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, 2021

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.)

700 Milam Street, Suite 1900

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 requirement of Sections 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. ☐

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	5
Item 1A. Risk Factors	13
Item 1B. Unresolved Staff Comments	20
Item 3. Legal Proceedings	20
Item 4. Mine Safety Disclosure	20
PART II
Item 5. Market for Registrant’s Common Equity, Related Member Matters and Issuer Purchases of Equity Securities	21
Item 6. [Reserved]	21
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	32
Item 8. Financial Statements and Supplementary Data	33
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	64
Item 9A. Controls and Procedures	64
Item 9B. Other Information	64
Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections	64
PART III
Item 10. Managers, Executive Officers and Company Governance	65
Item 11. Executive Compensation	65
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters	65
Item 13. Certain Relationships and Related Transactions, and Manager Independence	65
Item 14. Principal Accountant Fees and Services	65
PART IV
Item 15. Exhibits and Financial Statement Schedules	66
Item 16. Form 10-K Summary	74
Signatures	75

i

DEFINITIONS

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

Common Industry and Other Terms

Bcf	billion cubic feet
Bcf/d	billion cubic feet per day
Bcf/yr	billion cubic feet per year
Bcfe	billion cubic feet equivalent
DOE	U.S. Department of Energy
EPC	engineering, procurement and construction
FERC	Federal Energy Regulatory Commission
FTA countries	countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP	generally accepted accounting principles in the United States
Henry Hub	the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
IPM agreements	integrated production marketing agreements in which the gas producer sells to us gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu	million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpa	million tonnes per annum
non-FTA countries	countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC	U.S. Securities and Exchange Commission
SOFR	Secured Overnight Financing Rate
SPA	LNG sale and purchase agreement
TBtu	trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2021, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:

Unless the context requires otherwise, references to “CCH,” the “Company,” “we,” “us,” and “our” refer to Cheniere Corpus Christi Holdings, LLC and its consolidated subsidiaries.

2

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

•statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction facility, pipeline facility or other projects, or any expansions or portions thereof, by certain dates, or at all; 

•statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;

•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;

•statements regarding our future sources of liquidity and cash requirements;

•statements relating to the construction of our Trains and pipeline, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;

•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total natural gas liquefaction or storage capacities that are, or may become, subject to contracts;

•statements regarding counterparties to our commercial contracts, construction contracts and other contracts;

•statements regarding our planned development and construction of additional Trains and pipelines, including the financing of such Trains and pipelines;

•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;

•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;

•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;

•statements regarding the COVID-19 pandemic and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing creditworthiness of our contractual counterparties, any disruptions in our operations or construction of our Trains and the health and safety of Cheniere’s employees, and on our customers, the global economy and the demand for LNG;

•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

3

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

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.

4

PART I

ITEMS 1. AND 2.         BUSINESS AND PROPERTIES

General

Cheniere Corpus Christi Holdings, LLC (“CCH”) is a Delaware limited liability company formed in September 2014 by Cheniere Energy, Inc. (“Cheniere”). We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

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

We operate a natural gas liquefaction and export facility (the “Liquefaction Facilities”) and operate a 21.5-mile natural gas supply pipeline that interconnects the natural gas liquefaction and export facility at Corpus Christi (the “Corpus Christi LNG terminal”) with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries Corpus Christi Liquefaction, LLC (“CCL”) and Cheniere Corpus Christi Pipeline, L.P. (“CCP”), respectively. We operate three Trains for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project also includes 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.

Our customer arrangements provide us with significant, stable and long-term cash flows. As further discussed below, we contract our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted approximately 75% of the total production capacity with approximately 18 years of weighted average remaining life as of December 31, 2021. For further discussion of the contracted future cash flows under our revenue arrangements, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.

We remain focused on operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Corpus Christi LNG terminal, which provides opportunity for further liquefaction capacity expansion. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we can make a final investment decision (“FID”).

Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. Cheniere published its 2020 Corporate Responsibility (“CR”) report, which details our strategy and progress on ESG issues, as well as our efforts on integrating climate considerations into our business strategy and taking a leadership position on increased environmental transparency, including conducting a climate scenario analysis and our plan to provide LNG customers with Cargo Emission Tags. In August 2021, Cheniere also announced a peer-reviewed LNG life cycle assessment study which allows for improved greenhouse gas emissions assessment, which was published in the American Chemical Society Sustainable Chemistry & Engineering Journal. Cheniere’s CR report is available at cheniere.com/IMPACT. Information on our website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K.

5

Our Business Strategy

Our primary business strategy for the Liquefaction Project is to develop, construct and operate assets supported by long-term, fixed fee contracts. We plan to implement our strategy by:

•safely, efficiently and reliably operating and maintaining our assets;

•procuring natural gas and pipeline transport capacity to our facility;

•commencing commercial delivery for our long-term SPA customers, of which we have initiated for nine of ten third party long-term SPA customers as of December 31, 2021;

•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 environmental solutions.

Our Business

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

Our Liquefaction Project

We operate three Trains and two marine berths at the Liquefaction Project. We commenced commercial operating activities of Trains 1, 2 and 3 of the Liquefaction Project in February 2019, August 2019 and March 2021, respectively.

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

	FERC Approved Volume		DOE Approved Volume
	(in Bcf/yr)	(in mtpa)	(in Bcf/yr)	(in mtpa)
FTA countries	875.16	17	875.16	17
Non-FTA countries	875.16	17	767 (1)	15

(1)The authorization for an additional 108.16 Bcf/yr (approximately 2 mtpa) of natural gas is currently pending.

Pipeline Facilities

In November 2019, the FERC authorized CCP to construct and operate the pipeline for the additional facilities for the liquefaction and export of domestically-produced natural gas (“Corpus Christi Stage 3”) at the existing Liquefaction Project and pipeline location, which is being developed by a wholly owned subsidiary of Cheniere that is not owned or controlled by us. The pipeline will be designed to transport 1.5 Bcf/d of natural gas feedstock required by Corpus Christi Stage 3 from the existing regional natural gas pipeline grid.

Natural Gas Supply, Transportation and Storage

CCL has secured natural gas feedstock for the Corpus Christi LNG terminal through traditional long-term natural gas supply and IPM agreements. Additionally, to ensure that CCL is able to transport and manage the natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third-parties.

6

Customers

Information regarding our customer contracts can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.

The following table shows customers with revenues of 10% or greater of total revenues from external customers:

	Percentage of Total Revenues from External Customers
	Year Ended December 31,
	2021	2020	2019
Endesa Generación, S.A. (which subsequently assigned its SPA to Endesa S.A.) and Endesa S.A.	21%	31%	57%
PT Pertamina (Persero)	16%	16%	23%
Naturgy LNG GOM, Limited	15%	14%	—%

All of the above customers are long-term SPA customers that contribute to our LNG revenues.

Governmental Regulation

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

Federal Energy Regulatory Commission

The design, construction, operation, maintenance and expansion of the Liquefaction Project, the import or export of LNG and the purchase and transportation of natural gas in interstate commerce through the Corpus Christi Pipeline are highly regulated activities subject to the jurisdiction of the FERC pursuant to the Natural Gas Act of 1938, as amended (the “NGA”). Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.

 The FERC’s authority to regulate interstate natural gas pipelines and the services that they provide generally includes regulation of:

•rates and charges, and terms and conditions for natural gas transportation, storage and related services;

•the certification and construction of new facilities and modification of existing facilities;

•the extension and abandonment of services and facilities;

•the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;

•the acquisition and disposition of facilities;

•the initiation and discontinuation of services; and

•various other matters.

Under the NGA, our pipeline is not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including its own marketing affiliate. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified 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, FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for FERC’s decision-making process, which would now include, among other things, reasonably foreseeable greenhouse gas emissions that may be attributable to the project and the project’s impact on environmental justice communities. These FERC changes are the first revision in more than 20 years to FERC’s policy for the certification of new interstate natural gas pipeline projects under

7

Section 7 of the NGA. The updated Policy Statement has more limited applicability to LNG projects regulated under Section 3 of the Natural Gas Act. While the impact on our future projects and expansions is not known at this time, we do not expect it to have a material adverse effect on our operations.

We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate granted by the FERC with the issuance of our Certificate of Public Convenience and Necessity (“Certificate”) to our marketing affiliates. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.

In order to site, construct and operate the Corpus Christi LNG terminal, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct, amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law.

In December 2014, the FERC issued an order granting CCL authorization under Section 3 of the NGA to site, construct and operate Trains 1 through 3 of the Liquefaction Project and issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing construction and operation of the Corpus Christi Pipeline (the “December 2014 Order”). A party to the proceeding requested a rehearing of the December 2014 Order, and in May 2015, the FERC denied rehearing (the “Order Denying Rehearing”). The party petitioned the relevant Court of Appeals to review the December 2014 Order and the Order Denying Rehearing; that petition was denied on November 4, 2016. In June of 2018, CCL and CCP filed an application with the FERC for authorization under Section 3 of the NGA to site, construct and operate Corpus Christi Stage 3 at the existing Liquefaction Project and pipeline location, which is being developed by a wholly owned subsidiary of Cheniere that is not owned or controlled by us. In November 2019, the FERC authorized CCP to construct and operate the pipeline for Corpus Christi Stage 3. The order is not subject to appellate court review. In 2020, FERC authorized CCP to construct and operate a portion of Corpus Christi Stage 3 (Sinton Compressor Station Unit No. 1) on an interim basis independently from the remaining Corpus Christi Stage 3 facilities, which received FERC approval for in-service in December 2020.

On September 27, 2019, CCL filed a request with the FERC pursuant to Section 3 of the NGA, requesting authorization to increase the total LNG production capacity of the terminal from currently authorized levels to an amount which reflects more accurately the capacity of the facility based on enhancements during the engineering, design and construction process, as well as operational experience to date. The requested authorizations do not involve construction of new facilities. Corresponding applications for authorization to export the incremental volumes were also submitted to the DOE. The DOE issued Orders granting authorization to export LNG to FTA countries in April 2020. The DOE authorization for export to non-FTA countries is still pending. In October 2021, the FERC issued its Orders Amending Authorization under Section 3 of the NGA.

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

All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

Several other material governmental and regulatory approvals and permits will be required throughout the life of the Liquefaction Project. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of the Liquefaction Project. For example, throughout the life of the Liquefaction Project, we are subject to regular reporting requirements to the FERC, the Department of

8

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 have 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 Our Liquefaction Project. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.

Under Section 3 of the NGA applications for exports of natural gas to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest.

Pipeline and Hazardous Materials Safety Administration

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

PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $225,000 per day per violation, with a maximum administrative civil penalty of approximately $2.25 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 (the “PSD Permit”). These two permits are issued by the TCEQ.

Commodity Futures Trading Commission (“CFTC”)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in those markets. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, including the speculative position limit rules which became effective on March 15, 2021 and have a phased-in compliance date that began on January 1, 2022. Given the recent enactment of the speculative position limit rules, as well as the impact of other rules and regulations under the Dodd-Frank Act, the impact of such rules and regulations on our business continues to be uncertain.

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

9

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 require significant expenditures for compliance, can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.

Clean Air Act

The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by any such requirements.

In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of greenhouse gas (“GHG”) emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules were largely stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and additional amendments to new source performance standards for the oil and gas industry on September 14 and 15, 2020. On November 15, 2021, the EPA proposed new regulations to reduce methane emissions from both new and existing sources within the Crude Oil and Natural Gas source category. The proposed regulations if finalized, would result in more stringent requirements for new sources, expand the types of new sources covered, and for the first time, establish emissions guidelines for existing sources in the Crude Oil and Natural Gas source category. We are supportive of regulations reducing GHG emissions over time.

From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. In addition, many states have already taken regulatory action to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs, the imposition of taxes or fees related to GHG emissions or additional operating restrictions and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

10

Coastal Zone Management Act (“CZMA”)

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

Clean Water Act

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

Resource Conservation and Recovery Act (“RCRA”)

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

Protection of Species, Habitats and Wetlands

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

It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe that our operations, or the construction and operations of our Liquefaction Project, will be materially and adversely affected by such regulatory actions.

Market Factors and Competition

Market Factors

Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sale of LNG by Cheniere Marketing International LLP (“Cheniere Marketing”), or development of 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 rate of fuel switching for power generation from coal, nuclear or oil to natural gas, economic growth in developing countries and other related factors such as the effects of the COVID-19 pandemic. 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. Players around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Currently, significant amounts of money are being invested across Europe and Asia in natural gas projects under construction, and more continues to be earmarked to planned projects globally. Some examples include India’s commitment to invest over $60 billion to usher a gas-based economy, around $100 billion earmarked for Europe’s gas infrastructure buildout, and China’s hundreds of billions all along the natural gas value chain. We highlight regasification capacity, which will not only expand existing import capacities in rapidly growing markets like China and India, but also add new import markets all over the

11

globe, raising the total number of important markets to approximately 60 by 2030 from 43 in 2020 and just 15 markets as recently as 2005.

As a result of these dynamics, global demand for natural gas is projected by the International Energy Agency to grow by approximately 20 trillion cubic feet (“Tcf”) between 2020 and 2030 and 33 Tcf between 2020 and 2040. LNG’s share is seen growing from about 11% in 2020 to about 12% of the global gas market in 2030 and 14% in 2040. Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 57%, from 366.6 mtpa, or 17.6 Tcf, in 2020, to 576.5 mtpa, or 27.7 Tcf, in 2030 and to 734.5 mtpa or 35.3 Tcf in 2040. WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 517 mtpa in 2030, declining to 456 mtpa in 2040. This could result in a market need for construction of an additional approximately 60 mtpa of LNG production by 2030 and about 279 mtpa by 2040. As a cleaner burning fuel with far lower emissions than coal or liquid fuels in power generation, we expect gas and LNG to play a central role in balancing grids and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Project is competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

Our LNG terminal business has limited exposure to oil price movements as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes.  We have contracted approximately 75% of the total production capacity from the Liquefaction Project, with approximately 18 years of weighted average remaining life as of December 31, 2021, which includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes. 

Competition

When CCL needs to replace any existing SPA or enter into new SPAs, CCL will compete on the basis of price per contracted volume of LNG with other natural gas liquefaction projects throughout the world, including our affiliate Sabine Pass Liquefaction, LLC (“SPL”), which operates six Trains at a natural gas liquefaction facility in Cameron Parish, Louisiana. Revenues associated with any incremental volumes of the Liquefaction Project, including those made available to Cheniere Marketing, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to LNG markets than us.

Subsidiaries

Our assets are generally 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 Cheniere and its subsidiaries for operations, maintenance and management services. As of January 31, 2022, Cheniere and its subsidiaries had 1,550 full-time employees, including 333 employees who directly supported the Liquefaction Project. See Note 12—Related Party Transactions of our Notes to Consolidated Financial Statements for a discussion of the services agreements pursuant to which general and administrative services are provided to CCL and CCP. 

Available Information

Our principal executive offices are located at 700 Milam Street, Suite 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We 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 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

12

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 factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

The risk factors in this report are grouped into the following categories: 

•Risks Relating to Our Financial Matters;

•Risks Relating to Our Operations and Industry; and

•Risks Relating to Regulations.

Risks Relating to Our Financial Matters

Our existing level of cash resources and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

As of December 31, 2021, we had no cash and cash equivalents, $44 million of restricted cash and cash equivalents, $589 million of available commitments under our $1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) and $10.4 billion of total debt outstanding on a consolidated basis (before unamortized debt issuance costs). We incur, and will incur, significant interest expense relating to the assets at the Corpus Christi LNG terminal. Our ability to refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our CCH Working Capital Facility to fund our capital expenditures. If any of the lenders in the syndicates backing our CCH Working Capital Facility was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

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

Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2021, we had SPAs with a total of ten different third party customers. While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

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

Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer

13

arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.

Our efforts to manage commodity and financial risks through derivative instruments, including our IPM agreements, could adversely affect our results of operations and financial condition.

We use derivative instruments to manage commodity, currency and financial market risks. The extent of our derivative position at any given time depends on our assessments of the markets for these commodities and related exposures. We currently account for all derivative sat fair value, with immediate recognition of changes in the fair value in earnings. As described in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations, our net loss of $180 million for the year ended December 31, 2021 was primarily due to derivative losses, with substantially all of such losses relating 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 reported results of operations, particularly in periods of significant commodity, currency or financial market variability, or as a result of ineffectiveness of these contracts. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, our liquidity may be adversely impacted by the cash margin requirements of the commodities exchanges or the failure of a counterparty to perform in accordance with a contract.

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 completion of our Liquefaction Project, damage to our Liquefaction Project and increased insurance costs, all of which could adversely affect us.

Hurricane Harvey in 2017 and Winter Storm Uri in 2021 caused interruptions or temporary suspension in construction or operations at our Liquefaction Project or caused minor damage to our Liquefaction Project. In August 2020, we entered into an arrangement with our affiliate to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers from the other facility in the event operational conditions impact operations at the Corpus Christi LNG terminal or at our affiliate’s terminal. During the years ended December 31, 2021 and 2020, four TBtu and 17 TBtu, respectively, were loaded at our facilities for our affiliate pursuant to this agreement. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Corpus Christi LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of our other facilities and increase our insurance premiums. The U.S. Global Change Research Program has reported that the U.S.’s energy and transportation systems are expected to be increasingly disrupted by climate change and extreme weather events. An increase in frequency and severity of extreme weather events such as storms, floods, fires and rising sea levels could have an adverse effect on our operations.

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

We depend upon third party pipelines and other facilities that provide gas delivery options to our Liquefaction Project. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted. Any significant disruption to our natural gas supply 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.

14

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. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas 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 Corpus Christi LNG terminal and the operation of the Corpus Christi Pipeline are, and will be, subject to the inherent risks associated with these types of operations, 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. 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. 

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

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:

•competitive liquefaction capacity in North America;

•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;

•insufficient LNG tanker capacity;

•weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand. For example, LNG procurement in Japan rose dramatically in 2011 and several years thereafter following a tsunami that caused extensive destruction to its nuclear power infrastructure;

•reduced demand and lower prices for natural gas;

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

•decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;

•cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;

•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;

•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

15

•political conditions in natural gas producing regions;

•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;

•adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and

•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

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

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

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

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

In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from the Liquefaction Project also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Project in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Project, may also be impacted by an increase in natural gas prices in the United States.

As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or to the United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from the United States generally, or to the Corpus Christi LNG terminal or from the Liquefaction Project specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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

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

•increases in worldwide LNG production capacity and availability of LNG for market supply;

•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;

16

•increases in the cost to supply natural gas feedstock to our Liquefaction Project;

•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;

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

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

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

A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Facilities, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.

The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our pipeline, liquefaction and shipping operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third-parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Facilities. 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 Facilities suffer similar concurrent attacks, the Liquefaction Facilities may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A cyber attack involving our business or operational control, systems or related infrastructure, or that of third party pipelines with which we do business, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.

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

Our facilities at the Corpus Christi LNG terminal are critical infrastructure and have continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including the Delta and Omicron variants, has had no adverse impact on our on-going operations during this time, the risk of future variants is unknown. While we believe we can continue to mitigate any significant adverse impact to our employees and operations at our critical facilities related to the virus in its current form, the outbreak of a more potent variant in the future at one or more of our facilities could adversely affect our operations.

We are entirely dependent on Cheniere, including employees of Cheniere and its subsidiaries, for key personnel, and the unavailability of skilled workers or our 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 January 31, 2022, Cheniere and its subsidiaries had 1,550 full-time employees, including 333 employees who directly supported the Liquefaction Project. We have contracted with subsidiaries of Cheniere to provide the personnel necessary for the construction and operation of the Liquefaction Project. We depend on Cheniere’s subsidiaries hiring and retaining personnel sufficient to provide support for the Liquefaction Project. Cheniere competes with other liquefaction projects in the United States and globally, other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. We also compete with any other project Cheniere is developing, including the liquefaction facility operated by SPL (the “SPL Project”), for the time and expertise of Cheniere’s personnel. Further, we and Cheniere face competition for these highly skilled employees in the immediate vicinity of the Liquefaction Project and more generally from the Gulf Coast hydrocarbon processing and construction industries.

Our executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a

17

material adverse effect on our business. In addition, our future success will depend in part on our ability to engage, and Cheniere’s ability to attract and retain, additional qualified personnel.

A shortage in the labor pool of skilled workers, remoteness of our site locations or other general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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

We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, Cheniere Marketing has entered into an SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers. These agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand. In addition, Cheniere is currently operating the SPL Project in Cameron Parish, Louisiana, and is developing related facilities and a second natural gas pipeline at a site adjacent to the Liquefaction Project, and may continue to enter into commercial arrangements with respect to any future expansion of the Liquefaction Project.

We have or will have numerous contracts and commercial arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements with one or more Cheniere-affiliated entities as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.

We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminate their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.

Risks Relating to Regulations

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipeline and the export of LNG could impede operations and construction and could have a material adverse effect on us.

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

To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the three Trains and related facilities of the Liquefaction Project, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Corpus Christi Pipeline. To date, the DOE has also issued orders under Section 4 of the NGA authorizing CCL to export domestically produced LNG. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipeline on land owned by third parties. If we were to lose these rights or be required to relocate our pipeline, our business could be materially and adversely affected.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with such conditions, or our inability to obtain and maintain existing or newly imposed approvals and permits, filings, which 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 the siting of LNG facilities due to safety, environmental or security concerns, could impede the operation and construction of our infrastructure. 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.

18

Our Corpus Christi Pipeline and its FERC gas tariff are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.

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

In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.3 million per day for each violation.

Existing and future 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 and pipeline, including FERC and PHMSA, to issue compliance orders, 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 or to 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.

In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule requiring annual reporting of GHG emissions from stationary sources in a variety of industries. In 2010, the EPA expanded the rule to include reporting obligations for LNG terminals. In addition, the EPA has defined GHG emissions thresholds that would subject GHG emissions from new and modified industrial sources to regulation if the source is subject to PSD Permit requirements due to its emissions of non-GHG criteria pollutants. While the EPA subsequently took a number of additional actions primarily relating to GHG emissions from the electric power generation and the oil and gas exploration and production industries, those rules were largely stayed or repealed during the Trump Administration including by amendments adopted by the EPA on February 23, 2018 and additional amendments to new source performance standards for the oil and gas industry on September 14 and 15, 2020. On November 15, 2021, the EPA proposed new regulations to reduce methane emissions from both new and existing sources within the Crude Oil and Natural Gas source category. The proposed regulations, if finalized, would result in more stringent requirements for new sources, expand the types of new sources covered, and for the first time, establish emissions guidelines for existing sources in the Crude Oil and Natural Gas source category. In addition, other federal and state initiatives may be considered in the future to address GHG emissions through, for example, United States treaty commitments, direct regulation, market-based regulations such as a carbon emissions tax or cap-and-trade programs or clean energy 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. We are supportive of regulations reducing GHG emissions over time.

Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from the Corpus Christi LNG terminal or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may

19

require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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 maintain pipeline integrity testing programs that are intended to assess 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 $2.3 million.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

ITEM 3.     LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

ITEM 4.    MINE SAFETY DISCLOSURE

Not applicable.

20

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 2019 items and variance drivers between the year ended December 31, 2020 as compared to December 31, 2019 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, 2020.

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 Energy, Inc. (“Cheniere”) to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We operate a 21.5-mile natural gas supply pipeline (the “Corpus Christi Pipeline”) that interconnects the natural gas liquefaction and export facility near Corpus Christi, Texas (the “Corpus Christi LNG terminal”), and three natural gas liquefaction Trains, with several interstate natural gas pipelines (collectively, the “Liquefaction Project”). For further discussion of our business, see Items 1. and 2. Business and Properties.

Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted approximately 75% of the total production capacity from the Liquefaction Project with approximately 18 years of weighted average remaining life as of December 31, 2021. Our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases and transportation and liquefaction fuel to produce LNG, thus limiting our exposure to fluctuations in U.S. natural gas prices. We believe that continued global demand for natural gas and LNG, as further described in Items 1. and 2. Business and Properties—Market Factors and Competition, will provide a foundation for additional growth in our business in the future.

21

Overview of Significant Events

Our significant events since January 1, 2021 and through the filing date of this Form 10-K include the following:

•As of February 18, 2022, approximately 450 cumulative LNG cargoes totaling over 30 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

•In August 2021, we issued an aggregate principal amount of $750 million of fully amortizing 2.742% Senior Secured Notes due 2039 (the “2.742% CCH Senior Secured Notes”). The proceeds of the 2.742% CCH Senior Secured Notes, net of related fees, costs and expenses, were used to prepay a portion of the principal amount outstanding under our amended and restated term loan credit facility (the “CCH Credit Facility”).

•On March 26, 2021, substantial completion of Train 3 of the Liquefaction Project was achieved.

•CCL entered into an SPA for portfolio volumes aggregating approximately 7 million tonnes of LNG to be delivered between 2021 and 2032.

Market Environment

The LNG market in 2021 saw unprecedented price increases across all natural gas and LNG benchmarks. Colder than normal temperatures early in the year, concerns over low natural gas and LNG inventories, low additional LNG supply availability and forecasts of a cold 2021/2022 winter in Europe and Asia increased price volatility and supported a run-up in natural gas and LNG prices. These conditions were exacerbated by rising coal and carbon prices in Europe, persistent under-performance from some non-US LNG supply projects and reduced Russian pipe exports to Europe, precipitating the early stages of a price-based energy crisis in Europe.

High demand for LNG during the recovery from the initial stages of the COVID-19 pandemic resulted in intense competition for supplies between the Atlantic and Pacific basins. Global LNG demand grew by about approximately 5% from the comparable 2020 period, adding an additional 18 mtpa to the overall market. A robust economic recovery in China powered an 8% increase in Asia’s LNG demand of approximately 19.5 million tonnes from the comparable 2020 period. This led to competition for supplies between Asia, Europe and Latin America, exposing the supply constraints that the industry has had while emerging from the pandemic. In turn, this drove international natural gas and LNG prices higher and widened the price spreads between the U.S. and other parts of the world. As an example, the Dutch Title Transfer Facility (“TTF”) monthly settlement prices averaged $14.4/MMBtu in 2021, approximately 375% higher than the $3.0/MMBtu average in 2020, and the TTF monthly settlement prices averaged $28.9/MMBtu in the fourth quarter of 2021, approximately 512% higher than the $4.72/MMBtu average in the fourth quarter of 2020. Similarly, the 2021 average settlement price for the Japan Korea Marker (“JKM”) increased 292% year-over-year to an average of $15.0/MMBtu in 2021, and the fourth quarter of 2021 average settlement price for the JKM increased over 412% year-over-year to an average of $27.9/MMBtu. This extreme price increase triggered a strong supply response from the U.S., which played a significant role in balancing the global LNG market. The U.S. exported 70 million tonnes of LNG in 2021, a gain of approximately 49% from the comparable 2020 period, as the market continued to pull on supplies from our facilities and those of our competitors. Exports from our Liquefaction Project reached 14 million tonnes, representing over 20% of the gain in the U.S. total over the same period.

22

Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded (including both operational and commissioning volumes) during the years ended December 31, 2021 and 2020:

(1) The year ended December 31, 2021 excludes four TBtu that were loaded at our affiliate’s facility.

Net income (loss)

Our consolidated net loss was $180 million for the year ended December 31, 2021, compared to net income of $63 million for the year ended December 31, 2020. The $243 million decrease in net income was mainly due to the increase in commodity derivatives losses from changes in fair value and settlements of $1.2 billion between the periods, as further described below, and non-recurrence of $435 million in revenues recognized on LNG cargoes for which customers notified us that they would not take delivery, partially offset by increased margin on LNG delivered as a result of increases in both volume delivered and gross margin on LNG delivered per MMBtu.

Substantially all derivative losses relate to the use of commodity derivative instruments related to our IPM agreements, which are indexed to international LNG prices. While operationally we utilize commodity derivatives to mitigate price volatility for commodities procured or sold over a period of time, as a result of significant appreciation in forward international LNG commodity curves during the year ended December 31, 2021, we recognized approximately $1.2 billion of non-cash unfavorable changes in fair value attributed to positions related to IPM agreements.

Derivative instruments, which in addition to managing exposure to commodity-related marketing and price risks are utilized to manage exposure to changing interest rates volatility, are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions being economically hedged are accounted for under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.

23

Revenues

	Year Ended December 31,
(in millions, except volumes)	2021		2020		Variance ($)
LNG revenues	$	3,907	$	2,046	$	1,861
LNG revenues—affiliate	1,887		483		1,404
Total revenues	$	5,794	$	2,529	$	3,265
LNG volumes recognized as revenues (in TBtu) (1)	738		410		328

(1)Excludes volume associated with cargoes for which customers notified us that they would not take delivery. During the year ended December 31, 2021, includes four TBtu that were loaded at our affiliate’s facility.

Total revenues increased by approximately $3.3 billion during the year ended December 31, 2021 from the year ended December 31, 2020, primarily due to increased revenues per MMBtu as a result of variable fees that are received in addition to fixed fees when the customers take delivery of scheduled cargoes as opposed to exercising their contractual right to not take delivery, as well as from increases in Henry Hub prices. Additionally, there was higher volumes of LNG delivered between the periods due to the delivery of all available volume of LNG in 2021 and as a result of production from the third Train which achieved substantial completion on March 26, 2021.

Also included in LNG revenues is the sale of certain unutilized natural gas procured for the liquefaction process and gains and losses from certain commodity derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized revenues of $196 million and $171 million during the years ended December 31, 2021 and 2020, respectively, related to these transactions.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the years ended December 31, 2021 and 2020, we realized offsets to LNG terminal costs of $143 million and $32 million corresponding to 28 TBtu and 6 TBtu of LNG, respectively, that were related to the sale of commissioning cargoes.

Operating costs and expenses

	Year Ended December 31,
(in millions)	2021		2020		Variance ($)
Cost of sales	$	4,326	$	901	$	3,425
Cost of sales—affiliate	50		30		20
Cost of sales—related party	146		114		32
Operating and maintenance expense	423		347		76
Operating and maintenance expense—affiliate	106		90		16
Operating and maintenance expense—related party	9		6		3
General and administrative expense	7		7		—
General and administrative expense—affiliate	28		20		8
Depreciation and amortization expense	420		342		78
Impairment expense and loss on disposal of assets	2		1		1
Total operating costs and expenses	$	5,517	$	1,858	$	3,659

Total operating costs and expenses increased between the year ended December 31, 2021 compared to the year ended December 31, 2020, primarily as a result of increased cost of sales. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. Cost of sales (including related party) increased during the year ended December 31, 2021 from the comparable 2020 period, primarily as a result of increased cost of natural gas feedstock as a result of higher US natural gas prices and increased volume of LNG delivered, as well as unfavorable changes in our commodity derivatives to secure natural gas feedstock for the Liquefaction Project driven by unfavorable shifts in international forward commodity curves, as discussed above under Net income (loss). Cost of sales—affiliate increased during the year ended December 31, 2021 as a result of the cost of cargoes procured from our affiliate to fulfill our commitments to our long-term customers during operational constraints.

24

Operating and maintenance expense (including affiliate and related party) primarily includes costs associated with operating and maintaining the Liquefaction Project. Operating and maintenance expense (including affiliate and related party) increased between the years ended December 31, 2021 and 2020 primarily due to increased natural gas transportation and storage capacity demand charges, increased third party service and maintenance contract costs and increased payroll and benefit costs of operations personnel, generally as a result of an additional Train that was in operation between the periods. Operating and maintenance (including affiliates) also includes insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the year ended December 31, 2021 from the comparable period in 2020 as a result of commencing operations of Train 3 of the Liquefaction Project in March 2021.

Other expense (income)

	Year Ended December 31,
(in millions)	2021		2020		Variance ($)
Interest expense, net of capitalized interest	$	447	$	365	$	82
Loss on modification or extinguishment of debt	9		9		—
Interest rate derivative loss, net	1		233		(232)
Other income (expense), net	—		1		(1)
Total other expense	$	457	$	608	$	(151)

Interest expense, net of capitalized interest increased during the year ended December 31, 2021 compared to the comparable period in 2020, primarily because the construction of the third train of the Liquefaction Project was completed on March 26, 2021, which eliminated the portion of total interest costs that was eligible for capitalization. During the years ended December 31, 2021 and 2020, we incurred $473 million and $484 million of total interest cost of which we capitalized $26 million and $119 million, respectively. Capitalized interest primarily related to interest costs incurred to construct the assets of the Liquefaction Project.

Interest rate derivative loss, net decreased during the year ended December 31, 2021 compared to the comparable 2020 period, primarily due to the settlement of certain outstanding derivatives in August 2020 that were in an unfavorable position and a favorable shift in the long-term forward LIBOR curve between the periods.

Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include our debt offerings. The table below provides a summary of our available liquidity as of December 31, 2021 (in millions). Future material sources of liquidity are discussed below.

	December 31, 2021
Restricted cash and cash equivalents designated for the Liquefaction Project	$	44
Available commitments under the $1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) (1)	589
Total available liquidity	$	633

(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of the CCH Working Capital Facility as of December 31, 2021. See Note 10—Debt of our Notes to Consolidated Financial Statements for additional information on the CCH Working Capital Facility and other debt instruments.

Our liquidity position subsequent to December 31, 2021 is driven by future sources of liquidity and future cash requirements. Future sources of liquidity are expected to be composed of (1) cash receipts from executed contracts, under which we are contractually entitled to future revenues, and (2) additional sources of liquidity, from which we expect to receive cash although the cash is not underpinned by executed contracts. Future cash requirements are expected to be composed of (1) cash payments under executed contracts, under which we are contractually obligated to make payments, and (2) additional cash requirements, under which we expect to make payments although we are not contractually obligated to make the payments under executed contracts. Future sources of liquidity and future cash requirements are estimates based on management’s assumptions and currently known market conditions and other factors as of December 31, 2021.

25

Supplemental Guarantor Information

The 7.000% Senior Secured Notes due 2024, 5.875% Senior Secured Notes due 2025, 5.125% Senior Secured Notes due 2027, 3.700% Senior Secured Notes due 2029, and the series of Senior Secured Notes due 2039 with weighted average rate of 3.72% (collectively, the “CCH Senior Notes”) are jointly and severally guaranteed by each of our consolidated subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “Guarantor” and collectively, the “Guarantors”).

The Guarantors’ guarantees are full and unconditional, subject to certain release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of all or substantially all of the capital stock or the assets of the Guarantors, (2) the designation of the Guarantor as an “unrestricted subsidiary” in accordance with the indentures governing the CCH Senior Notes (the “CCH Indentures”), (3) upon the legal defeasance or covenant defeasance or discharge of obligations under the CCH Indentures and (4) the release and discharge of the Guarantors pursuant to the Common Security and Account Agreement. In the event of a default in payment of the principal or interest by us, whether at maturity of the CCH Senior Notes or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the Guarantors to enforce the guarantee.

The rights of holders of the CCH Senior Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or federal or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

Summarized financial information about us and the Guarantors as a group is omitted herein because such information would not be materially different from our Consolidated Financial Statements.

Future Sources and Uses of Liquidity

Future Sources of Liquidity under Executed Contracts

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration under our SPAs which has not yet been recognized as revenue. This future consideration is in most cases not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2021. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed contracts as of December 31, 2021 (in billions):

	Estimated Revenues Under Executed Contracts by Period (1)
	2022		2023 - 2026		Thereafter		Total
LNG revenues (fixed fees) (2)	$	2.0	$	7.5	$	23.2	$	32.7
LNG revenues (variable fees) (2) (3)	2.6		8.4		29.7		40.7
Total	$	4.6	$	15.9	$	52.9	$	73.4

(1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2021. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.

(2)LNG revenues (including $1.1 billion and $1.7 billion of fixed fees and variable fees, respectively, from affiliates) exclude revenues from contracts with original expected durations of one year or less. Fixed fees are fees that are due to us regardless of whether a customer exercises their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.

(3)LNG revenues (variable fees, including affiliate) reflect the assumption that customers elect to take delivery of all cargoes made available under the contract. LNG revenues (variable fees, including affiliate) are based on estimated

26

forward prices and basis spreads as of December 31, 2021. The pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt.

LNG Revenues

We have contracted approximately 75% of the total production capacity from the Liquefaction Project through long-term SPAs, with approximately 18 years of weighted average remaining life as of December 31, 2021. The majority of the contracted capacity is comprised of fixed-price, long-term SPAs we have executed with third parties to sell LNG from Trains 1 through 3 of the Liquefaction Project. Under the SPAs, the customers purchase LNG on a free on board (“FOB”) basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. The variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases and variable transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. In aggregate, the minimum annual fixed fee portion to be paid by the third-party SPA customers is approximately $1.8 billion for Trains 1 through 3 of the Liquefaction Project. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of BBB+, Baa1 and BBB+ by S&P Global Ratings, Moody’s Corporation and Fitch Ratings, respectively. A discussion of revenues under our SPAs can be found in Note 11—Revenues from Contracts with Customers of our Notes to Consolidated Financial Statements.

In addition to the third party SPAs discussed above, we have also executed SPAs with Cheniere Marketing International LLP (“Cheniere Marketing”) to sell (1) approximately 15 TBtu per annum of LNG with a term through 2043 (included in the table above), (2) any LNG produced by the Liquefaction Project in excess of that required for other customers at Cheniere Marketing’s option, of which any committed transactions are included in the table above, and (3) approximately 44 TBtu of LNG with a maximum term up to 2026 associated with our IPM agreement with EOG Resources, Inc.

Additional Future Sources of Liquidity

Available Commitments under Credit Facilities

As of December 31, 2021, we had $589 million in available commitments under the CCH Working Capital Facility, subject to compliance with the covenants, to potentially meet liquidity needs. Our credit facilities mature between 2023 and 2024.

Equity Contribution Agreement

In May 2018, we amended and restated the existing equity contribution agreement with Cheniere (the “Equity Contribution Agreement”) pursuant to which Cheniere agreed to provide cash contributions up to approximately $1.1 billion, not including $2.0 billion previously contributed under the original equity contribution agreement. Full discussion of the Equity Contribution Agreement can be found in Note 12—Related Party Transactions of our Notes to Consolidated Financial Statements.

27

Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts

We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures under executed contracts as of December 31, 2021 (in billions):

	Estimated Payments Due Under Executed Contracts by Period (1)
	2022		2023 - 2026		Thereafter		Total
Purchase obligations (2):
Natural gas supply agreements (3)	$	3.3	$	5.1	$	1.3	$	9.7
Natural gas transportation and storage service agreements (4)	0.2		0.8		2.3		3.3
Other purchase obligations (5)	—		0.1		0.5		0.6
Total	$	3.5	$	6.0	$	4.1	$	13.6

(1)Excludes contracts for which conditions precedent have not been met. Agreements in force as of December 31, 2021 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2021. The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.

(2)Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. As project milestones and other conditions precedent are achieved, our obligations are expected to increase accordingly. We include contracts for which we have an early termination option if the option is not currently expected to be exercised.

(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2021. Natural gas supply agreements include payments under IPM agreements, which are based on global gas market prices less fixed liquefaction fees and certain costs incurred by us.

(4)Includes $0.1 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements.

(5)Includes $0.5 billion of purchase obligations to affiliates under services agreements.

Natural Gas Supply, Transportation and Storage Service Agreements

We have secured natural gas feedstock for the Corpus Christi LNG terminal through long-term natural gas supply and IPM agreements. Under our IPM agreements, we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While IPM agreements are not revenue contracts for accounting purposes, the payment structure for the purchase of natural gas under the IPM agreements generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global LNG market price paid for the natural gas feedstock purchase.

As of December 31, 2021, we have secured 87% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Project during 2022. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2022. Natural gas supply is generally secured on an indexed pricing basis, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied conditions precedent as of December 31, 2021, we have secured up to 2,642 TBtu of natural gas feedstock through agreements with remaining terms that range up to 10 years. A discussion of our natural gas supply and IPM agreements can be found in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements.

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

28

Additional Future Cash Requirements for Operations and Capital Expenditures

Corporate Activities

We have contracts with subsidiaries of Cheniere for operations, maintenance and management services. Cheniere and its subsidiaries’ full-time employee headcount was 1,550, including 333 employees who directly supported the Liquefaction Project operations as of January 31, 2022. Full discussion of our operations, maintenance and management agreements can be found in Note 12—Related Party Transactions of our Notes to Consolidated Financial Statements.

Financially Disciplined Growth

Our affiliates hold significant land positions at the Corpus Christi LNG terminal, which provides potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. We expect that any potential future expansion at the Corpus Christi LNG terminal would increase cash requirements to support expanded operations, although expansion could be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.

Future Cash Requirements for Financing under Executed Contracts

We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2021 (in billions):

	Estimated Payments Due Under Executed Contracts by Period (1)
	2022		2023 - 2026		Thereafter		Total
Debt (2)	$	0.4	$	4.4	$	5.6	$	10.4
Interest payments (2)	0.5		1.3		1.0		2.8
Total	$	0.9	$	5.7	$	6.6	$	13.2

(1)The estimates above reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2021. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.

(2)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2021. Debt and interest payments do not contemplate repurchases, repayments and retirements that we expect to make prior to contractual maturity. See further discussion in Note 10—Debt of our Notes to Consolidated Financial Statements.

Debt

As of December 31, 2021, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $8.5 billion and credit facilities with an aggregate outstanding balance of $2.0 billion. As of December 31, 2021, 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 10—Debt of our Notes to Consolidated Financial Statements.

Interest

As of December 31, 2021, our senior notes had a weighted average contractual interest rate of 4.83% and our credit facilities had weighted average interest rates on outstanding balances ranging from 1.85% to 3.50%. Borrowings under our credit facilities are indexed to LIBOR, which is expected to be phased out by 2023. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We amended the CCH Credit Facility and the CCH Working Capital Facility in 2021 to establish a SOFR-indexed replacement rate for LIBOR. Undrawn commitments under the CCH Working Capital Facility are subject to commitment fees of 0.50%. Issued letters of credit under the CCH Working Capital Facility are subject to letter of credit fees of 1.25%. We had $361 million of issued letters of credit under the CCH Working Capital Facility as of December 31, 2021.

29

Sources and Uses of Cash

The following table summarizes the sources and uses of our restricted cash and cash equivalents for the years ended December 31, 2021 and 2020 (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,
	2021		2020
Net cash provided by operating activities	$	1,424	$	396
Net cash used in investing activities	(240)		(796)
Net cash provided by (used in) financing activities	(1,210)		390
Net decrease in restricted cash and cash equivalents	$	(26)	$	(10)

Operating Cash Flows

Operating cash flows during the years ended December 31, 2021 and 2020 were $1,424 million and $396 million, respectively. The $1,028 million increase in operating cash inflows in 2021 compared to 2020 was primarily related to increased cash receipts from the sale of LNG cargoes due to higher revenue per MMBtu and increased volume of LNG delivered between periods, in addition to higher than normal contributions from LNG and natural gas portfolio optimization activities due to significant volatility in LNG and natural gas markets during the year ended December 31, 2021. Partially offsetting these operating cash inflows was higher operating cash outflows due to higher natural gas feedstock costs.

Investing Cash Flows

Cash outflows for property, plant and equipment were primarily for the construction costs for the Liquefaction Project, which are capitalized as construction-in-process until achievement of substantial completion. On March 26, 2021, substantial completion of Train 3 of the Liquefaction Project was achieved.

Financing Cash Flows

During the year ended December 31, 2021, we issued an aggregate principal amount of $750 million of the 2.742% CCH Senior Secured Notes, which together with cash on hand, were used to repay outstanding borrowings under the CCH Credit Facility. Additionally, borrowings of $400 million under the CCH Working Capital Facility were used to fund our working capital requirements and $290 million was repaid during the year.

During the year ended December 31, 2020, we issued an aggregate principal amount of $769 million of the 3.52% Senior Secured Notes due 2039 to repay a portion of the outstanding borrowings under the CCH Credit Facility. Additionally, borrowings of $281 million under the CCH Working Capital Facility were used to fund our working capital requirements and $141 million was repaid during the year.

Debt Issuances and Related Financing Costs

The following table shows the issuances of debt during the years ended December 31, 2021 and 2020, including intra-quarter borrowings (in millions):

	Year Ended December 31,
	2021		2020
Senior Secured Notes due 2039	$	750	$	769
CCH Working Capital Facility	400		281
Total issuances	$	1,150	$	1,050

We incurred $4 million and $8 million of debt issuance and deferred financing costs during the years ended December 31, 2021 and 2020, respectively, related to the debt transactions described above.

30

Debt Repayments and Related Extinguishment Costs

The following table shows the repayments of debt during the years ended December 31, 2021 and 2020, including intra-quarter repayments (in millions):

	Year Ended December 31,
	2021		2020
CCH Credit Facility	$	(898)	$	(656)
CCH Working Capital Facility	(290)		(141)
Total repayments	$	(1,188)	$	(797)

We incurred $5 million and zero of debt extinguishment costs during the years ended December 31, 2021 and 2020, respectively, related to the debt transactions described above.

Distributions

During the years ended December 31, 2021 and 2020, we made distributions of $1,163 million and zero, respectively, to Cheniere.

Summary of Critical Accounting Estimates

The preparation of 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 Derivative Instruments

All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes in the fair value of our derivative positions through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market as discussed below.

Our derivative instruments consist of interest rate swaps, financial commodity derivative contracts transacted in an over-the-counter market and physical commodity contracts. We value our interest rate swaps using observable inputs including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. Valuation of our financial commodity derivative contracts is determined using observable commodity price curves and other relevant data.

Valuation of our physical commodity derivative contracts, consisting primarily of natural gas supply contracts for the operation of our liquified natural gas facilities, is often developed through the use of internal models which incorporate significant observable and unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and volatility, and associated events deriving fair value including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

31

The valuation of certain physical commodity derivatives requires the use of significant unobservable inputs and 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 is the change in unrealized valuation gain (loss) of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2021 and 2020 (in millions). The changes shown are limited to instruments held at the end of each respective period.

	Year Ended December 31,
	2021		2020
Change in unrealized gain (loss) relating to instruments still held at end of period	$	(1,276)	$	28

The $1.3 billion unrealized valuation loss on instruments held during the year ended December 31, 2021 is primarily attributed to significant appreciation in estimated forward international LNG commodity curves on our IPM agreements from December 31, 2020 to December 31, 2021, relative to prior comparative periods.

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

Recent Accounting Standards 

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

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):

	December 31, 2021				December 31, 2020
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(1,212)	$	186	$	11	$	77

See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.

Interest Rate Risk

We are exposed to interest rate risk primarily when we incur debt related to project financing. Interest rate risk is managed in part by replacing outstanding floating-rate debt with fixed-rate debt with varying maturities. We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the CCH Credit Facility (“CCH Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the CCH Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward one-month LIBOR curve across the remaining terms of the CCH Interest Rate Derivatives as follows (in millions):

	December 31, 2021				December 31, 2020
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
CCH Interest Rate Derivatives	$	(40)	$	—	$	(140)	$	1

See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.

32

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	34
Report of Independent Registered Public Accounting Firm	35
Consolidated Statements of Operations	37
Consolidated Balance Sheets	38
Consolidated Statements of Member’s Equity	39
Consolidated Statements of Cash Flows	40
Notes to Consolidated Financial Statements	41
Note 1—Organization and Nature of Operations	41
Note 2—Summary of Significant Accounting Policies	41
Note 3—Restricted Cash and Cash Equivalents	46
Note 4—Accounts and Other Receivables, Net of Current Expected Credit Losses	46
Note 5—Inventory	46
Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation	46
Note 7—Derivative Instruments	47
Note 8—Other Non-current Assets, Net	52
Note 9—Accrued Liabilities	52
Note 10—Debt	53
Note 11—Revenues from Contracts with Customers	55
Note 12—Related Party Transactions	58
Note 13—Commitments and Contingencies	61
Note 14—Customer Concentration	63
Note 15—Supplemental Cash Flow Information	63

33

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

Management’s Report on Internal Control Over Financial Reporting

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Corpus Christi Holdings, LLC (“Corpus Christi Holdings”).  In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).  Corpus Christi Holdings’ system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we have concluded that Corpus Christi Holdings maintained effective internal control over financial reporting as of December 31, 2021, 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)

34

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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Fair value of the level 3 physical liquefaction supply derivatives

As discussed in Notes 2 and 7 to the consolidated financial statements, the Company recorded fair value of level 3 physical liquefaction supply derivatives of $(1,221) million, as of December 31, 2021. The physical liquefaction supply derivatives consist of natural gas supply contracts for the operation of the liquefied natural gas facility. The fair value of the level 3 physical liquefaction supply derivatives is developed using internal models that incorporate significant unobservable inputs.

We identified the evaluation of the fair value of the level 3 physical liquefaction supply derivatives as a critical audit matter. Specifically, there is subjectivity in certain assumptions used to estimate the fair value, including assumptions for future prices of energy units for unobservable periods and liquidity.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of the level 3 physical liquefaction supply derivatives. This included controls related to the assumptions for significant unobservable inputs and the fair value

35

model. For a selection of level 3 liquefaction supply derivatives, we involved valuation professionals with specialized skills and knowledge who assisted in:

•evaluating the future prices of energy units for observable periods by comparing to market data, including quoted or published forward prices

•developing independent fair value estimates and comparing the independently developed estimates to the Company’s fair value estimates.

In addition, we evaluated the Company’s assumptions for future prices of energy units for unobservable periods and liquidity by comparing them to market or third-party data, including adjustments for third party quoted transportation prices.

/s/    KPMG LLP

KPMG LLP

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

Houston, Texas

February 23, 2022

36

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

	Year Ended December 31,
	2021		2020		2019
Revenues
LNG revenues	$	3,907	$	2,046	$	679
LNG revenues—affiliate	1,887		483		726
Total revenues	5,794		2,529		1,405
Operating costs and expenses
Cost of sales (excluding items shown separately below)	4,326		901		691
Cost of sales—affiliate	50		30		3
Cost of sales—related party	146		114		86
Operating and maintenance expense	423		347		242
Operating and maintenance expense—affiliate	106		90		59
Operating and maintenance expense—related party	9		6		—
Development expense	—		—		1
General and administrative expense	7		7		6
General and administrative expense—affiliate	28		20		11
Depreciation and amortization expense	420		342		231
Impairment expense and loss on disposal of assets	2		1		—
Total operating costs and expenses	5,517		1,858		1,330
Income from operations	277		671		75
Other income (expense)
Interest expense, net of capitalized interest	(447)		(365)		(278)
Loss on modification or extinguishment of debt	(9)		(9)		(41)
Interest rate derivative loss, net	(1)		(233)		(134)
Other income (expense), net	—		(1)		4
Total other expense	(457)		(608)		(449)
Net income (loss)	$	(180)	$	63	$	(374)

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

37

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions)

	December 31,
	2021		2020
ASSETS
Current assets
Restricted cash and cash equivalents	$	44	$	70
Accounts and other receivables, net of current expected credit losses	280		198
Accounts receivable—affiliate	315		42
Advances to affiliate	128		144
Inventory	156		89
Current derivative assets	17		10
Current derivative assets—related party	—		3
Other current assets	28		17
Other current assets—affiliate	—		1
Total current assets	968		574
Property, plant and equipment, net of accumulated depreciation	12,607		12,853
Debt issuance and deferred financing costs, net of accumulated amortization	7		11
Derivative assets	37		114
Derivative assets—related party	—		1
Other non-current assets, net	145		87
Total assets	$	13,764	$	13,640
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	119	$	19
Accrued liabilities	631		318
Accrued liabilities—related party	1		16
Current debt, net of discount and debt issuance costs	366		269
Due to affiliates	35		32
Current derivative liabilities	668		143
Other current liabilities	1		—
Total current liabilities	1,821		797
Long-term debt, net of discount and debt issuance costs	9,986		10,101
Derivative liabilities	638		114
Other non-current liabilities	38		4
Commitments and contingencies (see Note 13)
Member’s equity	1,281		2,624
Total liabilities and member’s equity	$	13,764	$	13,640

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

38

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, 2018	$	2,081	$	2,081
Capital contributions	711		711
Net loss	(374)		(374)
Balance at December 31, 2019	2,418		2,418
Capital contributions	145		145
Distributions	(2)		(2)
Net income	63		63
Balance at December 31, 2020	2,624		2,624
Distributions	(1,163)		(1,163)
Net loss	(180)		(180)
Balance at December 31, 2021	$	1,281	$	1,281

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

39

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2021		2020		2019
Cash flows from operating activities
Net income (loss)	$	(180)	$	63	$	(374)
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization expense	420		342		231
Amortization of discount and debt issuance costs	24		20		16
Loss on modification or extinguishment of debt	9		9		41
Total losses on derivatives, net	1,241		261		88
Total losses (gains) on derivatives, net—related party	(11)		1		1
Net cash used for settlement of derivative instruments	(107)		(174)		(30)
Impairment expense and loss on disposal of assets	2		1		—
Other	1		3		2
Changes in operating assets and liabilities:
Accounts receivable	(84)		(138)		(58)
Accounts receivable—affiliate	(273)		15		(57)
Advances to affiliate	14		(11)		(53)
Inventory	(62)		(18)		(37)
Accounts payable and accrued liabilities	468		63		174
Accrued liabilities—related party	(14)		11		3
Due to affiliates	9		5		15
Other, net	(33)		(56)		5
Other, net—affiliate	—		(1)		—
Net cash provided by (used in) operating activities	1,424		396		(33)
Cash flows from investing activities
Property, plant and equipment	(238)		(790)		(1,517)
Other	(2)		(6)		(2)
Net cash used in investing activities	(240)		(796)		(1,519)
Cash flows from financing activities
Proceeds from issuances of debt	1,150		1,050		4,203
Repayments of debt	(1,188)		(797)		(3,544)
Debt issuance and deferred financing costs	(4)		(8)		(16)
Debt extinguishment costs	(5)		—		(11)
Capital contributions	—		145		711
Distributions	(1,163)		—		—
Net cash provided by (used in) financing activities	(1,210)		390		1,343
Net decrease in restricted cash and cash equivalents	(26)		(10)		(209)
Restricted cash and cash equivalents—beginning of period	70		80		289
Restricted cash and cash equivalents—end of period	$	44	$	70	$	80

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

40

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We operate a natural gas liquefaction and export facility (the “Liquefaction Facilities”) and operate a 21.5-mile natural gas supply pipeline that interconnects the natural gas liquefaction and export facility near Corpus Christi, Texas (the “Corpus Christi LNG terminal”) with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries CCL and CCP, respectively. We operate three Trains for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project also contains three LNG storage tanks and two marine berths.

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. When necessary, reclassifications that are not material to our Consolidated Financial Statements are made to prior period financial information to conform to the current year presentation.

Use of Estimates

The preparation of 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”), as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value Measurements

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

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

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments.

The carrying amount of restricted cash and cash equivalents, accounts receivable and accounts payable 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. Debt fair values, as disclosed in Note 10—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs.

41

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Revenue Recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 11—Revenues from Contracts with Customers for further discussion of our revenue streams and accounting policies related to revenue recognition.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

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.

Accounts and Other Receivables

Accounts and other receivables are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Consolidated Statements of Operations. We did not have any current expected credit losses on our accounts and other receivables as of December 31, 2021 and 2020.

Inventory

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

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.

Generally, we begin capitalizing the costs of our LNG terminal once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminal.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets.

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

We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives. Refer to Note 6—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

42

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets.

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

We recorded $2 million of impairments related to property, plant and equipment during the year ended December 31, 2021. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2020 and 2019.

Interest Capitalization

We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon commencement of operations, these costs are transferred out of construction-in-process into terminal and interconnecting pipeline facilities assets and are amortized over the estimated useful life of the asset.

Regulated Natural Gas Pipelines 

The Corpus Christi Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to write off the associated regulatory assets and liabilities. 

Items that may influence our assessment are: 

•inability to recover cost increases due to rate caps and rate case moratoriums;  

•inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;  

•excess capacity;  

•increased competition and discounting in the markets we serve; and  

•impacts of ongoing regulatory initiatives in the natural gas industry.

Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipeline. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipeline is placed in service.

43

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2021, 2020 and 2019. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

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

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within other current assets. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

CCL has entered into fixed price long-term SPAs generally with terms of 20 years with 10 third parties and have entered into agreements with Cheniere Marketing International LLP (“Cheniere Marketing”). CCL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs.

See Note 14—Customer Concentration for additional details about our customer concentration.

Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.

Debt

Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders.  Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.

Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Consolidated Balance Sheets.

44

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in loss on modification or extinguishment of debt on our Consolidated Statements of Operations.

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.

We have not recorded an ARO associated with the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

Income Taxes

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

Business Segment

Our liquefaction and pipeline business at the Corpus Christi LNG terminal represents a single reportable segment. Our chief operating decision maker reviews the financial results of CCH in total when evaluating financial performance and for purposes of allocating resources.

Recent Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts expected to arise from the market transition from LIBOR to alternative reference rates. The transition period under this standard is effective March 12, 2020 and will apply through December 31, 2022.

We have various credit facilities and interest rate swaps indexed to LIBOR, as further described in Note 10—Debt. To date, we have amended certain of our credit facilities to incorporate a fallback replacement rate indexed to SOFR as a result of the expected LIBOR transition. We elected to apply the optional expedients as applicable to certain modified terms, however the impact of applying the optional expedients has not been material thus far. We will continue to elect to apply the optional expedients to qualifying contract modifications in the future.

45

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consists 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. As of December 31, 2021 and 2020, we had $44 million and $70 million of restricted cash and cash equivalents, respectively.

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

As of December 31, 2021 and 2020, accounts and other receivables, net of current expected credit losses consisted of the following (in millions):

	December 31,
	2021		2020
Trade receivable	$	256	$	182
Other accounts receivable	24		16
Total accounts and other receivables, net of current expected credit losses	$	280	$	198

NOTE 5—INVENTORY

As of December 31, 2021 and 2020, inventory consisted of the following (in millions):

	December 31,
	2021		2020
Materials	$	88	$	69
LNG	45		11
Natural gas	21		9
Other	2		—
Total inventory	$	156	$	89

NOTE 6—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

As of December 31, 2021 and 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	December 31,
	2021		2020
LNG terminal
LNG terminal and interconnecting pipeline facilities	$	13,222	$	10,176
LNG site and related costs	294		276
LNG terminal construction-in-process	66		2,960
Accumulated depreciation	(981)		(568)
Total LNG terminal, net of accumulated depreciation	12,601		12,844
Fixed assets
Fixed assets	23		22
Accumulated depreciation	(17)		(13)
Total fixed assets, net of accumulated depreciation	6		9
Property, plant and equipment, net of accumulated depreciation	$	12,607	$	12,853

46

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows depreciation expense and offsets to LNG terminal costs during the years ended December 31, 2021, 2020 and 2019 (in millions):

	Year Ended December 31,
	2021		2020		2019
Depreciation expense	$	419	$	341	$	230
Offsets to LNG terminal costs (1)	143		32		156

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the Liquefaction Project during the testing phase for its construction.

LNG Terminal Costs

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

Components	Useful life (years)
LNG storage tanks	50
Natural gas pipeline facilities	40
Marine berth, electrical, facility and roads	35
Water pipelines	30
Liquefaction processing equipment	6-50
Other	15-30

Fixed Assets and Other

Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments that are reported at fair value:

•interest rate swaps (“CCH Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on our amended and restated term loan credit facility (the “CCH Credit Facility”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt (“CCH Interest Rate Forward Start Derivatives” and, collectively with the CCH Interest Rate Derivatives, the “Interest Rate Derivatives”) and

•commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”).

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process, in which case it is capitalized.

47

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2021 and 2020 (in millions):

	Fair Value Measurements as of
	December 31, 2021								December 31, 2020
	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
CCH Interest Rate Derivatives liability	$	—	$	(40)	$	—	$	(40)	$	—	$	(140)	$	—	$	(140)
Liquefaction Supply Derivatives asset (liability)	5		4		(1,221)		(1,212)		4		(5)		12		11

We value our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

We include a portion of our Physical 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 would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

The Level 3 fair value measurements of natural gas positions within our Physical 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 our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2021:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(1,221)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.380) - $0.628 / $(0.035)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	199% - 662% / 326%

(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 our Physical Liquefaction Supply Derivatives.

48

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives, including those with related parties, during the years ended December 31, 2021, 2020 and 2019 (in millions):

	Year Ended December 31,
	2021		2020		2019
Balance, beginning of period	$	12	$	35	$	(4)
Realized and mark-to-market gains (losses):
Included in cost of sales	(1,276)		28		(83)
Purchases and settlements:
Purchases	9		—		121
Settlements	34		(58)		1
Transfers into Level 3, net (1)	—		7		—
Balance, end of period	$	(1,221)	$	12	$	35
Change in unrealized gain (loss) relating to instruments still held at end of period	$	(1,276)	$	28	$	(83)

(1)Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we 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. 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.

Interest Rate Derivatives

We have entered into interest rate swaps to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility. We previously also had interest rate swaps to hedge against changes in interest rates that could impact the anticipated future issuance of debt. In August 2020, we settled the outstanding CCH Interest Rate Forward Start Derivatives.

As of December 31, 2021, we had the following Interest Rate Derivatives outstanding:

	Notional Amounts
	December 31, 2021	December 31, 2020	Latest Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
CCH Interest Rate Derivatives	$4.5 billion	$4.6 billion	May 31, 2022	2.30%	One-month LIBOR

The following table shows the effect and location of our Interest Rate Derivatives on our Consolidated Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions):

		Loss Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location	Year Ended December 31,
		2021		2020		2019
CCH Interest Rate Derivatives	Interest rate derivative loss, net	$	(1)	$	(138)	$	(101)
CCH Interest Rate Forward Start Derivatives	Interest rate derivative loss, net	—		(95)		(33)

Liquefaction Supply Derivatives

CCL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges, including those associated with transactions under our IPM agreements, to purchase natural gas for the commissioning and

49

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain conditions precedent. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.

The forward notional amount for our Liquefaction Supply Derivatives was approximately 2,915 TBtu and 3,152 TBtu as of December 31, 2021 and 2020, respectively.

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions):

	Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)		Year Ended December 31,
		2021		2020		2019
LNG revenues		$	4	$	(1)	$	—
Cost of sales		(1,244)		(27)		46
Cost of sales—related party (2)		11		(1)		(1)

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

(2)Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12—Related Party Transactions.

50

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets

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

	December 31, 2021
	CCH Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	17	$	17
Derivative assets	—		37		37
Total derivative assets	—		54		54
Current derivative liabilities	(40)		(628)		(668)
Derivative liabilities	—		(638)		(638)
Total derivative liabilities	(40)		(1,266)		(1,306)
Derivative liability, net	$	(40)	$	(1,212)	$	(1,252)
	December 31, 2020
	CCH Interest Rate Derivatives		Liquefaction Supply Derivatives (1)		Total
Consolidated Balance Sheets Location
Current derivative assets	$	—	$	10	$	10
Current derivative assets—related party	—		3		3
Derivative assets	—		114		114
Derivative assets—related party	—		1		1
Total derivative assets	—		128		128
Current derivative liabilities	(100)		(43)		(143)
Derivative liabilities	(40)		(74)		(114)
Total derivative liabilities	(140)		(117)		(257)
Derivative asset (liability), net	$	(140)	$	11	$	(129)

(1)Does not include collateral posted with counterparties by us of $13 million and $5 million, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Includes a natural gas supply contract that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed in Note 12—Related Party Transactions.

51

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Consolidated Balance Sheets Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):

	CCH Interest Rate Derivatives		Liquefaction Supply Derivatives
As of December 31, 2021
Gross assets	$	—	$	76
Offsetting amounts	—		(22)
Net assets	$	—	$	54
Gross liabilities	$	(40)	$	(1,295)
Offsetting amounts	—		29
Net liabilities	$	(40)	$	(1,266)
As of December 31, 2020
Gross assets	$	—	$	132
Offsetting amounts	—		(4)
Net assets	$	—	$	128
Gross liabilities	$	(140)	$	(136)
Offsetting amounts	—		19
Net liabilities	$	(140)	$	(117)

NOTE 8—OTHER NON-CURRENT ASSETS, NET

As of December 31, 2021 and 2020, other non-current assets, net consisted of the following (in millions):

	December 31,
	2021		2020
Contract assets, net of current expected credit losses	$	103	$	48
Advances and other asset conveyances to third parties to support LNG terminal	24		22
Operating lease assets	4		5
Information technology service prepayments	3		3
Tax-related payments and receivables	2		3
Other	9		6
Total other non-current assets, net	$	145	$	87

NOTE 9—ACCRUED LIABILITIES

As of December 31, 2021 and 2020, accrued liabilities consisted of the following (in millions): 

	December 31,
	2021		2020
Accrued natural gas purchases	$	531	$	186
Interest costs and related debt fees	7		7
Liquefaction Project costs	43		76
Other	50		49
Total accrued liabilities	$	631	$	318

52

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 10—DEBT

As of December 31, 2021 and 2020, our debt consisted of the following (in millions): 

	December 31,
	2021		2020
Senior Secured Notes:
7.000% due 2024	$	1,250	$	1,250
5.875% due 2025	1,500		1,500
5.125% due 2027	1,500		1,500
3.700% due 2029	1,500		1,500
3.72% weighted average rate due 2039	2,721		1,971
Total Senior Secured Notes	8,471		7,721
CCH Credit Facility (1)	1,728		2,627
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) (2)	250		140
Total Debt	10,449		10,488
Current portion of long-term debt	(117)		(129)
Short-term debt	(250)		(140)
Unamortized discount and debt issuance costs, net	(96)		(118)
Total long-term debt, net of discount and debt issuance costs	$	9,986	$	10,101

(1)A portion of the outstanding balance that is due within one year is classified as current portion of long-term debt.

(2)The CCH Working Capital Facility is classified as short-term debt.

Senior Notes

CCH Senior Secured Notes

The senior secured notes due between 2024 and 2039, with a weighted average interest rate of 4.83% (“CCH Senior Secured Notes”) are jointly and severally guaranteed by our subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The CCH Senior Secured Notes are our senior secured obligations, ranking senior in right of payment to any and all of our future indebtedness that is subordinated to the CCH Senior Secured Notes and equal in right of payment with our other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Secured Notes. The CCH Senior Secured Notes are secured by a first-priority security interest in substantially all of our and the CCH Guarantors’ assets. We may, at any time, redeem all or part of the CCH Senior Secured Notes at specified prices set forth in the respective indentures governing the CCH Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption.

Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2021 (in millions): 

Years Ending December 31,	Principal Payments
2022	$	367
2023	67
2024	2,794
2025	1,500
2026	—
Thereafter	5,721
Total	$	10,449

53

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2021 (in millions):

	CCH Credit Facility (1)		CCH Working Capital Facility (2)
Original facility size	$	8,404	$	350
Incremental commitments	1,566		850
Less:
Outstanding balance	1,729		250
Commitments prepaid or terminated	8,241		—
Letters of credit issued	—		361
Available commitment	$	—	$	589
Priority ranking	Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.75% or base rate plus 0.75% (3)		LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75% (3)
Weighted average interest rate of outstanding balance	1.85%		3.50%
Commitment fees on undrawn balance	n/a		0.50%
Maturity date	June 30, 2024		June 29, 2023

(1)Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our and our subsidiaries assets and by a pledge by Cheniere CCH Holdco I, LLC of its limited liability company interests in us.

(2)Our obligations under the CCH Working Capital Facility are secured by substantially all of our and the CCH Guarantors assets as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility.

(3)These facilities were amended in 2021 to establish a SOFR-indexed replacement rate for LIBOR.

Restrictive Debt Covenants

The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain investments or pay dividends or distributions.

As of December 31, 2021, 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,
	2021		2020		2019
Total interest cost	$	473	$	484	$	539
Capitalized interest, including amounts capitalized as an AFUDC	(26)		(119)		(261)
Total interest expense, net of capitalized interest	$	447	$	365	$	278

54

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Fair Value Disclosures

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

	December 31, 2021				December 31, 2020
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	6,500	$	7,095	$	5,750	$	6,669
Senior notes — Level 3 (2)	1,971		2,227		1,971		2,387
Credit facilities — Level 3 (3)	1,978		1,978		2,767		2,767

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 

(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2021, 2020 and 2019 (in millions):

	Year Ended December 31,
	2021		2020		2019
LNG revenues (1)	$	3,903	$	2,047	$	679
LNG revenues—affiliate	1,887		483		726
Total revenues from customers	5,790		2,530		1,405
Net derivative gain (loss) (2)	4		(1)		—
Total revenues	$	5,794	$	2,529	$	1,405

(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized during the year ended December 31, 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2021 and 2019. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

(2)See Note 7—Derivative Instruments for additional information about our derivatives.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a free on board (“FOB”) (delivered to the customer at the Corpus Christi LNG terminal) 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; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 12—Related Party Transactions for additional information regarding these agreements.

55

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Corpus Christi LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Contract Assets and Liabilities

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

	December 31,
	2021		2020
Contract assets, net of current expected credit losses	$	104	$	48

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the year ended December 31, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

The following table reflects the changes in our contract liabilities, which we classify as other non-current liabilities on our Consolidated Balance Sheets (in millions):

	Year Ended December 31, 2021
Deferred revenue, beginning of period	$	—
Cash received but not yet recognized in revenue	35
Revenue recognized from prior period deferral	—
Deferred revenue, end of period	$	35

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2021 and 2020 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

56

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2021 and 2020:

	December 31, 2021			December 31, 2020
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	31.7	9	$	32.3	10
LNG revenues—affiliate	1.1		10	1.0		12
Total revenues	$	32.8		$	33.3

(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We have elected the following exemptions which omit certain potential future sources of revenue from the table above:

(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 58% and 33% of our LNG revenues from contracts included in the table above during the years ended December 31, 2021 and 2020, respectively, were related to variable consideration received from customers. None of our LNG revenues—affiliates from the contract included in the table above were related to variable consideration received from customers during the years ended December 31, 2021 and 2020.

We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

57

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 12—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations during the years ended December 31, 2021, 2020 and 2019 (in millions):

	Year Ended December 31,
	2021		2020		2019
LNG revenues—affiliate
Cheniere Marketing Agreements	$	1,837	$	468	$	719
Contracts for Sale and Purchase of Natural Gas and LNG	50		15		7
Total LNG revenues—affiliate	1,887		483		726
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	19		30		3
Cheniere Marketing Agreements	31		—		—
Total cost of sales—affiliate	50		30		3
Cost of sales—related party
Natural Gas Supply Agreement (1)	146		114		86
Operating and maintenance expense—affiliate
Services Agreements	105		89		58
Land Agreements	1		1		1
Total operating and maintenance expense—affiliate	106		90		59
Operating and maintenance expense—related party
Natural Gas Transportation Agreements	9		6		—
General and administrative expense—affiliate
Services Agreements	28		20		11

(1)Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement as of December 31, 2021 as discussed below.

We had $35 million and $32 million due to affiliates as of December 31, 2021 and 2020, respectively, under agreements with affiliates, as described below.

Cheniere Marketing Agreements

Cheniere Marketing SPA

CCL has a fixed price SPA with Cheniere Marketing (the “Cheniere Marketing Base SPA”) with a term of 20 years which allows Cheniere Marketing to purchase, at its option, (1) up to a cumulative total of 150 TBtu of LNG within the commissioning periods for Trains 1 through 3 and (2) any excess LNG produced by the Liquefaction Facilities that is not committed to customers under third party SPAs. Under the Cheniere Marketing Base SPA, Cheniere Marketing may, without charge, elect to suspend deliveries of cargoes (other than commissioning cargoes) scheduled for any month under the applicable annual delivery program by providing specified notice in advance. Additionally, CCL has: (1) a fixed price SPA with a term through 2043 with Cheniere Marketing which allows them to purchase volumes of approximately 15 TBtu per annum of LNG and (2) an SPA with Cheniere Marketing for approximately 44 TBtu of LNG with a maximum term up to 2026 associated with the integrated production marketing gas supply agreement between CCL and EOG Resources, Inc. As of December 31, 2021 and 2020, CCL had $314 million and $39 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing.

58

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Facility Swap Agreement

We have entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.

Services Agreements

Gas and Power Supply Services Agreement (“G&P Agreement”)

CCL has a G&P Agreement with Cheniere Energy Shared Services, Inc. (“Shared Services”), a wholly owned subsidiary of Cheniere, pursuant to which Shared Services will manage the gas and power procurement requirements of CCL. The services include, among other services, exercising the day-to-day management of CCL’s natural gas and power supply requirements, negotiating agreements on CCL’s behalf and providing other administrative services. Prior to the substantial completion of each Train of the Liquefaction Facilities, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facilities, for services performed while the Liquefaction Facilities is operational, CCL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train.

Operation and Maintenance Agreements (“O&M Agreements”)

CCL has an O&M Agreement (“CCL O&M Agreement”) with Cheniere LNG O&M Services, LLC (“O&M Services”), a wholly owned subsidiary of Cheniere, pursuant to which CCL receives all of the necessary services required to construct, operate and maintain the Liquefaction Facilities. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors, administering various agreements, information technology services and other services required to operate and maintain the Liquefaction Facilities. Prior to the substantial completion of each Train of the Liquefaction Facilities, no monthly fee payment is required except for reimbursement of operating expenses. After substantial completion of each Train of the Liquefaction Facilities, for services performed while the Liquefaction Facilities is operational, CCL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $125,000 (indexed for inflation) for services with respect to such Train.

CCP has an O&M Agreement (“CCP O&M Agreement”) with O&M Services pursuant to which CCP receives all of the necessary services required to construct, operate and maintain the Corpus Christi Pipeline. The services to be provided include, among other services, preparing and maintaining staffing plans, identifying and arranging for procurement of equipment and materials, overseeing contractors, information technology services and other services required to operate and maintain the Corpus Christi Pipeline. CCP is required to reimburse O&M Services for all operating expenses incurred on behalf of CCP.

Management Services Agreements (“MSAs”)

CCL has a MSA with Shared Services pursuant to which Shared Services manages the construction and operation of the Liquefaction Facilities, excluding those matters provided for under the G&P Agreement and the CCL O&M Agreement. The services include, among other services, exercising the day-to-day management of CCL’s affairs and business, managing CCL’s regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Liquefaction Facilities and obtaining insurance. Prior to the substantial completion of each Train of the Liquefaction Facilities, no monthly fee payment is required except for reimbursement of expenses. After substantial completion of each Train, CCL will pay, in addition to the reimbursement of related expenses, a monthly fee equal to 3% of the capital expenditures incurred in the previous month and a fixed monthly fee of $375,000 for services with respect to such Train.

CCP has a MSA with Shared Services pursuant to which Shared Services manages CCP’s operations and business, excluding those matters provided for under the CCP O&M Agreement. The services include, among other services, exercising the day-to-day management of CCP’s affairs and business, managing CCP’s regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Corpus Christi Pipeline and obtaining insurance.

59

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

CCP is required to reimburse Shared Services for the aggregate of all costs and expenses incurred in the course of performing the services under the MSA.

Natural Gas Supply Agreement

CCL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. However, this entity was acquired by a non-related party on November 1, 2021; therefore, as of such date, this agreement ceased to be considered a related party. In addition to the amounts recorded on our Consolidated Statements of Operations in the table above, CCL recorded accrued liabilities—related party of $13 million, current derivative assets—related party of $3 million and derivative assets—related party of $1 million as of December 31, 2020 related to this agreement.

Natural Gas Transportation Agreements

Agreements with Related Party

CCL is party to natural gas transportation agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project, for a period of 10 years which began in May 2020. Cheniere accounts for its investment in this related party as an equity method investment. In addition to the amounts recorded on our Consolidated Statements of Operations in the table above, CCL recorded accrued liabilities—related party of $1 million as of both December 31, 2021 and 2020 related to this agreement.

Agreements with Cheniere Corpus Christi Liquefaction Stage III, LLC

Cheniere Corpus Christi Liquefaction Stage III, LLC, a wholly owned subsidiary of Cheniere, has a transportation precedent agreement with CCP to secure firm pipeline transportation capacity for the transportation of natural gas feedstock to the expansion of the Corpus Christi LNG terminal it is constructing adjacent to the Liquefaction Project. The agreement will have a primary term of 20 years from the service commencement date with right to extend the term for two successive five-year terms.

Contracts for Sale and Purchase of Natural Gas and LNG

CCL has an agreement with Sabine Pass Liquefaction, LLC that allows them to sell and purchase natural gas with each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate.

CCL also has an agreement with Midship Pipeline Company, LLC that allows them to sell and purchase natural gas with each other.

Land Agreements

Lease Agreements

CCL has agreements with Cheniere Land Holdings, LLC (“Cheniere Land Holdings”), a wholly owned subsidiary of Cheniere, to lease the land owned by Cheniere Land Holdings for the Liquefaction Facilities. The total annual lease payment is $0.6 million and the terms of the agreements range from three to 10 years.

Easement Agreements

CCL has agreements with Cheniere Land Holdings which grant CCL easements on land owned by Cheniere Land Holdings for the Liquefaction Facilities. The total annual payment for easement agreements is $0.1 million, excluding any previously paid one-time payments, and the terms of the agreements range from three to five years.

60

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Dredge Material Disposal Agreement

CCL has a dredge material disposal agreement with Cheniere Land Holdings that terminates in 2042 which grants CCL permission to use land owned by Cheniere Land Holdings for the deposit of dredge material from the construction and maintenance of the Liquefaction Facilities. Under the terms of the agreement, CCL will pay Cheniere Land Holdings $0.50 per cubic yard of dredge material deposits up to 5.0 million cubic yards and $4.62 per cubic yard for any quantities above that.

Tug Hosting Agreement

In February 2017, CCL entered into a tug hosting agreement with Corpus Christi Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of Cheniere, to provide certain marine structures, support services and access necessary at the Liquefaction Facilities for Tug Services to provide its customers with tug boat and marine services. Tug Services is required to reimburse CCL for any third party costs incurred by CCL in connection with providing the goods and services.

State Tax Sharing Agreements

CCL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CCL 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, CCL will pay to Cheniere an amount equal to the state and local tax that CCL would be required to pay if CCL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere and Cheniere has not demanded any such payments from CCL under the agreement. The agreement is effective for tax returns due on or after May 2015.

CCP has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CCP 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, CCP will pay to Cheniere an amount equal to the state and local tax that CCP would be required to pay if CCP’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere and Cheniere has not demanded any such payments from CCP under the agreement. The agreement is effective for tax returns due on or after May 2015.

Equity Contribution Agreements

Equity Contribution Agreement

In May 2018, we amended and restated the existing equity contribution agreement with Cheniere (the “Equity Contribution Agreement”) pursuant to which Cheniere agreed to provide cash contributions up to approximately $1.1 billion, not including $2.0 billion previously contributed under the original equity contribution agreement. As of December 31, 2021, we have received $703 million in contributions under the Equity Contribution Agreement and Cheniere has no outstanding letters of credit on our behalf. Cheniere is only required to make additional contributions under the Equity Contribution Agreement after the commitments under the CCH Credit Facility have been reduced to zero and to the extent cash flows from operations of the Liquefaction Project are unavailable for Liquefaction Project costs.

NOTE 13—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain unconditional purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2021, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Natural Gas Supply, Transportation and Storage Service Agreements

CCL has physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 10 years.

61

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Additionally, CCL has natural gas transportation and storage service agreements for the Liquefaction Project. The initial terms of the natural gas transportation agreements range up 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The initial term of the natural gas storage service agreements ranges up to five years.

As of December 31, 2021, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in billions): 

Years Ending December 31,	Payments Due (1)
2022	$	3.5
2023	2.1
2024	1.6
2025	1.2
2026	1.0
Thereafter	3.6
Total	$	13.0

(1)Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread, and pricing of IPM agreements are variable based on global gas market prices less fixed liquefaction fees and certain costs by us.. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2021. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

Services Agreements

CCL and CCP have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements. 

Environmental and Regulatory Matters

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

Legal Proceedings

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In the opinion of management, as of December 31, 2021, 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.

62

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 14—CUSTOMER CONCENTRATION

The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with accounts receivable, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total accounts receivable, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers
		Year Ended December 31,			December 31,
		2021	2020	2019	2021	2020
Customer A		21%	31%	57%	*	15%
Customer B		16%	16%	23%	*	*
Customer C		15%	14%	—%	*	10%
Customer D		*	*	*	*	16%
Customer E		*	*	—%	31%	27%
Customer F		*	*	—%	*	11%
Customer G		*	—%	—%	11%	—%

* Less than 10%

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

	Revenues from External Customers
	Year Ended December 31,
	2021		2020		2019
Spain	$	1,432	$	1,001	$	451
Singapore	694		134		—
Indonesia	618		336		155
Ireland	599		285		—
France	423		136		—
United States	141		154		73
Total	$	3,907	$	2,046	$	679

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2021		2020		2019
Cash paid during the period for interest, net of amounts capitalized	$	423	$	345	$	258
Non-cash distributions to affiliates for conveyance of assets	—		2		—

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $20 million, $86 million and $187 million as of December 31, 2021, 2020 and 2019, respectively.

63

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Based on their evaluation as of the end of the fiscal year ended December 31, 2021, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

Management’s Report on Internal Control Over Financial Reporting

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

ITEM 9B.    OTHER INFORMATION

None.

ITEM 9C.    DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

64

PART III

ITEM 10.     MANAGERS, EXECUTIVE OFFICERS AND COMPANY GOVERNANCE

Omitted pursuant to Instruction I of Form 10-K.

ITEM 11.     EXECUTIVE COMPENSATION 

Omitted pursuant to Instruction I of Form 10-K.

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

Omitted pursuant to Instruction I of Form 10-K.

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

Omitted pursuant to Instruction I of Form 10-K.

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2021 and 2020 (in millions): 

	Fiscal 2021		Fiscal 2020
Audit Fees	$	1	$	1

Audit Fees—Audit fees for 2021 and 2020 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 2021 and 2020.

Tax Fees—There were no tax fees in 2021 and 2020.

Other Fees—There were no other fees in 2021 and 2020.

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, 2021 and 2020.

65

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	34
Report of Independent Registered Public Accounting Firm	35
Consolidated Statements of Operations	37
Consolidated Balance Sheets	38
Consolidated Statements of Member’s Equity	39
Consolidated Statements of Cash Flows	40
Notes to Consolidated Financial Statements	41

(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 elsewhere within 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

66

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
3.6	Certificate of Formation of Corpus Christi Pipeline GP, LLC	CCH	S-4	3.6	1/5/2017
3.7	Certificate of Correction to Certificate of Formation of Corpus Christi Pipeline GP, LLC	CCH	S-4	3.7	1/5/2017
3.8	Amended and Restated Limited Liability Company Agreement of Corpus Christi Pipeline GP, LLC	CCH	S-4	3.8	1/5/2017
3.9	Certificate of Limited Partnership of CCP	CCH	S-4	3.9	1/5/2017
3.10	Certificate of Amendment to Certificate of Limited Partnership of CCP	CCH	S-4	3.10	1/5/2017
3.11	Amended and Restated Agreement of Limited Partnership of CCP	CCH	S-4	3.11	1/5/2017
4.1	Indenture, dated as of May 18, 2016, among the Company, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee	Cheniere	8-K	4.1	5/18/2016
4.2	Form of 7.000% Senior Secured Note due 2024 (Included as Exhibit A-1 to Exhibit 4.1 above)	Cheniere	8-K	4.1	5/18/2016
4.3	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
4.4	Form of 5.875% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.3 above)	Cheniere	8-K	4.1	12/9/2016
4.5	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
4.6	Form of 5.125% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.5 above)	CCH	8-K	4.1	5/19/2017
4.7	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
4.8	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
4.9	Form of 4.80% Senior Secured Note due December 31, 2039 (Included as Exhibit A-1 to Exhibit 4.8 above)	CCH	8-K	4.1	9/30/2019
4.10	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
4.11	Form of 3.925% Senior Secured Note due December 31, 2039 (Included as Exhibit A to Exhibit 4.10 above)	CCH	8-K	4.1	10/18/2019
4.12	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
4.13	Form of 3.700% Senior Secured Note due 2029 (Included as Exhibit A-1 to Exhibit 4.12 above)	CCH	8-K	4.1	11/13/2019
4.14	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
4.15	Form of 2.742% Senior Secured Note due 2039 (Included as Exhibit A-1 to Exhibit 4.14 above)	CCH	8-K	4.1	8/24/2021
4.16	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
4.17	Form 3.52% Senior Secured Note due December 31, 2039 (Included as Exhibit A-1 to Exhibit 4.16 above)	CCH	8-K	4.1	8/21/2020

67

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.1	Amended and Restated Term Loan Facility Agreement, dated May 22, 2018, 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	10.4	5/24/2018
10.2	Amended and Restated Common Terms Agreement, dated May 22, 2018, 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	10.2	5/24/2018
10.3	First Amendment to the Amended and Restated Common Terms Agreement, dated as of November 28, 2018, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as Intercreditor Agent	CCH	10-K	10.3	2/26/2019
10.4	Second Amendment to the Amended and Restated Common Terms Agreement, dated as of August 30, 2019, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent	CCH	10-Q	10.2	11/1/2019
10.5	Third Amendment to the Amended and Restated Common Terms Agreement, dated as of November 8, 2019, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent	CCH	10-K	10.5	2/24/2021
10.6	Fourth Amendment to the Amended and Restated Common Terms Agreement, dated as of November 26, 2019, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent	CCH	10-K	10.6	2/24/2021
10.7	Fifth Amendment to the Amended and Restated Common Terms Agreement, dated as of November 16, 2020, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent	CCH	10-K	10.7	2/24/2021
10.8	Sixth Amendment to the Amended and Restated Common Terms Agreement, dated as of April 1, 2021, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as the Term Loan Facility Agent, The Bank of Nova Scotia as the Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent	CCH	10-Q	10.2	8/5/2021
10.9*	Seventh Amendment to the Amended and Restated Common Terms Agreement, dated as of October 8, 2021, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as the Term Loan Facility Agent, The Bank of Nova Scotia as the Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent

68

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.10*	Eighth Amendment to the Amended and Restated Common Terms Agreement, dated as of November 16, 2021, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, Société Générale as the Term Loan Facility Agent, The Bank of Nova Scotia as the Working Capital Facility Agent, each other Facility Agent on behalf of its respective Facility Lenders, and Société Générale as the Intercreditor Agent
10.11	Amended and Restated Common Security and Account Agreement, dated May 22, 2018, 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	10.3	5/24/2018
10.12	First Amendment to the Amended and Restated Common Security and Account Agreement, dated as of November 28, 2018, by and among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank	CCH	10-K	10.5	2/26/2019
10.13	Second Amendment to Common Security and Account Agreement, dated as of August 30, 2019, by and among the Company, CCL, CCP, Corpus Christi Pipeline GP, LLC, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank	CCH	10-Q	10.3	11/1/2019
10.14	Third Amendment to Common Security and Account Agreement, dated as of November 16, 2020, by and among the Company, CCL, CCP, Corpus Christi Pipeline GP, LLC, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank	CCH	10-K	10.11	2/24/2021
10.15	Fourth Amendment to Common Security and Account Agreement, dated as of April 1, 2021, among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank	CCH	10-Q	10.1	8/5/2021
10.16*	Fifth Amendment to Common Security and Account Agreement, dated as of October 8, 2021, among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank
10.17*	Sixth Amendment to Common Security and Account Agreement, dated as of November 16, 2021, among the Company, CCL, CCP and Corpus Christi Pipeline GP, LLC, the Senior Creditor Group Representatives, Société Générale as Intercreditor Agent for the Facility Lenders and any Hedging Banks, Société Générale as Security Trustee, and Mizuho Bank, Ltd. as Account Bank
10.18	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
10.19	Amended and Restated Equity Contribution Agreement, dated May 22, 2018, among the Company and Cheniere	CCH	8-K	10.5	5/24/2018

69

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.20	Amended and Restated Working Capital Facility Agreement, dated June 29, 2018, 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 Bank of Nova Scotia as Working Capital Facility Agent, and Société Générale as Security Trustee	CCH	8-K	10.1	7/2/2018
10.22	Registration Rights Agreement, dated as of August 24, 2021, among CCH and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and Morgan Stanley & Co, LLC, for itself and as representative of the purchasers	CCH	8-K	10.1	8/24/2021
10.23	Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated December 12, 2017, by and between CCL and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)	CCH	10-K/A	10.23	4/27/2018
10.24	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Stage 2 EPC Agreement Revised Table A-2, dated May 18, 2018, (ii) the Change Order CO-00002 Stage 2 EPC Agreement Amended and Restated Attachment C, dated May 18, 2018, (iii) the Change Order CO-00003 Fuel Provisional Sum Adjustment, dated May 24, 2018, (iv) the Change Order CO-00004 Currency Provisional Sum Adjustment, dated May 29, 2018, (v) the Change Order CO-00005 JT Valve Modifications, dated July 10, 2018 and (vi) the Change Order CO-00006 Tank B Soil Conditions, International Building Code, and East Jetty Marine Facility Schedule Acceleration, dated September 5, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)	CCH	10-Q	10.1	11/8/2018
10.25	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00007 Tell-Tale Signs, Additional Tie-Ins, and System Inspection Isometrics, dated October 15, 2018, (ii) the Change Order CO-00008 Insurance Provisional Sum Interim Adjustment, dated November 19, 2018 and (iii) the Change Order CO-00009 Traffic and Logistics Impacts Due to Enforcement of Electronic Logging Devices, dated November 28, 2018 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)	CCH	10-K	10.28	2/26/2019
10.26	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-000010 OSHA Handrail Requirement Changes Impact, dated January 25, 2019, (ii) the Change Order CO-00011 Differing Soil Conditions - Train 3, dated March 7, 2019 and (iii) the Change Order CO-00012 Tank B Logo Deletion, dated March 25, 2019 (Portions of this exhibit have been omitted.)	CCH	10-Q	10.2	5/9/2019

70

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.27	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-000013 Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD), dated May 2, 2019, (ii) the Change Order CO-00014 Tank B Jump-over Tie-In Interface - Long Lead Items, dated May 2, 2019 and (iii) the Change Order CO-00015 Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing (CVD) Q1_2019, dated June 4, 2019 (Portions of this exhibit have been omitted.)	CCH	10-Q	10.2	8/8/2019
10.28	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-000016 Tank B Jump-over Tie-In (Part 1) and Deletion of East Jetty Shroud, dated August 5, 2019, (ii) the Change Order CO-00017 H2S Removal Skid PSVs Modifications and Revision to Chemical Cleaning Milestones, dated August 5, 2019 and (iii) the Change Order CO-00018 Cold Box Redesign Major Permanent Plant Materials and Ethylene Cold Box’s E-1504 Partial Mockup, dated September 6, 2019 (Portions of this exhibit have been omitted.)	CCH	10-Q	10.5	11/1/2019
10.29	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00019 Aircraft Warning Lights, dated September 23, 2019, (ii) the Change Order CO-00020 Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD) Q2_2019, dated October 8, 2019, (iii) the Change Order CO-00021 Spare Transition Joints for Potential Future Cold Box Modifications, dated October 8, 2019, (iv) the Change Order CO-00022 Modification of the Train 3 Methane Cold Box, dated December 6, 2019 and (v) the Change Order Co-00023 Section 232 Steel & Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD) Q3_2019, dated December 10, 2019 (Portions of this exhibit have been omitted.)	CCH	10-K	10.18	2/25/2020
10.30	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00024 East Jetty Cooldown Line & Simultaneous Ship Loading, dated January 6, 2020, (ii) the Change Order CO-00025 East Jetty Manual Gas Sampler, dated January 7, 2020, (iii) the Change Order CO-00026 Study for Adding Valve Actuator for E-W Jetty Flow Segregation, dated January 8, 2020, (iv) the Change Order CO-00027 Tank B Isolation of Proposed Fourth In-Tank LNG Pump - Long Lead Items, dated January 8, 2020, (v) the Change Order CO-00028 Tank B Rundown Line (Part I), dated January 31, 2020, (vi) the Change Order CO-00029 9% Nickel and Cryogenic Rebar Provisional Sum Closeout, dated February 18, 2020 and (vii) the Change Order CO-00030 Additional Valve for Isolation in CCL Stage 2 to CCL Stage 3 from Tank B, dated February 18, 2020 (Portions of this exhibit have been omitted)	CCH	10-Q	10.1	4/30/2020

71

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.31	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00031 Tank B Isolation of Proposed 4th In-Tank LNG Pump (Post Start-Up of Tank B) - EPC, dated April 1, 2020, (ii) the Change Order CO-00032 Train 3 Thermowell Upgrades, dated April 3, 2020, (iii) the Change Order CO-00033 Tank B Rundown Line (Part 2) Development Costs, dated April 29, 2020 and (iv) the Change Order CO-00034 Train 3 UPS Modification of MV Motors, dated May 21, 2020 (Portions of this exhibit have been omitted)	CCH	10-Q	10.1	8/6/2020
10.32	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00035 Spill Conveyance from Flare KO Drum Area, dated July 6, 2020, (ii) the Change Order CO-00036 Tie-Ins for Heavy Hydrocarbon Removal Modifications (E&P) Rev 1, dated August 5, 2020, (iii) the Change Order CO-00037 Train 3 PV-16002 Valve Trim Change - Rev 1, dated August 14, 2020, (iv) the Change Order CO-00038 Hot Oil Overpressure Relief, dated August 14, 2020, (v) the Change Order CO-00039 Supply of Nitrogen for Commissioning Units 16, 17 and Feed Gas, dated August 20, 2020 and (vi) the Change Order CO-00040 COVID-19 Impacts, dated September 15, 2020 (Portions of this exhibit have been omitted)	CCH	10-Q	10.1	11/6/2020
10.33	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00041 Additional O&M Support (COVID-19), dated October 2, 2020 and (ii) the Change Order CO-00042 Replacement of Owner Spare Parts, dated December 31, 2020 (Portions of this exhibit have been omitted)	CCH	10-K	10.26	2/24/2021
10.34	Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00043 Early Turnover of Tank B, dated January 13, 2021 (Portions of this exhibit have been omitted)	CCH	10-Q	10.10	5/4/2021
10.35	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
10.36	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
10.37	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
10.38	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
10.39	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
10.40	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
10.41	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
10.42	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

72

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.43	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
10.44	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
10.45	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
10.46	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
10.47	Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing International LLP	CCH	S-4	10.32	1/5/2017
10.48	Amendment No. 1, dated June 26, 2015, to Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing International LLP	CCH	S-4	10.33	1/5/2017
10.49	Amendment No. 2, dated December 27, 2016, to Amended and Restated Base LNG Sale and Purchase Agreement (FOB), dated as of November 28, 2014, between CCL and Cheniere Marketing International LLP	CCH	S-4	10.34	1/5/2017
10.50	LNG Sale and Purchase Agreement (EOG Early IPM), dated December 30, 2019, between CCL (Seller) and Cheniere Marketing International LLP (Buyer)	CCH	10-K	10.34	2/25/2020
21.1*	Subsidiaries of the Company
22.1	List of Issuers and Guarantor Subsidiaries	CCH	S-4	22.1	7/14/2020
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.

73

ITEM 16.    FORM 10-K SUMMARY

None.

74

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 23, 2022

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 23, 2022
Zach Davis
/s/ Aaron Stephenson	Manager	February 23, 2022
Aaron Stephenson
/s/ Leonard E. Travis	Chief Accounting Officer (Principal Accounting Officer)	February 23, 2022
Leonard E. Travis

75