors for further discussion of risks relating to market 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 2025, Cheniere published Together, We Deliver, its sixth Corporate Responsibility (“CR”) report, which details Cheniere’s approach and progress on environmental, social and governance (“ESG”) matters. Cheniere’s 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. In 2024, Cheniere announced a voluntary, measurement-informed Scope 1 annual methane emissions intensity target across its liquefaction facilities. The Scope 1 methane target builds upon Cheniere’s robust climate strategy and leverages data from Cheniere’s multi-scale quantification, monitoring, reporting and verification (“QMRV”) emissions measurement program. Cheniere achieved a methane emissions intensity for 2024, which received third party limited assurance, of less than its methane target of 0.03% across its liquefaction sites, as reported in Cheniere’s latest CR report.

As a key aspect of its strategy, Cheniere collaborates with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, 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. As a result of Cheniere’s efforts described above, in 2025, Cheniere achieved OGMP 2.0 Gold Standard reporting by the UNEP for its comprehensive methane emissions measurement and reporting under the OGMP 2.0 program and recognition by the Coalition for LNG Emissions Abatement toward Net-zero led by the Japan Organization for Metals and Energy Security. 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, 2025, 2024 and 2023. 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.

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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, 2025, Cheniere and its subsidiaries had 1,717 full-time employees, including 507 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;

•Risks Relating to Our Relationship with Cheniere; 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, 2025, we had $195 million of restricted cash and cash equivalents, $4.1 billion of available commitments under our credit facilities and $5.4 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 and the Midscale Trains 8 & 9 Project as well as the Expansion Project if a positive FID is made on this expansion project. 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

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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 lenders or seek alternative 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, 2025, we had SPAs with fewer than 15 different third party customers, with customers under common control being considered a single customer, whereby three customers individually with revenues greater than 10% of total revenues from contracts with external customers accounted for an aggregate of 45% of total revenues from contracts with external customers for the year ended December 31, 2025.

While substantially all of our long-term third party customer arrangements are executed with a creditworthy 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 have a significant adverse or otherwise volatile effect on 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, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse or otherwise volatile 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, 2025 and 2024 included $2.6 billion and $1.0 billion of gains, 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. As of December 31, 2025 and 2024, we had collateral posted with counterparties by us of $9 million and $5 million, respectively, which are included in other current assets, net in our Consolidated Balance Sheets.

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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 an affiliate to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers from another affiliate’s 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 the other affiliate’s facilities 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, or interruptions to our power supply, 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 are designed in accordance with the 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 for transporters to continue shipping natural gas to us 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 immediately preceding risk factor. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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

Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Project to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the immediately preceding risk factor. Additionally, composition changes in the quality of feed gas received from third parties may impact operational efficiency and performance, which could have an effect on our operating results. 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

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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.

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, the Midscale Trains 8 & 9 Project and any potential expansion projects, including the Expansion Project.

Timely and cost-effective completion of the Corpus Christi Stage 3 Project, the Midscale Trains 8 & 9 Project and any potential expansion projects, including the Expansion 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, the Midscale Trains 8 & 9 Project and any potential expansion projects, including the Expansion 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, the Midscale Trains 8 & 9 Project and any potential expansion projects, including the Expansion 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.

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Cost overruns and delays in the completion of our expansion projects, including the Corpus Christi Stage 3 Project, the Midscale Trains 8 & 9 Project and the Expansion 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, the Midscale Trains 8 & 9 Project and any potential future expansion of LNG facilities, including the Expansion 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 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, certain of our SPAs 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.

Our ability to complete development and/or construction of additional Trains, including the Expansion 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 growth 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 Expansion 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 Expansion Project and 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 Expansion Project or any additional Trains or any additional expansion projects, which could have a material adverse effect on our growth strategy, financial condition, operating results, cash flow and liquidity.

Changes to U.S. trade policy could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The U.S. has recently enacted and proposed to enact significant new tariffs and trade restrictions. Additionally, President Trump has directed various federal agencies to further evaluate key aspects of U.S. trade policy and there has been ongoing discussion and commentary regarding potential significant changes to U.S. trade policies, treaties and tariffs. For example, as part of its Section 301 investigation of the maritime, logistics and shipbuilding sector in China (the “Section 301 Investigation”), the Office of the U.S. Trade Representative (the “USTR”) in April 2025 mandated, among other things, restrictions on maritime transport services for U.S. LNG exports. These measures require that, beginning in April 2029, 1% of U.S. LNG exports must be exported on U.S.-built vessels, with such percentage gradually increasing to 15% in April 2047, with certain exceptions. In its original April 2025 notice, USTR had included the potential suspension of LNG export licenses as a remedy for non-compliance with the U.S. vessel restrictions; however, USTR subsequently removed the suspension language. In November 2025, the White House announced that, as part of the broader economic and trade relations deal with China, it had agreed to defer certain pending tariff and trade measures against China, including suspending for one year the implementation

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of fees on China-linked vessels pursuant to the Section 301 Investigation. However, the timeline for the U.S.-built vessel requirements for U.S. LNG exports thus far has not been modified. Given the ongoing evolution of the Section 301 Investigation measures, the potential impact of the restrictions on us and the LNG industry remains uncertain.

There continues to exist significant uncertainty about the future relationship between the U.S. and other countries with respect to trade policies, trade agreements, trade restrictions and tariffs. Any resulting unwillingness or inability of LNG purchasers in such countries to import LNG from the U.S. or increases in pricing as a result of retaliatory tariffs on exported U.S. LNG, 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:

•increasingly competitive North American LNG landscape;

•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 worldwide;

•increased demand for natural gas in North America;

•increased natural gas production worldwide, either domestically or deliverable by pipelines, which could suppress demand for LNG;

•decreased oil and natural gas exploration activities which may decrease the production of natural gas in North America;

•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 North American LNG, natural gas or alternative energy sources, which may reduce the demand for exported North American 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 North American LNG compared to other sources, 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.

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

Operations of the Liquefaction Project are dependent upon the ability of our SPA customers to deliver LNG supplies from North America, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside North America, which could increase the available supply of natural gas outside North America 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 U.S., may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the U.S. 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 U.S.

As described in Market Factors and Competition 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 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 North America, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in North America.

As described in General in Items 1. and 2. Business and Properties, we have contracted through our SPAs and IPM agreements approximately 75% of the total anticipated production from the Liquefaction Project with approximately 16 years of weighted average remaining life as of December 31, 2025, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. Additionally, there are SPAs that Cheniere Marketing currently holds that are expected to be novated to us in the future. LNG produced by the Liquefaction Project that is not contracted under long-term contracts is available for Cheniere Marketing, Cheniere’s integrated marketing function, to sell in the global market under spot sales or other short-term agreements. 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 U.S. 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;

•decreases in demand for LNG or 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;

•increases in the cost to supply power 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;

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•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;

•increases in capacity and utilization of nuclear power and related facilities; and

•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

A cyberattack 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. Cyberattacks 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 cyberattacks, 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 cyberattack 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.

Risks Relating to Our Relationship with Cheniere

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, 2025, Cheniere and its subsidiaries had 1,717 full-time employees, including 507 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 U.S. 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 to us 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.

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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 for Cheniere 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. Currently, our payments to Cheniere for labor consist of reimbursement of cost plus a fixed monthly fee (indexed for inflation) per mtpa of each Train in service, therefore any increases in Cheniere’s costs will increase our operating costs which 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, as described in Market Factors and Competition, 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 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 and expect to continue to have numerous contracts and commercial arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements, as well as servicing and 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, 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 Expansion 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 all of our Trains in operation or under construction, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Corpus Christi Pipeline. In December 2025, we and another subsidiary of Cheniere filed an application with the FERC to increase the LNG production capacity of the previously-authorized Corpus Christi Stage 3 Project and Midscale Trains 8 & 9 Project by approximately 5 mtpa and the application remains pending at the FERC. Following the pre-filing in July 2025, in February 2026, we and another subsidiary of Cheniere filed an application with the FERC under the NGA for authorization to site, construct and operate the Expansion Project in a phased approach.

To date, the DOE has also issued orders under Section 3 of the NGA authorizing CCL and the Corpus Christi Stage 3 Project to export domestically produced LNG, as further detailed in DOE Export Licenses in Our Business. We currently have the Midscale Trains 8 & 9 Project pending non-FTA export approval with the DOE. 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.

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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 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. The FERC’s jurisdiction under the NGA allows the imposition of civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC thereunder, up to $1.6 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 U.S. 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 would have applied to our facilities beginning in calendar year 2024. The OBBBA, signed by President Trump on July 4, 2025, delays the imposition of the methane emissions charge until calendar year 2034. 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

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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, 2025, 2024 and 2023. 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 or variables impacting our tax obligations could potentially affect our financial results or liquidity.

Tax laws and regulations are complex and rapidly evolving. We are subject to various taxes in the jurisdictions where we operate, primarily consisting of ad valorem property taxes on assets at the Corpus Christi LNG Terminal. Changes to local, state or domestic tax laws, their interpretation, enforcement practices, and rates, including changes related to tariffs and duties, are beyond our control and could affect our tax obligations, compliance costs, financial results and cash flows. We continuously monitor and assess proposed tax legislation that could negatively impact our business.

Additionally, we have legacy property tax incentives secured for the Corpus Christi LNG Terminal, inclusive of the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project, that begin to expire starting in 2026, with continuing

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incentive roll-off thereafter over the longer term. The magnitude of property tax changes once our incentives expire is uncertain, but will be influenced, both in the near and longer term, by various factors including future local tax rates, local tax rate compression dynamics, and changes in our assessed property values over time. During the year ended December 31, 2025, our ad valorem property tax incurred, inclusive of both the Corpus Christi LNG Terminal and the Corpus Christi Pipeline, was approximately $57 million.

Further, CCL and CCP each have a state tax sharing agreement with Cheniere under which 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. The agreements for both CCL and CCP were effective for tax returns due on or after May 2015. 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. While to date there have been no state or local tax payments demanded by Cheniere under the tax sharing agreements, any payment demanded by Cheniere could adversely affect our financial results and cash flows.

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 a “govern, identify, protect, detect, respond and recover” approach to cybersecurity that is based on 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 principle of least privilege. 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 Cybersecurity 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 periodic training, user awareness campaigns and additional issue-specific training as needed. Cheniere also provides periodic 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.

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During the year ended December 31, 2025, 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 cyberattack 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.

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PART II

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

Not applicable.

ITEM 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, 2023 and variance drivers between the year ended December 31, 2024 as compared to December 31, 2023 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, 2024.

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. Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. For further discussion of our business, see Items 1. and 2. Business and Properties. 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, as well as the current geopolitical environment that has intensified the demand for supply security, should enable us to enter into long-term agreements and provide a foundation for additional growth in our business in the future.

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Overview of Significant Events

Our significant events since January 1, 2025 and through the filing date of this Form 10-K include the following:

Strategic

•Following the pre-filing in July 2025, in February 2026, we and another subsidiary of Cheniere filed an application with the FERC under the NGA for authorization to site, construct and operate in a phased approach the Expansion Project, a further expansion of the Corpus Christi LNG Terminal, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities.

•In December 2025, we and another subsidiary of Cheniere filed an application with the FERC to increase the LNG production capacity of the previously-authorized Corpus Christi Stage 3 Project and Midscale Trains 8 & 9 Project by approximately 5 mtpa, which remains pending at the FERC.

•In March 2025, we received authorization from the FERC under the Natural Gas Act of 1938, as amended to site, construct and operate the Midscale Trains 8 & 9 Project, and in June 2025, Cheniere’s Board made a positive FID with respect to the investment in the development, construction and operation of the Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under a fixed price separated turnkey EPC contract, which was novated to CCL, to commence construction of the Midscale Trains 8 & 9 Project.

Operational

•As of February 20, 2026, over 1,340 cumulative LNG cargoes totaling over 90 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

•In March, August, October and December 2025, substantial completions of Trains 1, 2, 3 and 4, respectively, of the Corpus Christi Stage 3 Project were achieved. In February 2026, LNG was produced for the first time from Train 5 of the Corpus Christi Stage 3 Project.

Financial

•In October 2025, S&P Global Ratings upgraded the issuer credit rating of CCH to BBB+ from BBB with a positive outlook.

Market Environment

Our results of operations are affected by the market environment in which we operate, including known trends and uncertainties, macroeconomic factors and other external environmental factors.

With just under 20 mtpa of year on year (“YoY”) increase in LNG supplies globally in 2025, the LNG market is transitioning from a multi-year state of tight market conditions into a period of rapid growth. The continued ramp up in new LNG supplies from the U.S. and Canada mark the start of a more ample supply landscape which is expected to loosen global balances over the next few years and result in a more moderate and stable price environment for LNG. Sustained downward pressure on global prices could potentially unlock latent demand that has otherwise been priced out since the disruption of Russian natural gas supply to Europe.

The increase in supply corresponded to a 5% YoY uptick in trade, which was primarily supported by Europe and the Middle East and North Africa (“MENA”) region amid weaker demand in Asia. Europe’s demand for LNG increased approximately 27% YoY in 2025 reaching a record level of approximately 125 mtpa. The main driver for this growth continues to be the replacement of Russian natural gas and the replenishment of underground storage inventories. We expect this driver to continue to play an important role in keeping LNG demand in Europe resilient, especially in light of the European Parliament’s vote to ban all residual Russian natural gas, including Russian LNG by 2027. The MENA region also contributed to demand growth in 2025 with imports increasing 7 mtpa or 62% versus 2024. Egypt was the main driver of this increase as it resorted to additional LNG imports to satisfy its growing domestic energy needs and supplement its own natural gas production.

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Asia’s LNG consumption however was down about 4% in 2025, dropping by 12 mtpa to 270 mtpa. While many of the major markets in Asia saw YoY declines, China’s was the largest, representing nearly the entire YoY change in the region. China’s LNG imports declined 16% or 12 mtpa YoY, due to broader, likely transient macro-economic challenges. Natural gas demand growth in China slowed in 2025 and higher piped natural gas flows from Russia and robust domestic natural gas production decreased the call on LNG.

Despite weaker demand in Asia and an easing in geopolitical conflicts during the second half of 2025, average prices remained elevated versus 2024. The Japan Korea Marker (“JKM”) monthly settlement prices in 2025 averaged $12.71 per MMBtu, 7.5% higher YoY while those for Title Transfer Facilities (“TTF”) averaged $12.04 per MMBtu, 10.3% higher YoY. Strong storage injections, an increase in LNG supply and expectations of mild weather resulted in downward pressure in the second half of the year with monthly settlements averaging at least $1.76 per MMBtu lower for JKM and $2.34 per MMBtu lower for TTF versus the first half of the year. Henry Hub monthly settlements averaged $3.43 per MMBtu during 2025.

As referenced above, expectations of significant LNG capacity expansions in the next few years, and the recent momentum in FIDs if continued, are likely to keep the price trajectory trending lower in Asia and Europe. We expect the price elastic markets, particularly in Asia, to respond to the increased availability and affordability of supply by growing imports to satisfy latent demand as well as organic longer-term growth.

Results of Operations

	Year Ended December 31,
(in millions)	2025		2024		Variance
Revenues
LNG revenues	$	4,448	$	3,599	$	849
LNG revenues—affiliate	2,053		1,281		772
Total revenues	6,501		4,880		1,621
Operating costs and expenses
Cost of sales (excluding operating and maintenance expense and depreciation and amortization expense shown separately below)	813		1,184		(371)
Cost of sales—affiliate	85		96		(11)
Operating and maintenance expense	560		524		36
Operating and maintenance expense—affiliate	142		117		25
Operating and maintenance expense—related party	32		24		8
General and administrative expense	7		8		(1)
General and administrative expense—affiliate	40		44		(4)
Depreciation and amortization expense	514		457		57
Other operating costs and expenses	3		3		—
Total operating costs and expenses	2,196		2,457		(261)
Income from operations	4,305		2,423		1,882
Other income (expense)
Interest expense, net of capitalized interest	(31)		(65)		34
Loss on modification or extinguishment of debt	—		(3)		3
Other income, net	9		10		(1)
Other income—affiliate	17		—		17
Total other expense	(5)		(58)		53
Net income	$	4,300	$	2,365	$	1,935

Volumes loaded and recognized from the Liquefaction Project

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	Year Ended December 31,
	2025			2024
	Operational	Commissioning	Total	Operational	Commissioning	Total
Volumes loaded and recognized (in TBtu)	854	24	878	760	—	760

2025 vs. 2024

Net income increased by $1.9 billion during the year ended December 31, 2025 as compared to the same period of 2024 primarily due to $1.6 billion of favorable changes in the fair value of agreements accounted for as derivative instruments and a $474 million increase in revenues, net of cost of natural gas feedstock, from increased volume of LNG loaded and recognized between the years. The following is an expanded discussion of the significant drivers of the variance in net income:

Total revenues

The $1.6 billion increase in total revenues during the year ended December 31, 2025 as compared to the same period of 2024 was primarily due to:

•$1.0 billion increase from higher pricing per MMBtu as a result of increased Henry Hub pricing; and

•$0.6 billion increase from higher production volume which was primarily due to the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project in 2025.

Total operating costs and expenses

The $261 million decrease in total operating costs and expenses during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to:

•$1.6 billion of gains from changes in fair value of agreements accounted for as derivative instruments included in cost of sales, primarily on our IPM agreements, due to the narrowing of global and U.S. domestic natural gas spreads and the effect of relative change in volatilities of applicable global and U.S. domestic natural gas prices; partially offset by:

•$1.2 billion increase in cost of natural gas feedstock, largely due to increased U.S. natural gas prices and to a lesser degree, increased volume of LNG delivered; and

•$69 million increase in operating and maintenance expense (including affiliate and related party) and $57 million increase in depreciation and amortization expense almost entirely as a result of the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project in 2025.

Total other expense

The $53 million decrease in total other expense during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to:

•$34 million decrease in interest expense, net of capitalized interest, due to a $18 million decrease in gross interest costs, resulting from the full retirement in April 2024 of $1.5 billion of the 5.875% Senior Secured Notes due 2025, and $16 million increase in capitalized interest costs, given the higher carrying value of assets under construction, primarily associated with the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project; and

•$17 million increase in other income—affiliate related to service agreements with an affiliated subsidiary of Cheniere, as further described in Note 11—Related Party Transactions of our Notes to Consolidated Financial Statements.

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Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to 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.

Commissioning volumes

Prior to substantial completion of a Train, amounts received from the sale of commissioning volumes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train and are necessary activities to bring the asset to the condition for its intended use. During the year ended December 31, 2025, we realized offsets to LNG terminal costs of $173 million corresponding to 24 TBtu of LNG that was related to the sale of commissioning volumes associated with the Corpus Christi Stage 3 Project. We did not record any offsets to LNG terminal costs during the year ended December 31, 2024.

Additional liquefaction capacities

The Corpus Christi Stage 3 Project and Midscale Trains 8 & 9 Project are currently under construction and are expected to add over 15 mtpa of operational liquefaction capacity, inclusive of estimated debottlenecking opportunities, once all Trains reach substantial completion, of which over 9 mtpa is still under construction as of December 31, 2025. As of December 31, 2025, the first four Trains of the Corpus Christi Stage 3 Project were in operation, with substantial completions for each Train achieved in March, August, October and December 2025, respectively. The operation and maintenance of these Trains and increased LNG volumes produced are expected to result in higher revenues and operating costs and expenses. Additionally, potential expansion projects that increase the amount of LNG volumes produced, including those discussed in Items 1. and 2. Business and Properties, would also be expected to result in higher revenues and operating costs and expenses.

Additionally, see Items 1. and 2. Business and Properties for discussion of our business seasonality.

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Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. 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 or contributions from Cheniere.

The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.

	December 31, 2025
Restricted cash and cash equivalents designated for the Liquefaction Project	$	195
Available commitments under our credit facilities (1):
Term loan facility agreement (the “CCH Credit Facility”)	2,710
Working capital facility agreement (the “CCH Working Capital Facility”)	1,390
Total available commitments under our credit facilities	4,100
Total available liquidity	$	4,295

(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2025. 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, 2025 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.

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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, 2025. 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 expect future material sources of liquidity to be derived from our long-term customer arrangements and structured cash flows under our SPAs. As described in Items 1. and 2. Business and Properties, these contracts with creditworthy counterparties form the foundation of our business and provide us with significant, stable, long-term cash flows.

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, 2025. The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2025 (in billions):

	Estimated Revenues Under Executed SPAs by Period (1) (2)
	2026		2027 - 2030		Thereafter		Total
LNG revenues (fixed fees)	$	2.8	$	11.3	$	28.6	$	42.7
LNG revenues (variable fees) (3)	3.9		14.6		44.8		63.3
Total	$	6.7	$	25.9	$	73.4	$	106.0

(1)LNG revenues exclude revenues from contracts with original expected durations of one year or less.

(2)LNG revenues (including $1.0 billion and $1.8 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, 2025.

Under our SPAs and IPM agreements currently in effect, we have contracted approximately 75% of the total anticipated production through the mid-2030s from our liquefaction capacity that is currently in construction or operation. Additionally, there are SPAs that Cheniere Marketing currently holds that are expected to be novated to us in the future. As described in General, under our SPAs, customers purchase LNG on either an FOB basis or a DAP basis 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.

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The table above excludes SPAs with Cheniere Marketing under which we sell LNG at pricing linked to the same global gas market prices as our IPM agreements. The IPM agreements, 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 17 years, we expect to generate liquidity from the approximately 3,158 TBtu of LNG yet to be delivered under these SPAs as of December 31, 2025. The table above also excludes volumes related to commissioning which 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.

Additional Future Sources of Liquidity

Available Commitments under Credit Facilities

As of December 31, 2025, we had $4.1 billion in available commitments under our credit facilities, as detailed earlier in the table summarizing our available liquidity, 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, 2025.

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. Following the pre-filing in July 2025, in February 2026, we and another subsidiary of Cheniere filed an application with the FERC under the NGA for authorization to site, construct and operate the Expansion Project in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities. 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, 2025 (in billions):

	Estimated Payments Due Under Executed Contracts by Period (1)
	2026		2027 - 2030		Thereafter		Total
Purchase obligations (2):
Natural gas supply agreements excluding IPM agreements (3) (4)	$	2.9	$	5.8	$	4.5	$	13.2
Natural gas transportation and storage service agreements (5)	0.3		1.1		2.6		4.0
Capital expenditures	1.4		0.9		—		2.3
Shipping services agreements (6)	0.3		1.6		4.9		6.8
Other purchase obligations (7)	0.1		0.3		1.5		1.9
Total	$	5.0	$	9.7	$	13.5	$	28.2

(1)Agreements in force as of December 31, 2025 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2025.

(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.

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(4)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2025. Natural gas supply agreements are presented net of $0.2 billion in contracted sales of natural gas as of December 31, 2025.

(5)Natural gas transportation and storage services agreements include $1.3 billion in obligations to related parties. See Note 11 — Related Party Transactions for further information about our related parties.

(6)Shipping services agreements are between CCL and Cheniere Marketing for the provision of shipping-related services associated with certain SPAs between CCL and third-party customers with DAP delivery terms.

(7)Other purchase obligations include $1.5 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 3,441 TBtu of natural gas feedstock for the Liquefaction Project through long-term natural gas supply agreements with remaining fixed terms of up to 14 years. As of December 31, 2025, we have secured approximately 66% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2026, excluding the 14% of which has been secured under IPM agreements. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2026. As further described in Future Sources of Liquidity under Executed Contracts, the pricing structure of our SPAs often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, thus limiting our net exposure to future increases in natural gas prices.

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 lump sum Bechtel EPC contracts for both the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 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. As of December 31, 2025, substantial completions of the first four of seven midscale Trains of the Corpus Christi Stage 3 Project were achieved. Additionally, in June 2025, Cheniere’s Board made a positive FID with respect to the Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under an EPC contract for a contract price of approximately $2.9 billion, subject to adjustment only by change order. Refer to Liquefaction Project and Expansion Projects in Items 1. and 2. Business and Properties — Our Business for a summary of the construction status and estimated completion of both the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project as of December 31, 2025. 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.

Additional Future Cash Requirements for Operations and Capital Expenditures

Operational Services

We do not have any employees, and thus have contracts with subsidiaries of Cheniere for operations, maintenance and management services. As described in Note 11—Related Party Transactions, our payment structures under the services agreements primarily consist of cost reimbursement, plus a compensating fee based on a fixed amount (indexed for inflation) per mtpa of each Train in service. Prior to the substantial completion of a Train, a compensating fee is charged based on a percentage of the capital expenditures of the Train under construction.

As of December 31, 2025, Cheniere and its subsidiaries had 1,717 full-time employees, including 507 employees who directly supported the Liquefaction Project.

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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, 2025 (in billions):

	Estimated Payments Due Under Executed Contracts by Period (1)
	2026		2027 - 2030		Thereafter		Total
Debt	$	—	$	3.4	$	2.0	$	5.4
Interest payments	0.2		0.6		0.4		1.2
Total	$	0.2	$	4.0	$	2.4	$	6.6

(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, 2025. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.

Debt

As of December 31, 2025, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $4.9 billion and credit facilities with $550 million outstanding loan balances. As of December 31, 2025, 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, 2025, our senior notes had a weighted average contractual interest rate of 4.10%. Interest on borrowings under our credit facilities will bear interest at a variable rate per annum equal to Term SOFR or the base rate specified therein, and we are subject to interest rates on outstanding balances, commitment fees on undrawn balances and letter of credit fees on issued letters of credit. We had $110 million aggregate amount of issued letters of credit under the CCH Working Capital Facility as of December 31, 2025. Further details of our credit facilities can be found in Note 9—Debt of our Notes to Consolidated Financial Statements.

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.

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Sources and Uses of Cash

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

	Year Ended December 31,
	2025		2024
Net cash provided by operating activities	$	1,995	$	1,771
Net cash used in investing activities	(2,306)		(1,830)
Net cash provided by (used in) financing activities	393		(3)
Net increase (decrease) in restricted cash and cash equivalents	$	82	$	(62)

Operating Cash Flows

The $224 million increase between the periods was primarily related to higher net cash inflows from LNG sales, as explained above in Results of Operations. Partially offsetting the increase was a decrease in working capital, which decreased mainly due to differences in timing of cash collections from the sale of LNG cargoes and payments to suppliers.

Investing Cash Flows

Our investing net cash outflows primarily related to: (1) construction costs for the Corpus Christi Stage 3 Project, which were $1.3 billion and $1.5 billion during the years ended December 31, 2025 and 2024, respectively, and (2) $749 million of costs paid for the Midscale Trains 8 & 9 Project during the year ended December 31, 2025, not including the amount incurred by another subsidiary of Cheniere that was developing the project prior to the EPC contract being novated to CCL upon FID of the Midscale Trains 8 & 9 Project in June 2025, primarily related to procurement and engineering. The $0.2 billion decrease in construction costs for the Corpus Christi Stage 3 Project between the periods was primarily related to a decline in expenditures in the current year related to the EPC contract as the project approaches completion. We expect to continue to incur capital expenditures for the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project as construction progresses on these projects.

Financing Cash Flows

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

	Year Ended December 31,
	2025		2024
Proceeds from borrowings	$	550	$	—
Contributions	375		415
Distributions	(515)		(400)
Other	(17)		(18)
Net cash provided by (used in) financing activities	$	393	$	(3)

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

Our derivative instruments are recorded at fair value unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception, 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

36

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 liquefaction supply derivatives valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2025 and 2024 (in millions). The changes in fair value shown are limited to instruments still held at the end of each respective period.

	Year Ended December 31,
	2025		2024
Favorable changes in fair value of liquefaction supply derivatives still held at the end of the period	$	2,058	$	554

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, 2025 and 2024.

The estimated fair value of level 3 liquefaction supply derivatives recognized in our Consolidated Balance Sheets as of December 31, 2025 and 2024 amounted to an asset of $3,193 million and $506 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.

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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):

	December 31, 2025				December 31, 2024
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	3,179	$	1,828	$	539	$	2,174

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

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

Management’s Report to the Member of Cheniere Corpus Christi Holdings, LLC	40
Report of Independent Registered Public Accounting Firm	41
Consolidated Statements of Operations	43
Consolidated Balance Sheets	44
Consolidated Statements of Member’s Equity	45
Consolidated Statements of Cash Flows	46
Notes to Consolidated Financial Statements	47
Note 1—Organization and Nature of Operations	47
Note 2—Summary of Significant Accounting Policies	47
Note 3—Trade and Other Receivables, Net of Current Expected Credit Losses	52
Note 4—Inventory	52
Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation	53
Note 6—Derivative Instruments	53
Note 7—Other Non-current Assets, Net	56
Note 8—Accrued Liabilities	56
Note 9—Debt	57
Note 10—Revenues	59
Note 11—Related Party Transactions	61
Note 12—Commitments and Contingencies	62
Note 13—Segment Information and Customer Concentration	63
Note 14—Supplemental Cash Flow Information	64

39

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, 2025, 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)

40

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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, 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 $3,193 million as of December 31, 2025, 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 the 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,

41

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 25, 2026

42

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

	Year Ended December 31,
	2025		2024		2023
Revenues
LNG revenues	$	4,448	$	3,599	$	3,845
LNG revenues—affiliate	2,053		1,281		1,620
Total revenues	6,501		4,880		5,465
Operating costs and expenses (recoveries)
Cost (recovery) of sales (excluding operating and maintenance expense and depreciation and amortization expense shown separately below)	813		1,184		(3,178)
Cost of sales—affiliate	85		96		171
Operating and maintenance expense	560		524		479
Operating and maintenance expense—affiliate	142		117		116
Operating and maintenance expense—related party	32		24		9
General and administrative expense	7		8		6
General and administrative expense—affiliate	40		44		45
Depreciation and amortization expense	514		457		449
Other operating costs and expenses	3		3		2
Total operating costs and expenses (recoveries)	2,196		2,457		(1,901)
Income from operations	4,305		2,423		7,366
Other income (expense)
Interest expense, net of capitalized interest	(31)		(65)		(217)
Loss on modification or extinguishment of debt	—		(3)		(10)
Other income, net	9		10		11
Other income—affiliate	17		—		—
Total other expense	(5)		(58)		(216)
Net income	$	4,300	$	2,365	$	7,150

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

43

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions)

	December 31,
	2025		2024
ASSETS
Current assets
Restricted cash and cash equivalents	$	195	$	113
Trade and other receivables, net of current expected credit losses	306		194
Trade receivables—affiliate	342		190
Advances to affiliates	100		180
Inventory	168		132
Current derivative assets	7		21
Prepaid expenses	15		12
Other current assets, net	30		10
Total current assets	1,163		852
Property, plant and equipment, net of accumulated depreciation	18,770		16,254
Derivative assets	3,913		1,805
Other non-current assets, net	421		423
Total assets	$	24,267	$	19,334
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	50	$	87
Accrued liabilities	752		523
Accrued liabilities—related party	3		3
Due to affiliates	184		76
Current derivative liabilities	433		635
Other current liabilities	11		25
Other current liabilities—affiliate	1		1
Total current liabilities	1,434		1,350
Long-term debt, net of unamortized discount and debt issuance costs	5,378		4,830
Derivative liabilities	308		652
Other non-current liabilities	28		40
Other non-current liabilities—affiliate	2		2
Total liabilities	7,150		6,874
Commitments and contingencies (see Note 12)
Member’s equity	17,117		12,460
Total liabilities and member’s equity	$	24,267	$	19,334

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

44

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

(in millions)

	Cheniere CCH HoldCo I, LLC		Total Member’s Equity
Balance at December 31, 2022	$	1,084	$	1,084
Contributions (excluding the item shown separately below)	180		180
Non-cash contribution (see Note 9)	398		398
Distributions	(280)		(280)
Net income	7,150		7,150
Balance at December 31, 2023	8,532		8,532
Contributions (excluding the items shown separately below)	415		415
Non-cash contribution (see Note 9)	1,514		1,514
Non-cash asset contribution from Cheniere (see Note 11)	34		34
Distributions	(400)		(400)
Net income	2,365		2,365
Balance at December 31, 2024	12,460		12,460
Contributions (excluding the items shown separately below)	375		375
Non-cash contribution (see Note 1)	497		497
Distributions	(515)		(515)
Net income	4,300		4,300
Balance at December 31, 2025	$	17,117	$	17,117

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

45

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2025		2024		2023
Cash flows from operating activities
Net income	$	4,300	$	2,365	$	7,150
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	514		457		449
Amortization of discount and debt issuance costs	9		9		11
Total gains on derivative instruments, net	(2,612)		(985)		(5,825)
Net cash provided by (used for) settlement of derivative instruments	(28)		(14)		7
Interest expense relieved by parent	—		23		2
Other	6		10		14
Changes in operating assets and liabilities:
Trade and other receivables	(108)		(13)		168
Trade receivables—affiliate	(136)		23		26
Inventory	(35)		(9)		50
Other current assets	(20)		(3)		74
Other non-current assets	(22)		(39)		(39)
Accounts payable and accrued liabilities	126		(37)		(347)
Accrued liabilities—related party	(1)		2		—
Total deferred revenue	(25)		(18)		(1)
Other, net	(5)		(2)		(2)
Other, net—affiliate	32		2		28
Net cash provided by operating activities	1,995		1,771		1,765
Cash flows from investing activities
Property, plant and equipment, net of proceeds from commissioning sales of LNG of $152 million, zero and zero, respectively	(2,298)		(1,810)		(1,711)
Other, net	(8)		(20)		(11)
Net cash used in investing activities	(2,306)		(1,830)		(1,722)
Cash flows from financing activities
Proceeds from borrowings	550		—		—
Repayments and repurchases of debt	—		—		(498)
Contributions	375		415		180
Distributions	(515)		(400)		(280)
Other	(17)		(18)		(8)
Net cash provided by (used in) financing activities	393		(3)		(606)
Net increase (decrease) in restricted cash and cash equivalents	82		(62)		(563)
Restricted cash and cash equivalents—beginning of period	113		175		738
Restricted cash and cash equivalents—end of period	$	195	$	113	$	175

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

46

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We own a natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through CCL, which has total expected production capacity of over 30 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which over 9 mtpa was under construction and the remainder was in operation as of December 31, 2025. The Corpus Christi LNG Terminal also has three LNG storage tanks and two marine berths. 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”).

The projects under construction at the Corpus Christi LNG Terminal include:

•a project consisting of seven midscale Trains that is expected to add total production capacity of over 10 mtpa of LNG once fully completed (the “Corpus Christi Stage 3 Project”), with over 4 mtpa under construction and the remainder in operation from the first four midscale Trains that have reached substantial completion as of December 31, 2025; and

•a project consisting of two additional midscale Trains that is expected to add total production capacity of approximately 5 mtpa of LNG once fully completed, inclusive of estimated debottlenecking opportunities (the “Midscale Trains 8 & 9 Project” and together with the existing assets at the Corpus Christi LNG Terminal, the Corpus Christi Stage 3 Project and the Corpus Christi Pipeline, the “Liquefaction Project”), which was under construction as of December 31, 2025. Cheniere’s board of directors made a positive FID with respect to the Midscale Trains 8 & 9 Project on June 17, 2025, and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 18, 2025. Upon FID of the Midscale Trains 8 & 9 Project in June 2025, the related EPC contract was novated to CCL from another subsidiary of Cheniere that was developing the project, and the related construction-in-process and other non-current assets recognized by the subsidiary totaling $373 million and $124 million, respectively, were contributed to CCL.

We do not have employees and thus we and 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. See Note 11—Related Party Transactions for additional details of the activity under these services agreements during the years ended December 31, 2025, 2024 and 2023.

We are a disregarded entity for federal, state and local 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 tax return of Cheniere. Accordingly, no provision or liability for income taxes is included in the accompanying Consolidated Financial Statements. However, other state or local taxes owed by us are subject to a tax sharing arrangement our subsidiaries have with Cheniere, as described in Note 11—Related Party Transactions. 

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 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.

47

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, or models that incorporate observable market data, when such data is available. 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 FOB or DAP delivery terms, which is generally the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of 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.

Sales generated during the commissioning phase of a Train are offset against the cost of construction for the respective Train, as further described under the caption Property, Plant and Equipment below. 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. For the years ended December 31, 2025, 2024 and 2023, we did not have any material revenue arrangements that were 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.

48

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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.

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

	Year Ended December 31,
	2025		2024		2023
Current expected credit losses, beginning of period	$	3	$	3	$	4
Charges (reversals), net	—		—		(1)
Current expected credit losses, end of period	$	3	$	3	$	3

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 or acquisition of assets, 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, preliminary material and equipment procurement and engineering design work.

Sales proceeds earned from volumes produced and sold during the commissioning phase of a respective 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, net of associated costs, as such activities are necessary to test the facility and bring the asset to the condition necessary for its intended use.

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 Consolidated Balance Sheets, and any 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

49

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2025, 2024 and 2023.

Interest Capitalization

We capitalize interest costs as part of the historical cost of qualifying assets, mainly during the construction period of the qualifying assets, which primarily consists of LNG terminal and related assets. Upon placing the underlying asset in service, these costs are depreciated or amortized over the estimated useful life of the corresponding assets for which interest costs were incurred.

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, unless a derivative instrument satisfies criteria for, and we elect, the normal purchases and normal sales exception and account for the instrument under the accrual method of accounting, whereby the designated instrument’s revenues or expenses, as applicable, are recognized only upon delivery, receipt or realization of the underlying transaction.

We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2025, 2024 and 2023; 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 and other current liabilities. 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 counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, consist principally of accounts receivable and contract assets related to our long-term SPAs, as our contracted LNG sales are primarily under SPAs with terms exceeding 10 years. As of December 31, 2025, CCL had SPAs with initial terms of 10 or more years with less than 15 different third party customers, with customers under common control being considered a single customer, and had agreements with Cheniere Marketing. CCL is dependent on the respective customers’ creditworthiness and their ability to perform under their respective agreements. While substantially all

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of our long-term third party customer arrangements are executed with a creditworthy 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, 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.

While we use derivative instruments that expose us to counterparty credit risk, our underlying arrangements typically include provisions that protect us and our counterparties against such risk. For example, our commodity derivatives executed over-the-counter or through an exchange 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. For non-exchange traded transactions, payments on margin deposits, either by us or by the counterparty depending on the position, are required 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. 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 assets.

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.

Term debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees 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, 2025 and 2024, 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 except in the case of our credit facilities, in which such items are amortized on a straight-line basis over the contractual term of the facility. Amortization is recorded in interest expense, net of capitalized interest using the effective interest method.

We classify debt on our Consolidated Balance Sheets based on contractual maturity, with the following exceptions:

•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement.

•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method 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

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dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the U.S. 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 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):

	December 31,
	2025		2024
Trade receivables	$	288	$	181
Other receivables	18		13
Total trade and other receivables, net of current expected credit losses	$	306	$	194

Upon collection of our trade receivables, cash will be immediately restricted for the payment of liabilities related to the Liquefaction Project. See Note 2—Summary of Significant Accounting Policies for further discussion of our Restricted Cash and Cash Equivalents.

NOTE 4—INVENTORY

Inventory consisted of the following (in millions):

	December 31,
	2025		2024
Materials	$	146	$	108
LNG	12		16
Natural gas	9		7
Other	1		1
Total inventory	$	168	$	132

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

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

	Useful live	December 31,
	(years)	2025		2024
LNG terminal
Terminal and interconnecting pipeline facilities	6 - 50	$	17,283	$	13,406
Land		575		302
Construction-in-process		3,716		4,846
Accumulated depreciation		(2,811)		(2,306)
Total LNG terminal, net of accumulated depreciation		18,763		16,248
Fixed assets
Fixed assets	3 - 10	31		28
Accumulated depreciation		(24)		(22)
Total fixed assets, net of accumulated depreciation		7		6
Property, plant and equipment, net of accumulated depreciation		$	18,770	$	16,254

The following table shows depreciation expense and offsets to LNG terminal (in millions):

	Year Ended December 31,
	2025		2024		2023
Depreciation expense	$	511	$	455	$	448
Sales proceeds earned from commissioning sales of LNG offset to LNG terminal (1)	173		—		—

(1)We realize offsets to LNG terminal for sales proceeds from commissioning volumes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

NOTE 6—DERIVATIVE INSTRUMENTS

We have commodity derivatives consisting of natural gas and power supply contracts, including 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
	December 31, 2025								December 31, 2024
	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)	$	—	$	(14)	$	3,193	$	3,179	$	—	$	33	$	506	$	539

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

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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, 2025:

	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$3,193	Market approach incorporating present value techniques	Henry Hub basis spread	$(4.085) - $0.067 / $(0.215)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	70% - 407% / 171%

(1)Unobservable inputs were weighted by the relative fair value of the instruments.

(2)Spread contemplates U.S. dollar-denominated pricing.    

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

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

	Year Ended December 31,
	2025		2024		2023
Balance, beginning of period	$	506	$	(502)	$	(6,205)
Realized and change in fair value gains (losses) included in net income (1):
Included in cost of sales, existing deals (2)	2,061		551		4,383
Included in cost of sales, new deals (3)	(3)		3		(1)
Purchases and settlements:
Purchases (4)	—		—		—
Settlements (5)	630		454		1,321
Transfers out of level 3 (6)	(1)		—		—
Balance, end of period	$	3,193	$	506	$	(502)
Favorable changes in fair value relating to instruments still held at the end of the period	$	2,058	$	554	$	4,382

(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.

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(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 indexed to Henry Hub, global LNG or other natural gas price indices. As of December 31, 2025, 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 6,423 TBtu and 7,003 TBtu as of December 31, 2025 and 2024, 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, 2025 and 2024.

The following table shows the effect and location of the Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations (in millions):

	Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)	Year Ended December 31,
	2025		2024		2023
LNG revenues	$	1	$	(3)	$	(5)
Cost of sales	2,611		988		5,830

(1)Does not include the realized value associated with the Liquefaction Supply Derivatives that settle through physical delivery. Fair value fluctuations associated with our 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
	December 31, 2025		December 31, 2024
Consolidated Balance Sheets Location
Current derivative assets	$	7	$	21
Derivative assets	3,913		1,805
Total derivative assets	3,920		1,826
Current derivative liabilities	(433)		(635)
Derivative liabilities	(308)		(652)
Total derivative liabilities	(741)		(1,287)
Derivative asset, net	$	3,179	$	539

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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 (in millions):

	Liquefaction Supply Derivatives
	December 31, 2025		December 31, 2024
Gross assets	$	4,724	$	2,836
Offsetting amounts	(804)		(1,010)
Net assets	$	3,920	$	1,826
Gross liabilities	$	(771)	$	(1,326)
Offsetting amounts	30		39
Net liabilities	$	(741)	$	(1,287)

We had collateral balances of $9 million and $5 million that were recorded within other current assets, net, and not netted on our Consolidated Balance Sheets, as of December 31, 2025 and 2024, respectively.

NOTE 7—OTHER NON-CURRENT ASSETS, NET

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

	December 31,
	2025		2024
Contract assets, net of current expected credit losses	$	244	$	223
Advances to service providers	86		86
Debt issuance costs and deferred commitment fees, net of accumulated amortization	47		47
Other	44		67
Total other non-current assets, net	$	421	$	423

NOTE 8—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	December 31,
	2025		2024
Natural gas purchases	$	492	$	319
LNG Terminal costs	193		143
Other accrued liabilities	67		61
Total accrued liabilities	$	752	$	523

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NOTE 9—DEBT

Debt consisted of the following (in millions): 

	December 31,
	2025		2024
Senior Secured Notes:
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		4,865
Term loan facility agreement (the “CCH Credit Facility”)	550		—
Working capital facility agreement (the “CCH Working Capital Facility”)	—		—
Total debt	5,415		4,865
Unamortized discount and debt issuance costs	(37)		(35)
Total long-term debt, net of unamortized discount and debt issuance costs	$	5,378	$	4,830

(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, prior 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 5.625% Senior Secured Notes due 2025. 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 Agreement, 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, 2025 (in millions): 

Years Ending December 31,	Principal Payments
2026	$	—
2027	1,321
2028	629
2029	1,299
2030	181
Thereafter	1,985
Total	$	5,415

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Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2025 (in millions):

	CCH Credit Facility (1)		CCH Working Capital Facility (2)
Total facility size	$	3,260	$	1,500
Less:
Outstanding balance	550		—
Letters of credit issued	—		110
Available commitment	$	2,710	$	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%
Weighted average interest rate of outstanding balance	5.316%		n/a
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, LLC, 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 agreements governing our indebtedness 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 distributions. For example, we are restricted from making distributions under agreements governing our indebtedness generally unless, 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. Additionally, as described in Note 2—Summary of Significant Accounting Policies, 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.

As of December 31, 2025, we were in compliance with all covenants related to our debt agreements.

Interest Expense

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

	Year Ended December 31,
	2025		2024		2023
Total interest cost	$	221	$	239	$	323
Capitalized interest	(190)		(174)		(106)
Total interest expense, net of capitalized interest	$	31	$	65	$	217

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Fair Value Disclosures

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

	December 31, 2025				December 31, 2024
	Carrying Amount (1)		Estimated Fair Value (2)		Carrying Amount (1)		Estimated Fair Value (2)
Senior Secured Notes	$	5,415	$	4,618	$	4,865	$	4,441

(1)Carrying amounts exclude unamortized discount and debt issuance costs.

(2)As of December 31, 2025 and 2024, $1.8 billion and $1.7 billion, respectively, 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 any outstanding borrowings under our credit facilities approximates the principal amount outstanding because the interest rates are indexed to 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):

	Year Ended December 31,
	2025		2024		2023
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)	$	4,447	$	3,602	$	3,850
LNG revenues—affiliate	2,053		1,281		1,620
Total revenues from contracts with customers	6,500		4,883		5,470
Net derivative gain (loss) (see Note 6)	1		(3)		(5)
Total revenues	$	6,501	$	4,880	$	5,465

LNG Revenues

We have numerous SPAs with third party customers for the sale of LNG on an FOB basis or a DAP basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 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. 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 included in other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	December 31,
	2025		2024
Contract assets, net of current expected credit losses	$	263	$	224

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Contract assets include 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 and have primarily arisen from certain SPAs that have tiered payments structures.

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, 2025
Deferred revenue, beginning of period	$	57
Cash received but not yet recognized in revenue	—
Revenue recognized from prior period deferral	(25)
Deferred revenue, end of period	$	32

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 between the years ended December 31, 2025 and 2024 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:

	December 31, 2025			December 31, 2024
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	41.7	8	$	47.5	9
LNG revenues—affiliate	1.0		7	0.9		9
Total revenues	$	42.7		$	48.4

(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.

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, and allocable to wholly unsatisfied future performance obligations or otherwise constrained, will vary based on (1) the future prices of the underlying variable index, primarily Henry Hub, throughout the contract terms, to the extent customers elect to take delivery of their LNG, (2) adjustments to the consumer price index and (3) the outcome of certain contingent events, including the achievement of milestones upon which delivery of LNG under certain contracts is conditioned.

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

	Year Ended December 31,
	2025		2024
LNG revenues	56	%	45	%
LNG revenues—affiliate	78	%	81	%

60

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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):

	Year Ended December 31,
	2025		2024		2023
LNG revenues—affiliate
SPAs and Letter Agreements (1)	$	2,053	$	1,281	$	1,620
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG (1) (2)	2		1		55
Shipping Services Agreements (3)	83		95		116
Total cost of sales—affiliate	85		96		171
Operating and maintenance expense—affiliate
Services Agreements (4)	141		117		116
Other Agreements	1		—		—
Total operating and maintenance expense—affiliate	142		117		116
Operating and maintenance expense—related party
Natural Gas Transportation Agreements (5)	32		24		9
General and administrative expense—affiliate
Services Agreements (4)	40		44		45
Other income—affiliate
Services Agreements (6)	17		—		—

(1)CCL primarily sells LNG to Cheniere Marketing under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices. In addition, CCL has an arrangement with Cheniere Marketing 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.

(2)CCL has an agreement with Sabine Pass Liquefaction, LLC (“SPL”) that allows the parties to sell and purchase natural gas with each other at prices and quantities as agreed between the parties per transaction. 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.

(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 under DAP delivery terms. Under the SSAs, CCL pays Cheniere Marketing a fee of 5% to 12% of Henry Hub plus a fixed fee for the shipping services provided.

(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. Our payment structures under the services agreements primarily consist of a cost reimbursement plus a compensating fee based on a fixed amount (indexed for inflation) per mtpa of each Train in service. 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 related parties through Cheniere’s equity method investments in the ordinary course of business for the operation of the Liquefaction Project. On February 13, 2025, Cheniere sold all of its interests in one of its equity method investments to a third party. We recognized $1 million,

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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

$8 million and $9 million of operating and maintenance expense from the investee during the years ended December 31, 2025, 2024 and 2023, respectively.

(6)Represents the amount of cumulative income allocated to certain of our subsidiaries by an affiliate, to whom our subsidiaries advance payments so that the affiliate may pay operating expenses on their behalf pursuant to their operating and maintenance agreements. The affiliate in turn temporarily invests such funds into interest and dividend earning deposit accounts, from which they allocated the historically earned income to our subsidiaries effective June 30, 2025. The affiliate currently allocates such income to our subsidiaries in the same period the affiliate earns such interest and dividend income.

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, 2025, we purchased certain physical assets from other subsidiaries of Cheniere to support the expansion of the Liquefaction Project for $109 million which is recorded in due to affiliates. 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 Agreement

We have an equity contribution agreement with Cheniere and our direct parent company (the “Equity Contribution Agreement”) pursuant to which Cheniere agreed to contribute any of our Senior Secured Notes that Cheniere has repurchased to us for no consideration. During the year ended December 31, 2024, Cheniere repurchased a total of $1.5 billion of certain series of our Senior Secured Notes, which were immediately contributed under the Equity Contribution Agreement 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, 2025 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 contractual commitments under lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project. The total contract price of the EPC contracts, inclusive of amounts incurred under change orders, for the Corpus Christi Stage 3 Project and the Midscale Trains 8 & 9 Project were approximately $6.0 billion and $2.9 billion, respectively, of which we had remaining obligations of approximately $0.7 billion and $1.6 billion, respectively, as of December 31, 2025

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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2025, 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, 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. Also provided regularly to the CODM are changes in the fair value of our derivative instruments, which are inclusive of significant noncash items, which were $2.6 billion, $1.0 billion and $5.8 billion in gains for the years ended December 31, 2025, 2024 and 2023, respectively. Interest income, which is included in other income, net on our Consolidated Statements of Operations, was $8 million, $10 million and $9 million for the years ended December 31, 2025, 2024 and 2023, respectively.

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 U.S. Total expenditures for additions to long-lived assets is reported on our Consolidated Statements of Cash Flows.

The following table shows the concentration of our customer credit risk with 10% or more of total revenues from contracts with external customers and/or trade receivables, net of current expected credit losses and contract assets, net of current expected credit losses. Customers under common control are considered to be a single customer.

	Percentage of Total Revenues from Contracts with External Customers			Percentage of Trade Receivables, Net and Contract Assets, Net from External Customers
	Year Ended December 31,			December 31,
	2025	2024	2023	2025	2024
Customer A	19%	20%	22%	*	*
Customer B	13%	13%	14%	*	*
Customer C	13%	13%	14%	*	*
Customer D	*	*	*	46%	53%
Customer E	*	*	*	12%	*

* Less than 10%

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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows total revenues from contracts with external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues to the country in which the party to the applicable agreement has its principal place of business, with foreign countries that individually accounted for 10% or more of total revenues from contracts with external customers shown separately from the remaining countries. Revenues attributed to foreign countries exclude certain sales and other operating revenues for which attribution to a specific country is not practicable.

	Total Revenues from Contracts with External Customers
	Year Ended December 31,
	2025		2024		2023
Spain	$	1,141	$	1,161	$	1,355
Singapore	739		525		590
France	672		540		543
Ireland	581		484		538
Indonesia	573		483		558
U.S.	108		86		86
Other countries	633		323		180
Total	$	4,447	$	3,602	$	3,850

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2025		2024		2023
Cash paid during the period for interest on debt, net of amounts capitalized	$	23	$	140	$	223
Non-cash investing activities (1):
Unpaid purchases of property, plant and equipment (2)	261		62		148
Transfers to property, plant and equipment from other non-current assets	24		—		—
Non-cash contribution of assets (See Note 1)	497		—		—
Contribution from Cheniere for extinguishment of Senior Secured Notes (see Note 9)	—		1,491		400
Conveyance of other non-current assets from Cheniere for infrastructure support (see Note 11)	—		34		—

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

(2)Net of proceeds not yet collected from commissioning sales of LNG of $21 million, zero and zero, respectively.

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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, 2025, 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

On February 25, 2026, CCL and Cheniere Marketing International LLP (“CMI”) entered into an SPA for approximately 1.5 mtpa of LNG associated with the previously existing DAP SPA between CMI and Orlen S.A.

ITEM 9C.    DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III

ITEM 10.     MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE

Omitted pursuant to Instruction I of Form 10-K.

ITEM 11.     EXECUTIVE COMPENSATION 

Omitted pursuant to Instruction I of Form 10-K.

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

Omitted pursuant to Instruction I of Form 10-K.

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

Omitted pursuant to Instruction I of Form 10-K.

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees billed by KPMG LLP for professional services rendered for 2025 and 2024 (in millions): 

	Fiscal 2025		Fiscal 2024
Audit Fees	$	2	$	1

Audit Fees—Audit fees for 2025 and 2024 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 2025 and 2024.

Tax Fees—There were no tax fees in 2025 and 2024.

Other Fees—There were no other fees in 2025 and 2024.

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, 2025 and 2024.

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PART IV

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	40
Report of Independent Registered Public Accounting Firm	41
Consolidated Statements of Operations	43
Consolidated Balance Sheets	44
Consolidated Statements of Member’s Equity	45
Consolidated Statements of Cash Flows	46
Notes to Consolidated Financial Statements	47

(2)     Financial Statement Schedules:

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

(3)    Exhibits:

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

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

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

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

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

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

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
3.1	Certificate of Formation of the Company	CCH	S-4	3.1	1/5/2017
3.2	Certificate of Correction to Certificate of Formation of the Company	CCH	S-4	3.2	1/5/2017
3.3	Amended and Restated Limited Liability Company Agreement of the Company	CCH	S-4	3.3	1/5/2017
3.4	Certificate of Formation of CCL	CCH	S-4	3.4	1/5/2017
3.5	Amended and Restated Limited Liability Company Agreement of CCL	CCH	S-4	3.5	1/5/2017

67

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
3.6	Certificate of Formation of Corpus Christi Pipeline GP, LLC	CCH	S-4	3.6	1/5/2017
3.7	Certificate of Correction to Certificate of Formation of Corpus Christi Pipeline GP, LLC	CCH	S-4	3.7	1/5/2017
3.8	Amended and Restated Limited Liability Company Agreement of Corpus Christi Pipeline GP, LLC	CCH	S-4	3.8	1/5/2017
3.9	Certificate of Limited Partnership of CCP	CCH	S-4	3.9	1/5/2017
3.10	Certificate of Amendment to Certificate of Limited Partnership of CCP	CCH	S-4	3.10	1/5/2017
3.11	Amended and Restated Agreement of Limited Partnership of CCP	CCH	S-4	3.11	1/5/2017
4.1	Indenture, dated as of May 18, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee	Cheniere	8-K	4.1	5/18/2016
4.2	First Supplemental Indenture, dated as of December 9, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee	Cheniere	8-K	4.1	12/9/2016
4.3	Second Supplemental Indenture, dated as of May 19, 2017, among the Company, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	5/19/2017
4.4	Form of 5.125% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.3 above)	CCH	8-K	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	8-K	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	8-K	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	8-K	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	8-K	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	8-K	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	8-K	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	8-K	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	8-K	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	8-K	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	8-K	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	8-K	4.1	8/21/2020
10.1	Amended and Restated Pledge Agreement, dated May 22, 2018, among Cheniere CCH HoldCo I, LLC and Société Générale as Security Trustee	CCH	8-K	10.4	5/24/2018
10.2	Amended and Restated Equity Contribution Agreement, dated May 22, 2018, among the Company and Cheniere	CCH	8-K	10.5	5/24/2018

68

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
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 Société Générale as the Term Loan Facility Agent	CCH	8-K	10.1	6/22/2022
10.4	First Amendment to Second A&R Term Loan Facility Agreement, dated April 19, 2024	CCH	10-Q	10.2	8/8/2024
10.5	Second Amended and Restated Common Terms Agreement, dated June 15, 2022, among the Company, CCP, Corpus Christi Pipeline GP, LLC, CCL, Société Générale, as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, and Société Générale as Intercreditor Agent, and any other facility lenders party thereto from time to time	CCH	8-K	10.3	6/22/2022
10.6	First Amendment to Second A&R Common Terms Agreement, dated April 19, 2024	CCH	10-Q	10.3	8/8/2024
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, Société Générale as the Intercreditor Agent, Société Générale as Security Trustee and Mizuho Bank, Ltd as the Account Bank	CCH	8-K	10.4	6/22/2022
10.8	First Amendment to Second A&R Common Security and Account Agreement, dated April 19, 2024	CCH	10-Q	10.4	8/8/2024
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 Société Générale as Security Trustee	CCH	8-K	10.2	6/22/2022
10.10	First Amendment to Second A&R Working Capital Facility Agreement, dated April 19, 2024	CCH	10-Q	10.5	8/8/2024
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 (successor of CCL Stage III) and Bechtel Energy Inc	CEI	10-Q	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 (successor of CCL Stage III) and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Maintaining Elevated Ground Flare Option, dated March 28, 2022, (ii) the Change Order CO-00002 Package 7 Pre-Investment of Trains 8 and 9 (Without Site Work), dated April 29, 2022 and (iii) the Change Order CO-00003 Modifications to Insurance Language, dated June 13, 2022 (Portions of this exhibit have been omitted.)	CCH	10-Q	10.6	8/4/2022
10.13	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-Q	10.1	11/3/2022

69

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
10.14	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-000010 Insurance Provisional Sum Interim Adjustment, dated September 13, 2022 and (ii) the Change Order CO-000011 Package 6 Descope and Transfer to Owner, dated September 14, 2022 (Portions of this exhibit have been omitted.)	CCH	10-K	10.10	2/23/2023
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-Q	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-Q	10.1	8/3/2023

70

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
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-Q	10.1	11/2/2023

71

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
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-K	10.14	2/21/2024

72

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
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.)	CCH	10-Q	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.)	CCH	10-Q	10.1	8/8/2024
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.)	CCH	10-Q	10.1	10/31/2024

73

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
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-0009 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-0096 Metering Telemetry in GIS Substation, dated November 13, 2024, (v) the Change Order CO-0097 Sifting and Sorting Operations, dated October 1, 2024, and (vi) the Change Order CO-0098 Acceleration Program Provisional Sum, dated December 20, 2024 (Portions of this exhibit have been omitted.)	CCH	10-K	10.22	2/20/2025
10.23	Change order 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.: the Change Order CO-00099 #57 Crushed Rock for Surface Paving - ISBL Areas, dated January 24, 2025 (Portions of this exhibit have been omitted.)	CCH	10-Q	10.1	5/8/2025
10.24	Change order 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-000100 HAZOP Provisional Sum Closure, dated August 24, 2024, (ii) the Change Order CO-00101 Hot Oil Spools and Heat Exchange Coating Specification, dated March 5, 2025, (iii) the Change Order CO-00102 Reconciliation (Tax) - Change Orders CO-00014 through CO-00061, dated February 2, 2024, (iv) the Change Order CO-00103 Lube Oil for Refrigeration Compressor, dated April 30, 2025, (v) the Change Order CO-00104 Miscellaneous Scope Revisions, dated March 13, 2025, (vi) the Change Order CO-00105 FERC and PHMSA (DOT) Support Hours (2024 Period), dated May 16, 2025, (vii) the Change Order CO-00106 Closure of Performance and Attendance Bonus (PAB) and Saturday Work Shift Program Provisional Sum, dated May 16, 2025, (viii) the Change Order CO-00107 P&ID Natives for Trains 1-2 and OSBL Phase 1, dated May 16, 2025, (ix) the Change Order CO-00108 Stormwater Sampling Outfall 003 (Small Triangle Area), dated May 22, 2025, and (x) the Change Order CO-00109 Owner Request for Train 1 Refrigerant Staging (Standby Driver), dated May 22, 2025 (Portions of this exhibit have been omitted.)	CCH	10-Q	10.1	8/7/2025
10.25	Change order 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-00110 Owner Accommodations at Contractor CityWest Offices, dated May 22, 2025, (ii) the Change Order CO-00111 Trim Modifications on PV-17016 and PV-17516 Valves, dated July 21, 2025, (iii) the Change Order CO-00112 Supply of Train 2 Demineralized Water (Owner Request), dated July 25, 2025 and (iv) the Change Order CO-00113 Acceleration Program Extension (August - November 2025), dated August 4, 2025 (Portions of this exhibit have been omitted.)	CCH	10-Q	10.1	10/30/2025
10.26*	Change order 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-00114 P&ID Natives for Trains 3 through 7 and OSBL Phase 2, dated October 29, 2025 and (ii) the Change Order CO-00115 Acceleration Program Extension (January - April 2026), dated December 23, 2025 (Portions of this exhibit have been omitted.)

74

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
10.27	Operation and Maintenance Agreement, dated as of May 13, 2015, among Cheniere LNG O&M Services, LLC and CCL	CCH	S-4	10.14	1/5/2017
10.28	Operation and Maintenance Agreement, dated as of May 13, 2015, among Cheniere LNG O&M Services, LLC and CCP	CCH	S-4	10.15	1/5/2017
10.29	LNG Sale and Purchase Agreement (FOB), dated April 1, 2014, between CCL (Seller) and Endesa Generación, S.A. (Buyer)	Cheniere	8-K	10.1	4/2/2014
10.30	LNG Sale and Purchase Agreement (FOB), dated April 7, 2014, between CCL (Seller) and Endesa S.A. (Buyer)	Cheniere	8-K	10.1	4/8/2014
10.31	Assignment and Amendment Agreement, dated April 7, 2014, among Endesa Generación S.A., Endesa S.A. and CCL	Cheniere	10-Q	10.3	5/1/2014
10.32	Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated July 23, 2015, between Endesa S.A. (Buyer) and CCL (Seller)	Cheniere	10-Q	10.9	10/30/2015
10.33	Amendment No. 2 of LNG Sale and Purchase Agreement (FOB), dated July 23, 2015, between Endesa S.A. (Buyer) and CCL (Seller)	Cheniere	10-Q	10.10	10/30/2015
10.34	Letter agreement regarding change from LIBOR to SOFR, dated May 18, 2023, to LNG Sale and Purchase Agreement, dated April 1, 2014, between CCL and Endesa S.A. (assignee of Endesa Generacion S.A.), as amended	CCH	10-Q	10.2	8/3/2023
10.35	Letter agreement regarding change from LIBOR to SOFR, dated May 18, 2023, to LNG Sale and Purchase Agreement, dated April 7, 2014, between CCL and Endesa S.A., as amended	CCH	10-Q	10.3	8/3/2023
10.36	Amended and Restated LNG Sale and Purchase Agreement (FOB), dated March 20, 2015, between CCL (Seller) and PT Pertamina (Persero) (Buyer)	Cheniere	10-Q	10.5	4/30/2015
10.37	Amendment No. 1, dated February 4, 2016, to Amended and Restated LNG Sale and Purchase Agreement (FOB) between CCL and PT Pertamina (Persero), dated March 20, 2015	CCH	S-4	10.22	1/5/2017
10.38	Amendment No. 2 of Amended and Restated LNG Sale and Purchase Agreement, dated June 27, 2019, between CCL and PT Pertamina (Persero)	CCH	10-Q	10.1	11/1/2019
10.39	LNG Sale and Purchase Agreement (FOB), dated June 2, 2014, between CCL (Seller) and Gas Natural Fenosa LNG SL (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)	Cheniere	8-K	10.1	6/2/2014
10.40	Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 27, 2018, between CCL (Seller) and Gas Natural Fenosa LNG GOM, Limited (Buyer)	CCH	10-Q	10.5	5/4/2018
10.41	Second Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated June 15, 2022, between CCL and Cheniere Marketing International LLP	CCH	8-K	10.6	6/22/2022
10.42	LNG Sale and Purchase Agreement (ARC), dated June 15, 2022, between CCL (successor of CCL Stage III) and Cheniere Marketing International LLP	CCH	8-K	10.5	6/22/2022
10.43	Letter Agreement regarding changes to the ARC IPM SPA, dated November 1, 2022, between CCL and Cheniere Marketing International LLP	CCH	10-Q	10.4	11/3/2022
10.44	LNG Sale and Purchase Agreement (Apache Corporation), dated June 15, 2022, between CCL and Cheniere Marketing International LLP	CCH	10-Q	10.2	11/3/2022
10.45	LNG Sale and Purchase Agreement (EOG Resources, Inc.), dated June 15, 2022, between CCL and Cheniere Marketing International LLP	CCH	10-Q	10.3	11/3/2022
10.46*	LNG Sale and Purchase Agreement (PKN Orlen), dated February 25, 2026, between CCL and Cheniere Marketing International LLP

75

Exhibit No.		Incorporated by Reference (1)
Exhibit No.	Description	Entity	Form	Exhibit	Filing Date
10.47	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-Q	10.2	10/31/2024
10.48	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-Q	10.3	10/31/2024
10.49	Shipping Services Agreement in relation to the PTT SPA, dated August 1, 2025, between CCL and Cheniere Marketing (Portions of this exhibit have been omitted.)	CCH	10-Q	10.2	8/7/2025
21.1	Subsidiaries of the Company	CCH	10-K	21.1	2/23/2023
22.1	List of Issuers and Guarantor Subsidiaries	CCH	10-K	22.1	2/20/2025
31.1*	Certification by President and Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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

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

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

ITEM 16.    FORM 10-K SUMMARY

None.

76

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 25, 2026

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 25, 2026
Zach Davis
/s/ David Slack	Chief Accounting Officer (Principal Accounting Officer)	February 25, 2026
David Slack

77