10-K

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, 2019

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 requirements 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 is a shell company (as defined in Rule 12b-2 of the Act).    Yes ☐   No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates: Not applicable

Indicate the number of shares outstanding of the issuer’s classes of common stock, as of the latest practicable date:    Not applicable

Documents incorporated by reference: None  

CHENIERE CORPUS CHRISTI HOLDINGS, LLC

TABLE OF CONTENTS

PART I
Items 1. and 2. Business and Properties	4
Item 1A. Risk Factors	12
Item 1B. Unresolved Staff Comments	24
Item 3. Legal Proceedings	25
Item 4. Mine Safety Disclosure	25
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6. Selected Financial Data	26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	37
Item 8. Financial Statements and Supplementary Data	38
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	76
Item 9A. Controls and Procedures	76
Item 9B. Other Information	76
PART III
Item 10. Managers, Executive Officers and Company Governance	77
Item 11. Executive Compensation	77
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Member Matters	77
Item 13. Certain Relationships and Related Transactions, and Manager Independence	77
Item 14. Principal Accountant Fees and Services	77
PART IV
Item 15. Exhibits and Financial Statement Schedules	78
Item 16. Form 10-K Summary	84
Signatures	85

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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
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, an energy unit
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
SPA	LNG sale and purchase agreement
TBtu	trillion British thermal units, an energy unit
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, 2019, 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.

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” 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 relating to the construction of our Trains and pipeline, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;

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

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

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

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

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

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

• any other statements that relate to non-historical or future information.

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

3

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”), a Houston-based energy infrastructure company primarily engaged in LNG-related businesses, to develop, construct, operate, maintain and own natural gas liquefaction and export facilities (the “Liquefaction Facilities”) and a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction 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 are currently operating two Trains and are constructing one additional Train for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain 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 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 maintaining and operating our assets, including our Trains;

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

• commencing commercial delivery for our long-term SPA customers, of which we have initiated for three of nine long-term SPA customers as of December 31, 2019;

• completing construction and commencing operation of Train 3 of the Liquefaction Project;

• making LNG available to our long-term SPA customers to generate steady and reliable revenues and operating cash flows;

• further expanding and/or optimizing the Liquefaction Project by leveraging existing infrastructure; and

• maintaining a prudent and cost-effective capital structure.

Our Liquefaction Project

We are currently operating two Trains and one marine berth at the Liquefaction Project and are constructing one additional Train and marine berth. We have received authorization from the FERC to site, construct and operate Trains 1 through 3 of the Liquefaction Project. We completed construction of Trains 1 and 2 of the Liquefaction Project and commenced commercial operating activities in February 2019 and August 2019, respectively. The following table summarizes the project completion and construction status of Train 3 of the Liquefaction Project, including the related infrastructure, as of December 31, 2019:

	Train 3
Overall project completion percentage	74.8%
Completion percentage of:
Engineering	98.7%
Procurement	99.5%
Subcontract work	28.3%
Construction	49.5%
Expected date of substantial completion	1H 2021

The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal to FTA countries for a 25-year term and to non-FTA countries for a 20-year term, both of which commenced in June 2019, up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas. The terms of each of these authorizations began on the date of first export thereunder.

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An application was filed in September 2019 to authorize additional exports from the Liquefaction Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 108 Bcf/yr of natural gas, for a total Liquefaction Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of the volumes contemplated in the application. The application is currently pending before DOE.

Customers

CCL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) with nine third parties for Trains 1 through 3 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 70% of the total production capacity from these Trains. Under these SPAs, the customers will purchase LNG from CCL 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 equal to approximately 115% of Henry Hub. The 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. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the Liquefaction Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. 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 for the applicable Train, as specified in each SPA.

In aggregate, the minimum fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to approximately $1.4 billion upon the date of first commercial delivery for Train 2 and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the Liquefaction Project.

The annual contracted cash flows from fixed fees of each buyer of LNG under CCL’s third-party SPAs that constitute more than 10% of CCL’s aggregate fixed fees under all its SPAs for Trains 1 through 3 of the Liquefaction Project are:

• approximately $410 million from Endesa S.A. (“Endesa”);

• approximately $280 million from PT Pertamina (Persero) (“Pertamina”); and

• approximately $270 million from Naturgy LNG GOM, Limited (formerly known as Gas Natural Fenosa LNG GOM, Limited) (“Naturgy”), which is guaranteed by Naturgy Energy Group, S.A. (formerly known as Gas Natural SDG S.A.).

The average annual contracted cash flow from fixed fees for all of our other SPAs with third-parties is approximately $790 million.

In addition, Cheniere Marketing International LLP (“Cheniere Marketing”), an indirect wholly-owned subsidiary of Cheniere, has agreements with CCL to purchase: (1) 15 TBtu per annum of LNG with an approximate term of 23 years, (2) any LNG produced by CCL in excess of that required for other customers at Cheniere Marketing’s option and (3) 0.85 mtpa of LNG with a term of up to seven years associated with an integrated production marketing (“IPM”) gas supply agreement, as described below.

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,
	2019	2018	2017
Endesa	57%	—%	—%
Pertamina	23%	—%	—%

5

Natural Gas Transportation, Storage and Supply

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing variability in natural gas needs for the Liquefaction Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2019, CCL had secured up to approximately 2,999 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to eight years, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.

A portion of the natural gas feedstock transactions for CCL are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.

Construction

CCL entered into separate lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 3 of the Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risk unless certain specified events occur, in which case Bechtel may cause CCL to enter into a change order, or CCL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 3, which is currently under construction, is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2019. As of December 31, 2019, we have incurred $2.0 billion under this contract.

Pipeline Facilities

In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended (the “NGA”), authorizing CCP to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline is designed to transport 2.25 Bcf/d of natural gas feedstock required by the Liquefaction Project from the existing regional natural gas pipeline grid. The construction of the Corpus Christi Pipeline was completed in the second quarter of 2018.

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 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 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.

6

 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 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.

We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC 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 additional facilities for the liquefaction and export of domestically-produced natural gas (“Corpus Christi Stage 3”) at the existing Liquefaction Project, 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.

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 each terminal from currently authorized levels to an amount which reflects more accurately the capacity of each 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 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.

7

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 $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 U.S. Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations have not materially affected our construction or operations.

DOE Export License

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, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. 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.

In October 2019, PHMSA published final rules revising its regulations governing the safety of certain gas transmission pipelines (effective July 1, 2020) and established new enforcement procedures for the issuance of temporary emergency orders (effective December 2, 2019).

PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $218,000 per day per violation, with a maximum administrative civil penalty of approximately $2 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 Services, 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 (“RRC”).

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

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Commodity Futures Trading Commission (“CFTC”)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The regulatory regime created by the Dodd-Frank Act is designed primarily to (1) regulate certain participants in the swaps markets, including entities falling within the categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange trading of standardized swaps of certain classes as designated by the CFTC, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authority of the CFTC and the SEC regarding the derivatives markets. Most of the regulations are already in effect, while other rules and regulations, including the proposed margin rules, position limits and commodity clearing requirements, remain to be finalized or effectuated. Therefore, the impact of those rules and regulations on our business continues to be uncertain.

A provision of the Dodd-Frank Act requires the CFTC, in order to diminish or prevent excessive speculation in commodity markets, to adopt rules, as it finds necessary and appropriate, imposing new position limits on certain physical commodity futures contracts and options thereon, as well as economically equivalent swaps traded on registered swap trading platforms and on over-the-counter swaps that perform a significant price discovery function with respect to certain markets. In that regard, the CFTC has re-proposed position limits rules that would modify and expand the applicability of limits on speculative positions in certain physical commodity futures contracts and economically equivalent futures, options and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging and other types of transactions. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

Pursuant to rules adopted by the CFTC, certain interest rate swaps and index credit default swaps must be cleared through a derivatives clearing organization and executed on an exchange or swap execution facility. The CFTC has not yet proposed to designate swaps in any other asset classes, including swaps relating to physical commodities, for mandatory clearing and trade execution, but could do so in the future. Although we expect to qualify for the end-user exception from the mandatory clearing and exchange-trading requirements applicable to any swaps that we enter into to hedge our commercial risks, the mandatory clearing and exchange-trading requirements may apply to other market participants, including our counterparties (who may be registered as Swap Dealers), with respect to other swaps, and the application of such rules may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.

As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require Swap Dealers and Major Swap Participants, including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

Any new rules or changes to existing rules promulgated under the Dodd-Frank Act could (1) impair the availability of derivatives, (2) materially increase the cost of, or decrease the liquidity of, the derivatives we use to hedge, (3) significantly alter the terms and conditions of derivatives and (4) potentially increase our exposure to less creditworthy counterparties. Further, any resulting reduction in the use of derivatives could make cash flow more volatile and less predictable, which in turn could adversely affect our ability to plan for and fund capital expenditures.

Pursuant to the Dodd-Frank Act, the CFTC has 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.

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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 (“CAA”)

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

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 have largely been stayed or repealed including by amendments adopted by the EPA on February 23, 2018, additional proposed amendments to new source performance standards for the oil and gas industry on September 24, 2019, and the EPA’s June 19, 2019 adoption of the Affordable Clean Energy rule for power generation.

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 or additional operating restrictions and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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 (“CWA”)

The Liquefaction Project is subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Texas, by the TCEQ).

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.

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Protection of Species, Habitats and Wetlands

Various federal and state statutes, such as the Endangered Species Act (the “ESA”), the Migratory Bird Treaty Act (“MBTA”), 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.

In August 2019, the U.S. Fish and Wildlife Service (the “FWS”) announced a series of changes to the rules implementing the ESA, including revisions to the regulations governing interagency cooperation, listing species and delisting critical habitat, and prohibitions related to threatened wildlife and plants. The revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions.

In addition, in December 2017, the Department of Interior’s (“DOI’s”) Solicitor’s Office issued an official opinion that the MBTA’s broad prohibition on “taking” migratory birds applies only to affirmative actions and does prohibit incidental harm. In April 2018 the FWS issued guidance consistent with the DOI’s opinion and on January 30, 2020, the FWS issued a proposed rule defining the scope of the MBTA to cover only actions directed at migratory birds, their nests or their eggs.

We do not believe that our operations, or the construction and operations of our Liquefaction Project, will be materially and adversely affected by these recent regulatory actions.

Market Factors and Competition

If and 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. Cheniere is currently constructing and operating natural gas liquefaction facilities in Cameron Parish, Louisiana through its subsidiary Sabine Pass Liquefaction, LLC (“SPL”), which has entered into fixed price SPAs with third parties for the sale of LNG from Trains 1 through 6 of these natural gas liquefaction facilities, and may continue to enter into commercial agreements with respect to this natural gas liquefaction facility that might otherwise have been entered into with respect to Train 3. 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 markets than us. Our affiliates have proximity to our customers, with offices located in Houston, London, Singapore, Beijing and Tokyo.

Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sale of LNG by 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 and economic growth in developing countries. 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.  Global demand for natural gas is projected by the International Energy Agency to grow by approximately 27 trillion cubic feet (“Tcf”) between 2018 and 2030 and 39 Tcf between 2018 and 2035. LNG’s share is seen growing from about 11% in 2018 to about 16% of the global gas market in 2030 and 18% in 2035.  Wood Mackenzie Limited (“WoodMac”) forecasts that global demand for LNG will increase by approximately 79%, from approximately 316 mtpa, or 15.2 Tcf, in 2018, to approximately 566 mtpa, or 27.2 Tcf, in 2030 and to 678 mtpa or 32.6 Tcf in 2035. WoodMac also forecasts LNG production from existing operational facilities and new facilities already under construction will be able to supply the market with approximately 469 mtpa in 2030, declining to 430 mtpa in 2035. This will result in a market need for construction of an additional approximately 97 mtpa of LNG production by 2030 and about 248 mtpa by 2035.  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.

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Our LNG terminal business has limited exposure to the decline in oil prices 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.  As of January 31, 2020, U.S. natural gas prices indicate that LNG exported from the U.S. continues to be competitively priced, supporting the opportunity for U.S. LNG to fill uncontracted future demand through the execution of long-term and medium-term contracting of LNG from our terminal.

Subsidiaries

Our assets are generally held by our subsidiaries. We conduct most of our business through these subsidiaries, including the development, construction and 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, 2020, Cheniere and its subsidiaries had 1,530 full-time employees, including 330 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 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; and

• Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business.

Risks Relating to Our Financial Matters

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

As of December 31, 2019, we had no cash and cash equivalents, $79.7 million of current restricted cash and $10.2 billion of total debt outstanding on a consolidated basis (before unamortized debt issuance costs), excluding $470.8 million of outstanding letters of credit. We incur, and will incur, significant interest expense relating to the assets at the Liquefaction Project. Our ability to refinance our indebtedness will depend on our ability to access the 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.

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We have not always been profitable historically, and we have not historically had positive operating cash flow. We may not achieve profitability or generate positive operating cash flow in the future.

We had net losses of $374.3 million and $48.7 million for the years ended December 31, 2019 and 2017, respectively. In addition, our net cash flow used in operating activities was $33.4 million, $60.2 million and $64.3 million for the years ended December 31, 2019, 2018 and 2017, respectively. In the future, we may incur operating losses and experience negative operating cash flow. We may not be able to reduce costs, increase revenues or reduce our debt service obligations sufficiently to maintain our cash resources, which could cause us to have inadequate liquidity to continue our business.

We will continue to incur significant capital and operating expenditures while we develop and construct the Liquefaction Project. Any delays beyond the expected development period for Train 3 could cause operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate any significant positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete the applicable Train.

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 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, 2019, we had SPAs with nine third-party customers. We are dependent on each customer’s continued willingness and ability to perform its obligations under its SPA. We are exposed to the credit risk of any guarantor of these customers’ obligations under their respective SPA in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its SPA, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the SPA.

Each of our customer contracts is subject to termination under certain circumstances.

Each of our SPAs contains various termination rights allowing our customers to terminate their SPAs, including, without limitation: (1) upon the occurrence of certain events of force majeure; (2) if we fail to make available specified scheduled cargo quantities; and (3) delays in the commencement of commercial operations. We may not be able to replace these SPAs on desirable terms, or at all, if they are terminated.

Our use of hedging arrangements may adversely affect our future operating results or liquidity.

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements could expose us to risk of financial loss in some circumstances, including when:

• expected supply is less than the amount hedged;

• the counterparty to the hedging contract defaults on its contractual obligations; or

• there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.

The provisions of the Dodd-Frank Act and the rules adopted and to be adopted by the CFTC, the SEC and other federal regulators establishing federal regulation of the over-the-counter (“OTC”) derivatives market and entities like us that participate

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in that market may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminal and to secure natural gas feedstock for our liquefaction facilities.

The CFTC has re-proposed position limits rules that would modify and expand the applicability of position limits on the amounts of certain speculative futures contracts, as well as economically equivalent options, futures and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging positions and other types of transactions. To the extent the revised CFTC position limits proposal becomes final, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

Under the Dodd-Frank Act and the rules adopted thereunder, certain swaps may be required to be cleared through a derivatives clearing organization. While the CFTC has designated certain interest rate swaps and index credit default swaps for mandatory clearing, it has not yet finalized rules designating any physical commodity swaps, for mandatory clearing or mandatory exchange trading. Further, we qualify for the end-user exception from the mandatory clearing and trade execution requirements for our swaps entered into to hedge our commercial risks. If we fail to qualify for that exception as to any swap we enter into and have to clear that swap through a derivatives clearing organization, we could be required to post margin (or post higher margin than if we entered into an uncleared OTC swap) with respect to such swap, our cost of entering into and maintaining such swap could increase and we would not enjoy the same flexibility with the cleared swaps that we enjoy with the uncleared OTC swaps we enter into. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.

As required by the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require certain market participants to collect and post initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users and certain registered swap dealers and major swap participants. Although we believe we will not be required to post margin with respect to any uncleared swaps we enter into in the future, were we required to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. Our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, contractually require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.

The Dodd-Frank Act also imposes other regulatory requirements on swaps market participants, including end users of swaps, such as regulations relating to swap documentation, reporting and recordkeeping, and certain business conduct rules applicable to swap dealers and major swap participants. Together with the Basel III capital requirements on certain swaps market participants, the regulatory requirements of the Dodd-Frank Act and the rules thereunder relating to swaps and derivatives market participants could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter and reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.

The Federal Reserve Board also has proposed rules that would limit certain physical commodity activities of financial holding companies. Such rules, if adopted, may adversely affect our ability to execute our strategies by restricting our available counterparties for certain types of transactions, limiting our ability to obtain certain services, and reducing liquidity in physical and financial markets. It is uncertain at this time whether, when and in what form the Federal Reserve’s proposed rules regarding financial holding companies may become final and effective.

We expect that our hedging activities will remain subject to significant and developing regulations and regulatory oversight. However, the full impact of the various U.S. (and non-U.S.) regulatory developments in connection with these activities will not be known with certainty until such derivatives market regulations are fully implemented and related market practices and structures are fully developed.

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Risks Relating to the Completion of Our Liquefaction Facilities and the Development and Operation of Our Business 

Our ability to complete construction of the Liquefaction Project depends on our ability to obtain sufficient equity funding to cover the remaining capital costs. If we are unable to obtain sufficient equity funding, we may experience delays in completing, or we may not be able to complete, construction of the Liquefaction Project.

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, 2019, we have received $557.9 million in contributions under the Equity Contribution Agreement. Cheniere is only required to make additional contributions under the Equity Contribution Agreement after the commitments under our credit facility (“CCH Credit Facility”) have been reduced to zero and to the extent certain cash flows from operations of the Liquefaction Project are unavailable to fund Liquefaction Project costs.

The insufficiency of equity contributions to meet the equity-funded portion of our finance plan for the remaining costs to construct the Liquefaction Project may cause a delay in development of our Trains and we may not be able to complete Train 3. Even if we are able to obtain alternative equity funding, the funding may be inadequate to cover any increases in costs and may not be sufficient to mitigate the impact of delays in completion of Train 3, which may cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. Any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cost overruns and delays in the completion of one or more Trains, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The actual construction costs of Train 3 and any additional Trains may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future EPC contracts resulting from the occurrence of certain specified events that may give Bechtel the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We have already experienced increased costs due to change orders. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations.

Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to the EPC contracts with Bechtel or any future EPC contract related to additional Trains, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are dependent on Bechtel and other contractors for the successful completion of the Liquefaction Project.

Timely and cost-effective completion of the Liquefaction Project in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of Bechtel and our other contractors under their agreements. The ability of Bechtel and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:

• design and engineer each Train to operate in accordance with specifications;

• engage and retain third-party subcontractors and procure equipment and supplies;

• respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;

• attract, develop and retain skilled personnel, including engineers;

• post required construction bonds and comply with the terms thereof;

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• manage the construction process generally, including coordinating with other contractors and regulatory agencies; and

• maintain their own financial condition, including adequate working capital.

Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Liquefaction Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of Bechtel and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Liquefaction Project or result in a contractor’s unwillingness to perform further work on the Liquefaction Project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We have historically not had any revenues or positive cash flows. Our ability to achieve profitability and generate positive operating cash flow in the future is subject to significant uncertainty.

We will continue to incur significant capital and operating expenditures while we develop and construct the Liquefaction Project. We began to generate cash flow from operations in the first quarter of 2019 when substantial completion of Train 1 was achieved.

Any delays beyond the construction of Train 3 or the development period for any future Train we may develop could result in operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flow under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate any significant positive operating cash flows and achieve profitability in the future is dependent on our ability to successfully and timely complete the applicable Train.

We are relying on estimates for the future capacity ratings and performance capabilities of the Liquefaction Project, and these estimates may prove to be inaccurate.

We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the Liquefaction Project. If any Train, when actually constructed, fails to have the capacity ratings and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

If third-party pipelines and other facilities interconnected to our pipeline and facilities are or become unavailable to transport natural gas, this 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 or any other reason, our ability to meet our SPA obligations and continue shipping natural gas from producing regions or to end markets could be restricted, thereby reducing our revenues which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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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, LNG terminal, including the Liquefaction Project and other facilities, and 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. Although the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the three Trains and related facilities of the Liquefaction Project and Section 7 of the NGA authorizing the siting, construction and operation of the Corpus Christi Pipeline, the FERC orders require us to comply with certain ongoing conditions and obtain certain additional approvals in conjunction with ongoing construction and operations of the Liquefaction Project. We will be required to obtain similar approvals and permits with respect to any expansion or modification of our liquefaction and pipeline facilities. We cannot control the outcome of the regulatory review and approval processes. Certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We do not know whether or when any such approvals or permits can be obtained, or whether any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, including as a result of untimely notices or filings, we may not be able to recover our investment in our projects. Additionally, government disruptions, such as a U.S. government shutdown, may delay or halt our ability to obtain and maintain necessary approvals and permits. 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, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Delays in the completion of Train 3 could lead to reduced revenues or termination of one or more of the SPAs by our customers.

Any delay in completion of Train 3 could cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. In particular, each of our SPAs provides that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our Corpus Christi Pipeline and its FERC gas tariffs are subject to FERC regulation.

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 the 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, the 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.

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

The PHMSA requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high 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 integrity;

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• 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.

Our business could be materially and adversely affected if we lose the right to situate the Corpus Christi Pipeline on property owned by third parties.

We do not own the land on which the Corpus Christi Pipeline is situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate the Corpus Christi Pipeline, our business could be materially and adversely affected.

Hurricanes 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 caused temporary suspension in construction of our Liquefaction Project or caused minor damage to our Liquefaction Project. 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 the Liquefaction Project or our other facilities and increases in 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.

We may not be successful in fully implementing our proposed business strategy to provide liquefaction capabilities at the Liquefaction Project.

It will take several years to finish construction of Train 3 at the Liquefaction Project and any additional stages of the Liquefaction Project that we may develop, and even if successfully constructed, the Liquefaction Project already is, and will continue to be, subject to the operating risks described herein. Accordingly, there are many risks associated with the Liquefaction Project, and if we are not successful in implementing our business strategy, we may not be able to generate cash flows, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may not complete construction or operate our proposed LNG facility or all of our Trains or any additional LNG facilities or Trains beyond those currently planned, which could limit our growth prospects.

We may not complete construction of our proposed LNG facility or some of our Trains, whether due to lack of commercial interest or inability to obtain financing or otherwise. Our ability to develop additional liquefaction facilities will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world. Competitors may have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to sources of natural gas and LNG than we do. If we are unable or unwilling to construct and operate additional LNG facilities, our prospects for growth will be limited.

Our cost estimates for Trains are subject to change as a result of cost overruns, change orders under existing or future construction contracts, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules. In the event we experience cost overruns, delays or both, the amount of funding needed to complete a Train could exceed our available funds and result in our failure to complete such Train and thereby negatively impact our business and limit our growth prospects.

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We may enter into certain arrangements to share the use and operations of our facilities with adjacent projects, which would require us to meet certain conditions under the indentures governing each of our senior notes (the “CCH Indentures”). Despite the protection provided by the CCH Indentures, the nature of such sharing arrangements is not currently known and may limit our operational flexibility, use of land and/or facilities and the ability of the security trustee under the Common Security and Account Agreement to take certain enforcement actions against the security interest in substantially all of our assets and the assets of our current and any future guarantors.

Cheniere is developing up to seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG adjacent to the Liquefaction Project, along with a second natural gas pipeline. If these entities ultimately construct these Trains and facilities or any additional Trains or facilities, they would not be part of the Liquefaction Project but CCL and CCP may nevertheless enter into sharing arrangements with the entities owning those Trains and related facilities that would involve sharing the use and capacity of each other’s land and facilities, including pooling of capacity of Trains, sharing of common facilities, such as storage tanks and berths, and use of capacity of the pipeline facilities, to the extent permitted under the Common Terms Agreement and the CCH Indentures. CCL and CCP also may transfer and/or amend previously-obtained permits and other authorizations or applications such that they may be used by those entities. As future arrangements that would only be fully determined if the circumstances arise, there is uncertainty as to the full scope and impact of these sharing arrangements. The CCH Indentures requires us to meet certain conditions in respect of such sharing arrangements. These sharing arrangements would be subject to quiet enjoyment rights for CCL, CCP and the owner of the other Train(s). The nature of these sharing arrangements could limit the ability of the security trustee under the Common Security and Account Agreement to take certain enforcement action against the security interest in substantially all of our assets and the assets of our current and any future guarantors in respect of which quiet enjoyment rights have been granted to a third party.

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.

A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damages.

Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are entirely dependent on Cheniere, including employees of Cheniere and its subsidiaries, for key personnel, and a loss of key personnel could have a material adverse effect on our business.

As of January 31, 2020, Cheniere and its subsidiaries had 1,530 full-time employees, including 330 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 liquefaction 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, 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.

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

A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations 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.

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 developing the Sabine Pass Liquefaction Project in Cameron Parish, Louisiana, and is developing additional Trains and related facilities and a second natural gas pipeline at a site adjacent to the Liquefaction Project. Cheniere may enter into commercial arrangements with respect to these projects that might otherwise have been entered into with respect to Train 3 or another expansion of the Liquefaction Project and may require that we transfer and/or amend permits and other authorizations we have received to enable them to be used by such projects.

We have or will have numerous contracts and commercial arrangements with Cheniere and its affiliates, including future SPAs, transportation, interconnection, marketing and gas balancing arrangements with one or more Cheniere-affiliated entities as well as other agreements and arrangements. We anticipate that we will enter into other such agreements in the future, which cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates will 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.

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

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

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

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

• increases in the cost to supply natural gas feedstock to our liquefaction project;

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

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

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

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

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Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, 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 extreme weather events and temperature volatility resulting from climate change;

• 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;

• 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 flows, 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 will be 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

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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 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 our LNG terminal and liquefaction facilities are and will be subject to the inherent risks associated with these types of operations, including explosions, 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. 

Operation of the Liquefaction Project involves significant risks.

As of December 31, 2019, Trains 1 and 2 of the Liquefaction Project had reached substantial completion and were placed into operation, and Train 3 was under construction. As more fully discussed in these Risk Factors, the Liquefaction Project faces operational risks, including the following:

• the facilities performing below expected levels of efficiency;

• breakdown or failures of equipment;

• operational errors by vessel or tug operators;

• operational errors by us or any contracted facility operator;

• labor disputes; and

• weather-related interruptions of operations.

We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements, which could have a material adverse effect on us.

We believe that there is sufficient capacity on the Corpus Christi Pipeline to accommodate all of our natural gas feedstock transportation requirements for Trains 1 through 3. We have also entered into firm transportation agreements with several third-party pipeline companies partially securing firm pipeline transportation capacity for the Liquefaction Project on interstate and intrastate pipelines which will connect to the Corpus Christi Pipeline for the production contemplated for Trains 1 through 3. If and when we need to replace one or more of our existing agreements with these interconnecting pipelines or enter into additional agreements, we may not be able to do so on commercially reasonable terms or at all, which would impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition,

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operating results, cash flow, liquidity and prospects. Additionally, the capacity on the Corpus Christi Pipeline and the interconnecting pipelines may not be sufficient to accommodate any additional Trains. Development of any additional Trains will require us to secure additional pipeline transportation capacity but we may not be able to do so on commercially reasonable terms or at all.

Various economic and political factors could negatively affect the development, construction and operation of the Liquefaction Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:

• increased construction costs;

• economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;

• decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;

• the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;

• political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and

• any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.

There may be shortages of LNG vessels worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of our business and our customers because of:

• an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;

• political or economic disturbances in the countries where the vessels are being constructed;

• changes in governmental regulations or maritime self-regulatory organizations;

• work stoppages or other labor disturbances at the shipyards;

• bankruptcy or other financial crisis of shipbuilders;

• quality or engineering problems;

• weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and

• shortages of or delays in the receipt of necessary construction materials.

Terrorist attacks, cyber incidents or military campaigns may adversely impact our business.

A terrorist attack, cyber incident or military incident involving an LNG facility, our infrastructure or an LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, which would increase our costs and decrease our cash flows. A terrorist incident or cyber incident may also result in temporary or permanent closure of our existing facilities, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of terrorism, cyber incidents or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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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 pipelines, 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 have largely been stayed or repealed including by amendments adopted by the EPA on February 23, 2018, additional proposed amendments to new source performance standards for the oil and gas industry on September 24, 2019, and the EPA’s June 19, 2019 adoption of the Affordable Clean Energy rule for power generation. However, Congress or a future Administration may reverse these decisions. 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 terminal, or could increase compliance costs for our operations.

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

Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Substantially all of our anticipated revenue in 2020 will be dependent upon the Liquefaction Project. Due to our lack of asset and geographic diversification, an adverse development at the Liquefaction Project or in the LNG industry would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURE

Not applicable.

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PART II

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

Not applicable.

ITEM 6. SELECTED FINANCIAL DATA

Selected financial data set forth below are derived from our audited consolidated and combined financial data for the periods indicated for CCH (in thousands). The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report.

	Year Ended December 31,
	2019			2018			2017			2016			2015
Consolidated Statement of Operations Data:
Revenues	$	1,405,170		$	—		$	—		$	—		$	—
Income (loss) from operations	74,820			(21,879		)	(19,161		)	(6,472		)	(23,044		)
Other income (expense)	(449,116		)	28,165			(29,491		)	(79,015		)	(204,053		)
Net income (loss)	(374,296		)	6,286			(48,652		)	(85,487		)	(227,097		)

	December 31,
	2019		2018		2017		2016		2015
Consolidated Balance Sheet Data:
Property, plant and equipment, net	$	12,507,419	$	11,138,825	$	8,261,383	$	6,076,672	$	3,924,551
Total assets	13,111,512		11,720,353		8,659,880		6,636,448		4,304,042
Long-term debt, net	10,093,480		9,245,552		6,669,476		5,081,715		2,713,000

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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. Our discussion and analysis includes the following subjects: 

• Overview of Business 

• Overview of Significant Events 

• Liquidity and Capital Resources

• Contractual Obligations

• Results of Operations 

• Off-Balance Sheet Arrangements  

• Summary of Critical Accounting Estimates 

• Recent Accounting Standards

Overview of Business

We are operating and constructing a natural gas liquefaction and export facility (the “Liquefaction Facilities”) and operating a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries CCL and CCP, respectively.

We are currently operating two Trains and are constructing one additional Train for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain 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.

Overview of Significant Events

Our significant events since January 1, 2019 and through the filing date of this Form 10-K include the following:

Strategic

• In September 2019, CCL entered into an integrated production marketing (“IPM”) transaction with EOG Resources, Inc. (“EOG”) to purchase 140,000 MMBtu per day of natural gas on a long-term basis beginning in early 2020, at a price based on the Platts Japan Korea Marker (“JKM”), net of a fixed liquefaction fee and certain costs incurred by Cheniere.

Operational

• As of February 21, 2020, over 100 cumulative LNG cargoes totaling approximately 8 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

• In February 2019 and August 2019, CCL achieved substantial completion of Trains 1 and 2 of the Liquefaction Project, respectively, and commenced operating activities.

Financial

• We completed the following debt transactions:

◦ In November 2019, we issued an aggregate principal amount of $1.5 billion of 3.700% Senior Secured Notes due 2029 (the "2029 CCH Senior Notes"). Net proceeds of the offering were used to prepay a portion of the outstanding borrowings under the amended and restated CCH Credit Facility (the “CCH Credit Facility”).

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◦ In October 2019, we issued an aggregate principal amount of $475 million of 3.925% Senior Secured Notes due 2039 (the "3.925% CCH Senior Notes") pursuant to a note purchase agreement with certain accounts managed by BlackRock Real Assets and certain accounts managed by MetLife Investment Management to prepay a portion of the outstanding indebtedness under the CCH Credit Facility.

◦ In September 2019, we issued an aggregate principal amount of $727 million of 4.80% Senior Secured Notes due 2039 (the “4.80% CCH Senior Notes”) pursuant to a note purchase agreement originally entered into in June 2019 (“CCH Note Purchase Agreement”) with Allianz Global Investors GmbH, to prepay a portion of the outstanding indebtedness under the CCH Credit Facility.

• In September 2019, Fitch Ratings (“Fitch”) and S&P Global Ratings each assigned an investment grade rating of BBB- to our senior secured debt, and Fitch assigned an investment grade issuer default rating of BBB- to us. In October 2019, Moody’s Investors Service upgraded its rating of our senior secured debt from Ba2 to Ba1 (Positive Outlook).

• In June 2019, the date of first commercial delivery was reached under the 20-year SPAs with Endesa S.A. and PT Pertamina (Persero) relating to Train 1 of the Liquefaction Project.

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at December 31, 2019 and 2018 (in thousands):

	December 31,
	2019		2018
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the Liquefaction Project	79,741		289,141
Available commitments under the following credit facilities:
CCH Credit Facility	—		981,675
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	729,216		716,475

Corpus Christi LNG Terminal

Liquefaction Facilities

We are currently operating two Trains and one marine berth at the Liquefaction Project and are constructing one additional Train and marine berth. We have received authorization from the FERC to site, construct and operate Trains 1 through 3 of the Liquefaction Project. We completed construction of Trains 1 and 2 of the Liquefaction Project and commenced commercial operating activities in February 2019 and August 2019, respectively. The following table summarizes the project completion and construction status of Train 3 of the Liquefaction Project, including the related infrastructure, as of December 31, 2019:

	Train 3
Overall project completion percentage	74.8%
Completion percentage of:
Engineering	98.7%
Procurement	99.5%
Subcontract work	28.3%
Construction	49.5%
Expected date of substantial completion	1H 2021

The DOE has authorized the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal to FTA countries for a 25-year term and to non-FTA countries for a 20-year term, both of which commenced in June 2019, up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas. The terms of each of these authorizations began on the date of first export thereunder.

An application was filed in September 2019 to authorize additional exports from the Liquefaction Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 108 Bcf/yr of natural gas, for a total Liquefaction Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of the volumes contemplated in the application. The application is currently pending before DOE.

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Customers

CCL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) with nine third parties for Trains 1 through 3 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 70% of the total production capacity from these Trains. Under these SPAs, the customers will purchase LNG from CCL on a 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 equal to approximately 115% of Henry Hub. The 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. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the Liquefaction Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. 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 for the applicable Train, as specified in each SPA.

In aggregate, the minimum fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to approximately $1.4 billion upon the date of first commercial delivery for Train 2 and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the Liquefaction Project.

In addition, Cheniere Marketing International LLP (“Cheniere Marketing”), an indirect wholly-owned subsidiary of Cheniere, has agreements with CCL to purchase: (1) 15 TBtu per annum of LNG with an approximate term of 23 years, (2) any LNG produced by CCL in excess of that required for other customers at Cheniere Marketing’s option and (3) 0.85 mtpa of LNG with a term of up to seven years associated with the IPM gas supply agreement between CCL and EOG.

Natural Gas Transportation, Storage and Supply

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing variability in natural gas needs for the Liquefaction Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2019, CCL had secured up to approximately 2,999 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to eight years, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.

A portion of the natural gas feedstock transactions for CCL are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.

Construction

CCL entered into separate lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 3 of the Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risk unless certain specified events occur, in which case Bechtel may cause CCL to enter into a change order, or CCL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 3, which is currently under construction, is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2019. As of December 31, 2019, we have incurred $2.0 billion under this contract.

Pipeline Facilities

In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended, authorizing CCP to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline

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is designed to transport 2.25 Bcf/d of natural gas feedstock required by the Liquefaction Project from the existing regional natural gas pipeline grid. The construction of the Corpus Christi Pipeline was completed in the second quarter of 2018.

Capital Resources

We expect to finance the construction costs of the Liquefaction Project from one or more of the following: operating cash flows from CCL and CCP, project debt and equity contributions from Cheniere. The following table provides a summary of our capital resources from borrowings and available commitments for the Liquefaction Project, excluding any equity contributions, at December 31, 2019 and 2018 (in thousands):

	December 31,
	2019		2018
Senior notes (1)	$	6,952,000	$	4,250,000
Credit facilities outstanding balance (2)	3,282,655		5,323,737
Letters of credit issued (2)	470,784		315,525
Available commitments under credit facilities (2)	729,216		1,698,150
Total capital resources from borrowings and available commitments (3)	$	11,434,655	$	11,587,412

(1) Includes 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”), 5.875% Senior Secured Notes due 2025 (the “2025 CCH Senior Notes”), 5.125% Senior Secured Notes due 2027 (the “2027 CCH Senior Notes”), 4.80% CCH Senior Notes, 3.925% CCH Senior Notes and 2029 CCH Senior Notes (collectively, the “CCH Senior Notes”).

(2) Includes CCH Credit Facility and CCH Working Capital Facility.

(3) Does not include additional borrowings or contributions by our indirect parents which may be used for the Liquefaction Project.

CCH Senior Notes

The CCH Senior Notes are jointly and severally guaranteed by our subsidiaries, CCL, CCP and CCP GP (each a “Guarantor” and collectively, the “Guarantors”). The indentures governing the CCH Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to us or any of our restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of us and our restricted subsidiaries taken as a whole; or permit any Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. The covenants included in the respective indentures that govern the CCH Senior Notes are subject to a number of important limitations and exceptions.

The CCH Senior 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 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 Notes. The CCH Senior Notes are secured by a first-priority security interest in substantially all of our assets and the assets of the CCH Guarantors.

At any time prior to six months before the respective dates of maturity for each of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the appropriate indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time within six months of the respective dates of maturity for each of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

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CCH Credit Facility

In May 2018, we amended and restated the CCH Credit Facility to increase total commitments under the CCH Credit Facility from $4.6 billion to $6.1 billion. Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in us. As of December 31, 2019 and 2018, we had zero and $1.0 billion of available commitments and $3.3 billion and $5.2 billion of loans outstanding under the CCH Credit Facility, respectively. As part of the capital allocation framework announced by Cheniere in June 2019, we prepaid $152.8 million of outstanding borrowings under the CCH Credit Facility during the year ended December 31, 2019.

The CCH Credit Facility matures on June 30, 2024, with principal payments due quarterly commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following the completion of the Liquefaction Project as defined in the common terms agreement and (2) a set date determined by reference to the date under which a certain LNG buyer linked to the last Train of the Liquefaction Project to become operational is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the completion of Trains 1 through 3 and designed to achieve a minimum projected fixed debt service coverage ratio of 1.50:1.

Under the CCH Credit Facility, we are required to hedge not less than 65% of the variable interest rate exposure of our senior secured debt. We are restricted from making certain distributions under agreements governing our indebtedness generally until, among other requirements, the completion of the construction of Trains 1 through 3 of the Liquefaction Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.

CCH Working Capital Facility

In June 2018, we amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility from $350 million to $1.2 billion. The CCH Working Capital Facility is intended to be used for loans (“CCH Working Capital Loans”) and the issuance of letters of credit for certain working capital requirements related to developing and operating the Liquefaction Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the Guarantors. We may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility. As of December 31, 2019 and 2018, we had $729.2 million and $716.5 million of available commitments, $470.8 million and $315.5 million aggregate amount of issued letters of credit and zero and $168.0 million of loans outstanding under the CCH Working Capital Facility, respectively.

The CCH Working Capital Facility matures on June 29, 2023, and we may prepay the CCH Working Capital Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans”) at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. We are required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the assets of the Guarantors as well as all of our membership interests and the membership interest in each of the Guarantors on a pari passu basis with the CCH Senior Notes and the CCH Credit Facility.

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, 2019, we have received $557.9 million in contributions under the Equity Contribution Agreement and Cheniere has posted $585.0 million of letters of credit on our behalf under its revolving credit facility. 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.

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Early Works Equity Contribution Agreement

In conjunction with the amendment and restatement of the Equity Contribution Agreement, we terminated the early works equity contribution agreement with Cheniere entered into in December 2017. Prior to termination in May 2018, we had received $250.0 million in contributions from Cheniere under the early works equity contribution agreement.

Restrictive Debt Covenants

As of December 31, 2019, we were in compliance with all covenants related to our debt agreements.

LIBOR

The use of LIBOR is expected to be phased out by the end of 2021. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue to work with our lenders to pursue any amendments to our debt agreements that are currently subject to LIBOR and will continue to monitor, assess and plan for the phase out of LIBOR.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the years ended December 31, 2019, 2018 and 2017 (in thousands). 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,
	2019			2018			2017
Operating cash flows	$	(33,373	)	$	(60,162	)	$	(64,316	)
Investing cash flows	(1,519,220		)	(2,960,267		)	(1,962,209		)
Financing cash flows	1,343,193			3,083,011			1,982,544
Net increase (decrease) in cash, cash equivalents and restricted cash	(209,400		)	62,582			(43,981		)
Cash, cash equivalents and restricted cash—beginning of period	289,141			226,559			270,540
Cash, cash equivalents and restricted cash—end of period	$	79,741		$	289,141		$	226,559

Operating Cash Flows

Operating cash net outflows during the years ended December 31, 2019, 2018 and 2017 were $33.4 million, $60.2 million and $64.3 million, respectively. The decrease in operating cash net outflows in 2019 compared to 2018 was primarily due to increased cash receipts from the sale of LNG cargoes, as a result of the commencement of operations of Trains 1 and 2 of the Liquefaction Project in March 2019 and August 2019, respectively, partially offset by increased operating costs and expenses. The decrease in operating cash flows in 2018 compared to 2017 was primarily due to decreased cash used for settlement of derivative instruments, partially offset by increased cash used for working capital requirements.

Investing Cash Flows

Investing cash net outflows during the years ended December 31, 2019, 2018 and 2017 were $1,519.2 million, $2,960.3 million and $1,962.2 million, respectively, and were primarily used to fund the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion.

Financing Cash Flows

Financing cash net inflows during the year ended December 31, 2019 were $1,343.2 million, primarily as a result of:

• issuance of an aggregate principal of $1.5 billion of the 2029 CCH Senior Notes, $727.0 million of the 4.80% CCH Senior Notes and $475 million of the 3.925% CCH Senior Notes, which were used to prepay a portion of the outstanding balance of the CCH Credit Facility;

• $16.2 million of debt issuance costs primarily related to up-front fees paid upon the closing of these transactions;

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• $11.1 million of debt extinguishment cost related to the issuance of the 2029 CCH Senior Notes;

• $981.7 million of borrowings and $2,854.8 million of repayments under the CCH Credit Facility;

• $521.0 million of borrowings and $689.0 million of repayments under the CCH Working Capital Facility; and

• $710.7 million of equity contributions from Cheniere.

Financing cash net inflows during the year ended December 31, 2018 were $3,083.0 million, primarily as a result of:

• $2.9 billion of borrowings and $281.5 million of repayments under the CCH Credit Facility;

• $188.0 million of borrowings and $20.0 million of repayments under the CCH Working Capital Facility;

• $45.7 million of debt issuance costs related to up-front fees paid upon the closing of the above transactions;

• $9.1 million of debt extinguishment costs related to the repayment of the CCH Credit Facility; and

• $324.5 million of equity contributions from Cheniere.

Financing cash net inflows during the year ended December 31, 2017 were $1,982.5 million, primarily as a result of:

• $1.5 billion of borrowings under the CCH Credit Facility;

• issuance of an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes, which was used to prepay $1.4 billion of outstanding borrowings under the CCH Credit Facility;

• $24.0 million of borrowings and $24.0 million of repayments made under the CCH Working Capital Facility;

• $23.5 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and

• $402.1 million of equity contributions from Cheniere.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2019 (in thousands):

	Payments Due By Period (1)
	Total		2020		2021-2022		2023-2024		Thereafter
Debt (2)	$	10,234,655	$	—	$	253,480	$	4,279,175	$	5,702,000
Interest payments (2)	3,270,424		477,703		941,669		835,865		1,015,187
Operating lease obligations (3)	6,830		652		3,302		2,626		250
Purchase obligations: (4)
Construction obligations (5)	399,809		263,754		136,055		—		—
Natural gas supply, transportation and storage service agreements (6)	6,162,163		1,255,512		1,758,763		1,075,700		2,072,188
Other purchase obligations (7)	485,451		23,579		47,159		47,159		367,554
Total	$	20,559,332	$	2,021,200	$	3,140,428	$	6,240,525	$	9,157,179

(1) Agreements in force as of December 31, 2019 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2019.

(2) Based on the total debt balance, scheduled maturities and fixed or estimated forward interest rates in effect at December 31, 2019.  Interest payment obligations exclude adjustments for interest rate swap agreements. A discussion of our debt obligations can be found in Note 10—Debt of our Notes to Consolidated Financial Statements.

(3) Operating lease obligations primarily relate to land sites for the Liquefaction Project.

(4) Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include only contracts for which conditions precedent have been met. 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 expected to be exercised.

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(5) Construction obligations consist of the estimated remaining cost pursuant to our EPC contracts as of December 31, 2019 for Trains with respect to which we have made a final investment decision to commence construction.  A discussion of these obligations can be found at Note 13—Commitments and Contingencies of our Notes to Consolidated Financial Statements.

(6) Pricing of natural gas supply agreements are based on estimated forward prices and basis spreads as of December 31, 2019.

(7) Relates primarily to services agreements for the operation of the Liquefaction Project, including services agreements with affiliates of $333.7 million as discussed in Note 12—Related Party Transactions.

In addition, as of December 31, 2019, we had $470.8 million aggregate amount of issued letters of credit under the CCH Working Capital Facility. We also had tax agreements with certain local taxing jurisdictions for an aggregate amount of $212.1 million to be paid through 2033, based on estimated tax obligations as of December 31, 2019.

Results of Operations

Our consolidated net loss was $374.3 million in the year ended December 31, 2019, compared to net income of $6.3 million in the year ended December 31, 2018. This $380.6 million decrease in net income in 2019 was primarily the result of increased interest expense, net of capitalized interest and derivative loss, net, which was partially offset by increased income from operations.

Our consolidated net income was $6.3 million in the year ended December 31, 2018, compared to a net loss of $48.7 million in the year ended December 31, 2017. This $55.0 million increase in net income in 2018 was primarily a result of increased derivative gain, net associated with interest rate derivative activity and decreased loss on modification or extinguishment of debt.

We enter into derivative instruments to manage our exposure to changing interest rates and commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions economically hedged receive accrual accounting treatment, 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, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.

Revenues

	Year Ended December 31,
(in thousands, except volumes)	2019		2018		Change		2017		Change
LNG revenues	$	679,070	$	—	$	679,070	$	—	$	—
LNG revenues—affiliate	726,100		—		726,100		—		—
Total revenues	$	1,405,170	$	—	$	1,405,170	$	—	$	—
LNG volumes recognized as revenues (in TBtu)	286		—		286		—		—

During the year ended December 31, 2019, we began recognizing LNG revenues from the Liquefaction Project following the substantial completion and the commencement of operating activities of Train 1 and Train 2 of the Liquefaction Project in February 2019 and August 2019, respectively. We expect our LNG revenues to increase in the future upon Train 3 of the Liquefaction Project becoming operational, in addition to full year operation of the Trains that were completed during 2019. Also included in LNG revenues are gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery and the sale of natural gas procured for the liquefaction process.

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, 2019 and 2018, we realized offsets to LNG terminal costs of $156.1 million and $48.7 million corresponding to 38 TBtu and 7 TBtu of LNG, respectively, that related to the sale of commissioning cargoes. We did not realize any offsets to LNG terminal costs during the year ended December 31, 2017.

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Operating costs and expenses

	Year Ended December 31,
(in thousands)	2019		2018			Change		2017		Change
Cost of sales	$	691,301	$	172		$	691,129	$	91	$	81
Cost of sales—affiliate	3,015		—			3,015		—		—
Cost of sales—related party	85,429		—			85,429		—		—
Operating and maintenance expense (recovery)	242,027		(96		)	242,123		3,024		(3,120		)
Operating and maintenance expense—affiliate	59,319		4,283			55,036		2,401		1,882
Development expense	596		177			419		516		(339		)
Development expense—affiliate	61		—			61		8		(8		)
General and administrative expense	6,106		5,263			843		5,551		(288		)
General and administrative expense—affiliate	11,352		2,201			9,151		1,173		1,028
Depreciation and amortization expense	230,780		9,859			220,921		892		8,967
Impairment expense and loss on disposal of assets	364		20			344		5,505		(5,485		)
Total operating costs and expenses	$	1,330,350	$	21,879		$	1,308,471	$	19,161	$	2,718

2019 vs 2018 and 2018 vs 2017

Our total operating costs and expenses increased during the year ended December 31, 2019 from the years ended December 31, 2018 and 2017, primarily as a result of the commencement of operations of Trains 1 and 2 of the Liquefaction Project in February 2019 and August 2019, respectively.

Cost of sales (including affiliate and related party) increased during the year ended December 31, 2019 from the years ended December 31, 2018 and 2017, primarily related to the increase in the volume of natural gas feedstock related to our LNG sales due to the commencement of operations at the Liquefaction Project. 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 also includes gains and losses from derivatives associated with economic hedges to secure natural gas feedstock for the Liquefaction Project.

Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Project. The increase in operating and maintenance expense (including affiliate) during the year ended December 31, 2019 from the years ended December 31, 2018 and 2017 was primarily related 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 the commencement of operations at the Liquefaction Project. 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, 2019 from the comparable period in 2018 as a result of commencing operations of Trains 1 and 2 of the Liquefaction Project in February 2019 and August 2019, respectively. Depreciation and amortization expense increased during the year ended December 31, 2018 from the comparable period in 2017 primarily due to the completion of construction of the Corpus Christi Pipeline in the second quarter of 2018, as the related assets began depreciating upon reaching substantial completion.

Other expense (income)

	Year Ended December 31,
(in thousands)	2019			2018			Change			2017			Change
Interest expense, net of capitalized interest	$	278,035		$	—		$	278,035		$	—		$	—
Loss on modification or extinguishment of debt	41,296			15,332			25,964			32,480			(17,148		)
Derivative loss (gain), net	133,427			(43,105		)	176,532			(3,249		)	(39,856		)
Other expense (income)	(3,642		)	(392		)	(3,250		)	260			(652		)
Total other expense (income)	$	449,116		$	(28,165	)	$	477,281		$	29,491		$	(57,656	)

2019 vs. 2018 and 2018 vs. 2017

Interest expense, net of capitalized interest, increased during the year ended December 31, 2019 compared to the years ended December 31, 2018 and 2017, primarily as a result of a decrease in the portion of total interest costs that could be capitalized

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due to the commencement of operations at the Liquefaction Project. For the year ended December 31, 2019, we incurred $538.7 million of total interest cost, of which we capitalized $260.6 million which was primarily related to interest costs incurred for the construction of the Liquefaction Project. During the years ended December 31, 2018 and 2017, we incurred $451.1 million and $360.9 million, which were entirely capitalized.

Loss on modification or extinguishment of debt increased during the year ended December 31, 2019 compared to the year ended December 31, 2018 and decreased between the year ended December 31, 2018 and the year ended December 31, 2017. The loss on modification or extinguishment of debt recognized in each of the years was related to the incurrence of third party fees and write off of unamortized discount and debt issuance costs recognized upon refinancing our credit facilities with senior notes, paydown of our credit facilities as part of Cheniere’s capital allocation framework or upon amendment and restatement of our credit facilities.

Derivative loss, net increased during the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily due to an unfavorable shift in the long-term forward LIBOR curve between the periods. Derivative gain, net increased during the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods.

Other income increased during the year ended December 31, 2019 as compared to the year ended December 31, 2018, primarily due to an increase in interest income earned on our cash and cash equivalents.

Off-Balance Sheet Arrangements

As of December 31, 2019, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results. 

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 based on the value for which the derivative instrument could be exchanged between willing parties.  If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation approaches. Such evaluations may involve significant judgment and the results are based on expected future events or conditions, particularly for those valuations using inputs unobservable in the market.

Our derivative instruments consist of interest rate swaps, financial commodity derivative contracts transacted in an over-the-counter market 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 contracts 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 evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our physical commodity contracts incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. A portion of our physical commodity contracts require us to make critical accounting estimates that involve significant judgment, 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

36

includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

Gains and losses on derivative instruments are recognized in earnings. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a change in the estimated fair value could occur in the near future as interest rates and commodity prices change.

Recent Accounting Standards 

For descriptions 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 thousands):

	December 31, 2019				December 31, 2018
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
Liquefaction Supply Derivatives	$	46,656	$	62,695	$	(68	)	$	1,165

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 (“Interest Rate Derivatives”) and to hedge against changes in interest rates that could impact our anticipated future issuance of debt (“Interest Rate Forward Start Derivatives” and, collectively with the Interest Rate Derivatives, CCH Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the 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 thousands):

	December 31, 2019					December 31, 2018
	Fair Value			Change in Fair Value		Fair Value		Change in Fair Value
Interest Rate Derivatives	$	(80,645	)	$	19,122	$	18,069	$	37,145
Interest Rate Forward Start Derivatives	(7,582		)	14,886		—		—

See Note 7—Derivative Instruments for additional details about our derivative instruments.

37

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	39
Report of Independent Registered Public Accounting Firm	40
Consolidated Balance Sheets	41
Consolidated Statements of Operations	42
Consolidated Statements of Member’s Equity	43
Consolidated Statements of Cash Flows	44
Notes to Consolidated Financial Statements	45
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	75

38

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, 2019, 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/ Michael J. Wortley
	Michael J. Wortley
	President and Chief Financial Officer (Principal Executive and Financial Officer)

39

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member and Managers of

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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

Change in Accounting Principle

As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for income taxes in 2019, 2018, and 2017 due to the adoption of ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.

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.

/s/    KPMG LLP

KPMG LLP

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

Houston, Texas

February 24, 2020

40

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2019		2018
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	79,741		289,141
Accounts and other receivables	57,712		24,989
Accounts receivable—affiliate	57,211		21,060
Advances to affiliate	115,476		94,397
Inventory	69,179		26,198
Derivative assets	73,809		15,627
Derivative assets—related party	2,623		2,132
Other current assets	14,852		15,217
Other current assets—affiliate	5		633
Total current assets	470,608		489,394
Property, plant and equipment, net	12,507,419		11,138,825
Debt issuance and deferred financing costs, net	14,705		38,012
Non-current derivative assets	61,217		19,032
Non-current derivative assets—related party	1,933		3,381
Other non-current assets, net	55,630		31,709
Total assets	$	13,111,512	$	11,720,353
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	7,290	$	16,202
Accrued liabilities	369,980		162,205
Accrued liabilities—related party	2,531		—
Current debt	—		168,000
Due to affiliates	26,900		25,086
Derivative liabilities	46,486		13,576
Other current liabilities	364		—
Other current liabilities—affiliate	519		—
Total current liabilities	454,070		385,069
Long-term debt, net	10,093,480		9,245,552
Non-current derivative liabilities	134,667		8,595
Other non-current liabilities	10,433		—
Other non-current liabilities—affiliate	1,284		—
Commitments and contingencies (see Note 13)
Member’s equity	2,417,578		2,081,137
Total liabilities and member’s equity	$	13,111,512	$	11,720,353

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

41

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2019			2018			2017
Revenues
LNG revenues	$	679,070		$	—		$	—
LNG revenues—affiliate	726,100			—			—
Total revenues	1,405,170			—			—
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)	691,301			172			91
Cost of sales—affiliate	3,015			—			—
Cost of sales—related party	85,429			—			—
Operating and maintenance expense (recovery)	242,027			(96		)	3,024
Operating and maintenance expense—affiliate	59,319			4,283			2,401
Development expense	596			177			516
Development expense—affiliate	61			—			8
General and administrative expense	6,106			5,263			5,551
General and administrative expense—affiliate	11,352			2,201			1,173
Depreciation and amortization expense	230,780			9,859			892
Impairment expense and loss on disposal of assets	364			20			5,505
Total operating costs and expenses	1,330,350			21,879			19,161
Income (loss) from operations	74,820			(21,879		)	(19,161		)
Other income (expense)
Interest expense, net of capitalized interest	(278,035		)	—			—
Loss on modification or extinguishment of debt	(41,296		)	(15,332		)	(32,480		)
Derivative gain (loss), net	(133,427		)	43,105			3,249
Other income (expense)	3,642			392			(260		)
Total other income (expense)	(449,116		)	28,165			(29,491		)
Net income (loss)	$	(374,296	)	$	6,286		$	(48,652	)

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

42

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

(in thousands)

	Cheniere CCH HoldCo I, LLC			Total Member’s Equity
Balance at December 31, 2016	$	1,313,809		$	1,313,809
Capital contributions	402,119			402,119
Net loss	(48,652		)	(48,652		)
Balance at December 31, 2017	1,667,276			1,667,276
Capital contributions	407,575			407,575
Net income	6,286			6,286
Balance at December 31, 2018	2,081,137			2,081,137
Capital contributions	710,737			710,737
Net loss	(374,296		)	(374,296		)
Balance at December 31, 2019	$	2,417,578		$	2,417,578

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

43

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities
Net income (loss)	$	(374,296	)	$	6,286		$	(48,652	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization expense	230,780			9,859			892
Amortization of discount and debt issuance costs	15,953			—			—
Loss on modification or extinguishment of debt	41,296			15,332			32,480
Total losses (gains) on derivatives, net	88,052			(43,128		)	(3,158		)
Total losses on derivatives, net—related party	957			—			—
Net cash used for settlement of derivative instruments	(29,437		)	(7,222		)	(50,981		)
Impairment expense and loss on disposal of assets	364			20			5,505
Other	1,603			—			—
Changes in operating assets and liabilities:
Accounts receivable	(57,654		)	—			—
Accounts receivable—affiliate	(57,203		)	—			—
Advances to affiliate	(53,231		)	(10,911		)	—
Inventory	(36,885		)	(24,852		)	—
Accounts payable and accrued liabilities	174,471			10,354			152
Accrued liabilities—related party	2,531			—			—
Due to affiliates	15,368			530			1,567
Other, net	3,863			(16,313		)	(1,454		)
Other, net—affiliate	95			(117		)	(667		)
Net cash used in operating activities	(33,373		)	(60,162		)	(64,316		)
Cash flows from investing activities
Property, plant and equipment, net	(1,517,162		)	(2,962,936		)	(1,987,254		)
Other	(2,058		)	2,669			25,045
Net cash used in investing activities	(1,519,220		)	(2,960,267		)	(1,962,209		)
Cash flows from financing activities
Proceeds from issuances of debt	4,203,550			3,114,800			3,040,000
Repayments of debt	(3,543,757		)	(301,455		)	(1,436,050		)
Debt issuance and deferred financing costs	(16,210		)	(45,743		)	(23,496		)
Debt extinguishment cost	(11,127		)	(9,108		)	(29		)
Capital contributions	710,737			324,517			402,119
Net cash provided by financing activities	1,343,193			3,083,011			1,982,544
Net increase (decrease) in cash, cash equivalents and restricted cash	(209,400		)	62,582			(43,981		)
Cash, cash equivalents and restricted cash—beginning of period	289,141			226,559			270,540
Cash, cash equivalents and restricted cash—end of period	$	79,741		$	289,141		$	226,559

Balances per Consolidated Balance Sheets:

	December 31,
	2019		2018
Cash and cash equivalents	$	—	$	—
Restricted cash	79,741		289,141
Total cash, cash equivalents and restricted cash	$	79,741	$	289,141

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

44

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

CCH is a Houston-based Delaware limited liability company formed in September 2014 by Cheniere to hold its limited partner interest in CCP and its equity interests in CCL and CCP GP. We are operating and constructing a natural gas liquefaction and export facility (the “Liquefaction Facilities”) and operating a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries CCL and CCP, respectively. We are currently operating two Trains and are constructing one additional Train for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain 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.

Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

Recent Accounting Standards

We adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), and subsequent amendments thereto on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. The adoption of the standard did not materially impact our Consolidated Financial Statements. Upon adoption of the standard, we recorded right-of-use assets of $8.1 million in other non-current assets, net, and lease liabilities of $0.5 million in other current liabilities—affiliate, $5.2 million other non-current liabilities and $1.2 million in other non-current liabilities—affiliate.

In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The new guidance retrospectively eliminates the requirement to allocate the consolidated amount of current and deferred tax expense to entities that are not subject to income tax. We early adopted this guidance effective December 31, 2019 and recorded a cumulative-effect adjustment to retained earnings of $2.1 million on our subsidiaries’ financial statements, that has been eliminated upon consolidated on our Consolidated Financial Statements. The provision for income taxes, taxes payable and deferred income tax balances have been retrospectively removed from our subsidiaries’ financial statements. The deferred tax assets were offset with a full valuation allowance and therefore no cumulative effect adjustment to retained earnings was required on our Consolidated Financial Statements.

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, revenue recognition, property, plant and equipment, derivative instruments 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

45

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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, accounts receivables 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. Non-financial assets and liabilities initially measured at fair value include AROs.

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. Revenues from the sale of LNG are recognized as LNG revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.

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

Restricted cash 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.

Accounts Receivable

Accounts receivable is reported net of any allowances for doubtful accounts. We periodically review the collectability on our accounts receivable and recognize an allowance if there is probability of non-collection, based on historical write-off and customer-specific factors. We did not have an allowance on our accounts receivable as of December 31, 2019 and 2018.

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 and subsequently charged to expense when issued.

Accounting for LNG Activities

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. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.

46

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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. 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. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses 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 is identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. During the year ended December 31, 2017, we recognized $5.5 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2019 and 2018.

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 reduce our asset balances to reflect a market basis less than cost and 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 the natural gas pipelines are placed in service.

47

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. When we have the contractual right and intend 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, 2019, 2018 and 2017. 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 restricted cash, derivative instruments and accounts receivable. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these 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 nine 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.

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, they are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in gain (loss) on modification or extinguishment of debt on our Consolidated Statements of Operations.

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.

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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.

NOTE 3—RESTRICTED CASH

Restricted cash 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, 2019 and 2018, restricted cash consisted of the following (in thousands):

	December 31,
	2019		2018
Current restricted cash
Liquefaction Project	$	79,741	$	289,141

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

As of December 31, 2019 and 2018, accounts and other receivables consisted of the following (in thousands):

	December 31,
	2019		2018
Trade receivable	$	44,403	$	51
Other accounts receivable	13,309		24,938
Total accounts and other receivables	$	57,712	$	24,989

NOTE 5—INVENTORY

As of December 31, 2019 and 2018, inventory consisted of the following (in thousands):

	December 31,
	2019		2018
Natural gas	$	6,870	$	1,326
LNG	6,103		—
Materials and other	56,206		24,872
Total inventory	$	69,179	$	26,198

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NOTE 6—PROPERTY, PLANT AND EQUIPMENT

As of December 31, 2019 and 2018, property, plant and equipment, net consisted of the following (in thousands):

	December 31,
	2019			2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	10,027,111		$	618,547
LNG site and related costs	275,959			44,725
LNG terminal construction-in-process	2,425,226			10,470,577
Accumulated depreciation	(232,451		)	(7,416		)
Total LNG terminal costs, net	12,495,845			11,126,433
Fixed assets
Fixed assets	19,083			15,534
Accumulated depreciation	(7,509		)	(3,142		)
Total fixed assets, net	11,574			12,392
Property, plant and equipment, net	$	12,507,419		$	11,138,825

 

Depreciation expense was $230.0 million, $9.5 million and $0.8 million during the years ended December 31, 2019, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $156.1 million and $48.7 million during the years ended December 31, 2019 and 2018, respectively, that were 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. We did not realize any offsets to LNG terminal costs during the year ended December 31, 2017.

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 10 and 50 years, as follows:

Components	Useful life (yrs)
Water pipelines	30
Natural gas pipeline facilities	40
Liquefaction processing equipment	10-50
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 (“Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on our amended and restated credit facility (the “CCH Credit Facility”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt (“Interest Rate Forward Start Derivatives” and, collectively with the Interest Rate Derivatives, “CCH 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 (collectively, the “Liquefaction Supply Derivatives”).

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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.

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, 2019 and 2018, which are classified as derivative assets, derivative assets—related party, non-current derivative assets, non-current derivative assets—related party, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in thousands):

	Fair Value Measurements as of
	December 31, 2019										December 31, 2018
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total
Interest Rate Derivatives asset (liability)	$	—	$	(80,645	)	$	—	$	(80,645	)	$	—	$	18,069	$	—		$	18,069
Interest Rate Forward Start Derivatives liability	—		(7,582		)	—		(7,582		)	—		—		—			—
Liquefaction Supply Derivatives asset (liability)	2,383		9,198			35,075		46,656			1,299		2,990		(4,357		)	(68		)

We value our CCH 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 conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of December 31, 2019 and 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

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 prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2019:

	Net Fair Value Asset (in thousands)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$35,075	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.718) - $0.050
		Option pricing model	International LNG pricing spread, relative to Henry Hub (1)	86% - 191%

(1)    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.

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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, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018			2017
Balance, beginning of period	$	(4,357	)	$	(91	)	$	—
Realized and mark-to-market gains (losses):
Included in cost of sales	(82,645		)	(9,944		)	—
Purchases and settlements:
Purchases	120,755			5,678			(91		)
Settlements	1,432			—			—
Transfers out of Level 3 (1)	(110		)	—			—
Balance, end of period	$	35,075		$	(4,357	)	$	(91	)
Change in unrealized losses relating to instruments still held at end of period	$	(82,645	)	$	(9,944	)	$	—

(1) Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. 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.

CCH Interest Rate Derivatives

CCH has 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.

In June and July of 2019, we entered into the Interest Rate Forward Start Derivatives to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH, which is anticipated by the end of 2020. In November 2019, we settled a portion of the Interest Rate Forward Start Derivatives in conjunction with the prepayment of $1.5 billion of commitments under the CCH Credit Facility. In June 2018, we settled a portion of the Interest Rate Derivatives in conjunction with the amendment of the CCH Credit Facility.

As of December 31, 2019, we had the following CCH Interest Rate Derivatives outstanding:

	Notional Amounts
	December 31, 2019	December 31, 2018	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives	$4.5 billion	$4.0 billion	May 20, 2015	May 31, 2022	2.30%	One-month LIBOR
Interest Rate Forward Start Derivatives	$750 million	—	September 30, 2020	December 31, 2030	2.06%	Three-month LIBOR

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The following table shows the fair value and location of our CCH Interest Rate Derivatives on our Consolidated Balance Sheets (in thousands):

	December 31, 2019									December 31, 2018
	Interest Rate Derivatives			Interest Rate Forward Start Derivatives			Total			Interest Rate Derivatives			Interest Rate Forward Start Derivatives		Total
Consolidated Balance Sheet Location
Derivative assets	$	—		$	—		$	—		$	10,556		$	—	$	10,556
Non-current derivative assets	—			—			—			7,918			—		7,918
Total derivative assets	—			—			—			18,474			—		18,474
Derivative liabilities	(31,984		)	(7,582		)	(39,566		)	(7		)	—		(7		)
Non-current derivative liabilities	(48,661		)	—			(48,661		)	(398		)	—		(398		)
Total derivative liabilities	(80,645		)	(7,582		)	(88,227		)	(405		)	—		(405		)
Derivative asset (liability), net	$	(80,645	)	$	(7,582	)	$	(88,227	)	$	18,069		$	—	$	18,069

The following table shows the changes in the fair value and settlements of our CCH Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018		2017
Interest Rate Derivatives gain (loss)	$	(100,508	)	$	43,105	$	3,249
Interest Rate Forward Start Derivatives loss	(32,919		)	—		—

Liquefaction Supply Derivatives

CCL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent.

The forward notional for our Liquefaction Supply Derivatives was approximately 3,153 TBtu and 2,854 TBtu as of December 31, 2019 and 2018, respectively, of which 120 TBtu and 55 TBtu, respectively, were for a natural gas supply contract CCL has with a related party.

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

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	December 31, 2019			December 31, 2018
Derivative assets	$	73,809		$	5,071
Derivative assets—related party	2,623			2,132
Non-current derivative assets	61,217			11,114
Non-current derivative assets—related party	1,933			3,381
Total derivative assets	139,582			21,698
Derivative liabilities	(6,920		)	(13,569		)
Non-current derivative liabilities	(86,006		)	(8,197		)
Total derivative liabilities	(92,926		)	(21,766		)
Derivative asset (liability), net	$	46,656		$	(68	)

(1) Does not include collateral posted with counterparties by us of $4.5 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of both December 31, 2019 and 2018.

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The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2019, 2018 and 2017 (in thousands):

		Year Ended December 31,
	Consolidated Statements of Operations Location (1)	2019			2018		2017
Liquefaction Supply Derivatives gain	LNG revenues	$	227		$	—	$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	45,148			23		(91		)
Liquefaction Supply Derivatives loss	Cost of sales—related party	(957		)	—		—

(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.

Consolidated Balance Sheet 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 thousands):

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of December 31, 2019
Interest Rate Derivatives	$	(80,645	)	$	—		$	(80,645	)
Interest Rate Forward Start Derivatives	(7,582		)	—			(7,582		)
Liquefaction Supply Derivatives	145,135			(5,553		)	139,582
Liquefaction Supply Derivatives	(98,625		)	5,699			(92,926		)
As of December 31, 2018
Interest Rate Derivatives	$	19,520		$	(1,046	)	$	18,474
Interest Rate Derivatives	(413		)	8			(405		)
Liquefaction Supply Derivatives	31,770			(10,072		)	21,698
Liquefaction Supply Derivatives	(29,996		)	8,230			(21,766		)

NOTE 8—OTHER NON-CURRENT ASSETS

As of December 31, 2019 and 2018, other non-current assets, net consisted of the following (in thousands):

	December 31,
	2019		2018
Advances and other asset conveyances to third parties to support LNG terminal	$	18,703	$	18,209
Operating lease assets	7,215		—
Tax-related payments and receivables	3,200		3,783
Information technology service prepayments	3,010		2,435
Advances made under EPC and non-EPC contracts	14,067		—
Other	9,435		7,282
Total other non-current assets, net	$	55,630	$	31,709

NOTE 9—ACCRUED LIABILITIES

As of December 31, 2019 and 2018, accrued liabilities consisted of the following (in thousands): 

	December 31,
	2019		2018
Interest costs and related debt fees	$	7,950	$	994
Accrued natural gas purchases	132,148		91,910
Liquefaction Project costs	192,215		46,964
Other	37,667		22,337
Total accrued liabilities	$	369,980	$	162,205

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NOTE 10—DEBT

As of December 31, 2019 and 2018, our debt consisted of the following (in thousands): 

	December 31,
	2019			2018
Long-term debt
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	$	1,250,000		$	1,250,000
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500,000			1,500,000
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500,000			1,500,000
4.80% Senior Secured Notes due 2039 (“4.80% CCH Senior Notes”)	727,000			—
3.925% Senior Secured Notes due 2039 (“3.925% CCH Senior Notes”)	475,000			—
3.700% Senior Secured Notes due 2029 (“2029 CCH Senior Notes”)	1,500,000			—
CCH Credit Facility	3,282,655			5,155,737
Unamortized debt issuance costs	(141,175		)	(160,185		)
Total long-term debt, net	10,093,480			9,245,552
Current debt
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	—			168,000
Total debt, net	$	10,093,480		$	9,413,552

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, 2019 (in thousands): 

Years Ending December 31,	Principal Payments
2020	$	—
2021	134,973
2022	118,507
2023	132,859
2024	4,146,316
Thereafter	5,702,000
Total	$	10,234,655

Senior Notes

CCH Senior Notes

In September 2019, we issued an aggregate principal amount of $727 million of the 4.80% CCH Senior Notes in a private placement conducted pursuant to Section 4(a)(2) of the Securities Act. The 4.80% CCH Senior Notes were issued under an indenture dated as of September 27, 2019 pursuant to a note purchase agreement with the purchasers party thereto and Allianz Global Investors GmbH, as noteholder consultant, originally entered into in June 2019. In October 2019, we issued an aggregate principal amount of $475 million of the 3.925% CCH Senior Notes in a private placement conducted pursuant to Section 4(a)(2) of the Securities Act. The 3.925% CCH Senior Notes were issued under an indenture dated October 17, 2019 pursuant to a note purchase agreement with the purchasers party thereto and certain accounts managed by BlackRock Real Assets and certain accounts managed by MetLife Investment Management. The 4.80% CCH Senior Notes and the 3.925% CCH Senior Notes accrue interest at a fixed rate of 4.80% and 3.925% per annum, respectively, and are fully amortizing according to a fixed sculpted amortization schedule with semi-annual payments of interest starting December 2019 and semi-annual payments of principal starting June 2027. The 4.80% CCH Senior Notes and the 3.925% CCH Senior Notes have a weighted average life of 15 years.

In November 2019, we issued an aggregate principal amount of $1.5 billion of the 2029 CCH Senior Notes. The 2029 CCH Senior Notes were issued pursuant to the same indenture governing the 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes (together with the 2029 CCH Senior Notes, the "144A CCH Senior Notes"). Borrowings under the 2029 CCH Senior Notes accrue interest at a fixed rate of 3.700% per annum.

The proceeds of the 4.80% CCH Senior Notes, 3.925% CCH Senior Notes and 2029 CCH Senior Notes were used to prepay a portion of the balance outstanding under the CCH Credit Facility, resulting in the recognition of debt modification and

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extinguishment costs of $38.7 million for the year ended December 31, 2019 relating to the write off of unamortized debt discounts and issuance costs.

The 144A CCH Senior Notes, 4.80% CCH Senior Notes and 3.925% CCH Senior Notes (collectively, the “CCH Senior Notes”) are jointly and severally guaranteed by our subsidiaries, CCL, CCP and CCP GP (the “Guarantors”). The indentures governing each of the CCH Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to us or any of our restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of us and our restricted subsidiaries taken as a whole; or permit any Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. Interest on the CCH Senior Notes is payable semi-annually in arrears.

At any time prior to six months before the respective dates of maturity for each of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the appropriate indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time within six months of the respective dates of maturity for each of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2019 (in thousands):

	CCH Credit Facility		CCH Working Capital Facility
Original facility size	$	8,403,714	$	350,000
Incremental commitments	1,565,961		850,000
Less:
Outstanding balance	3,282,655		—
Commitments terminated	6,687,020		—
Letters of credit issued	—		470,784
Available commitment	$	—	$	729,216
Interest rate on available balance	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75%
Weighted average interest rate of outstanding balance	3.55%		n/a
Maturity date	June 30, 2024		June 29, 2023

CCH Credit Facility

In May 2018, we amended and restated the CCH Credit Facility to increase total commitments under the CCH Credit Facility from $4.6 billion to $6.1 billion. Borrowings are used to fund a portion of the costs of developing, constructing and placing into service the three Trains and the related facilities of the Liquefaction Project and for related business purposes.

The CCH Credit Facility matures on June 30, 2024, with principal payments due quarterly commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following the completion of the Liquefaction Project as defined in the common terms agreement and (2) a set date determined by reference to the date under which a certain LNG buyer linked to the last Train of the Liquefaction Project to become operational is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the completion of Trains 1 through 3 and designed to achieve a minimum projected fixed debt service coverage ratio of 1.50:1.

Loans under the CCH Credit Facility accrue interest at a variable rate per annum equal to, at our election, LIBOR or the base rate (determined by reference to the applicable agent’s prime rate), plus the applicable margin. The applicable margin for LIBOR loans is 1.75% and for base rate loans is 0.75%. Interest on LIBOR loans is due and payable at the end of each applicable

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interest period and interest on base rate loans is due and payable at the end of each quarter. The CCH Credit Facility also requires us to pay a commitment fee at a rate per annum equal to 40% of the margin for LIBOR loans, multiplied by the outstanding undrawn debt commitments.

Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in us, on a pari passu basis with the CCH Senior Notes and the CCH Working Capital Facility.

Under the CCH Credit Facility, we are required to hedge not less than 65% of the variable interest rate exposure of our senior secured debt. We are restricted from making certain distributions under agreements governing our indebtedness generally until, among other requirements, the completion of the construction of Trains 1 through 3 of the Liquefaction Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.

The amendment and restatement of the CCH Credit Facility resulted in the recognition of $15.3 million of debt modification and extinguishment costs during the year ended December 31, 2018 relating to the incurrence of third party fees and write off of unamortized debt issuance costs. We were required to pay certain upfront fees to the agents and lenders under the CCH Credit Facility together with additional transaction fees and expenses in the aggregate amount of $53.3 million during the year ended December 31, 2018.

As part of the capital allocation framework announced by Cheniere in June 2019, we prepaid $152.8 million of outstanding borrowings under the CCH Credit Facility during the year ended December 31, 2019. The prepayment resulted in the recognition of debt extinguishment costs of $2.6 million for the year ended December 31, 2019.

CCH Working Capital Facility

In June 2018, we amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility from $350 million to $1.2 billion. The CCH Working Capital Facility is intended to be used for loans (“CCH Working Capital Loans”) and the issuance of letters of credit for certain working capital requirements related to developing and operating the Liquefaction Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the Guarantors. We may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility.

Loans under the CCH Working Capital Facility, including CCH Working Capital Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans” and collectively, the “Revolving Loans”) accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of (1) the prime rate, (2) the federal funds rate plus 0.50% and (3) one month LIBOR plus 0.50%) plus the applicable margin. The applicable margin for LIBOR Revolving Loans ranges from 1.25% to 1.75% per annum, and the applicable margin for base rate Revolving Loans ranges from 0.25% to 0.75% per annum. Interest on Revolving Loans is due and payable on the date the loan becomes due. Interest on LIBOR Revolving Loans is due and payable at the end of each LIBOR period, and interest on base rate Revolving Loans is due and payable at the end of each quarter.

We pay (1) a commitment fee equal to an annual rate of 40% of the applicable margin for LIBOR Revolving Loans on the average daily amount of the excess of the total commitment amount over the principal amount outstanding, (2) a letter of credit fee equal to an annual rate equal to the applicable margin for LIBOR Revolving Loans on the undrawn portion of all letters of credit issued under the CCH Working Capital Facility and (3) a letter of credit fronting fee equal to an annual rate of 0.20% of the undrawn portion of all fronted letters of credit. Each of these fees is payable quarterly in arrears.

If draws are made upon a letter of credit issued under the CCH Working Capital Facility and we do not elect for such draw (a “CCH LC Draw”) to be deemed a CCH LC Loan, we are required to pay the full amount of the CCH LC Draw on or prior to the business day following the notice of the CCH LC Draw. A CCH LC Draw accrues interest at an annual rate of 2.00% plus the base rate.

We were required to pay certain upfront fees to the agents and lenders under the CCH Working Capital Facility together with additional transaction fees and expenses in the aggregate amount of $13.8 million during the year ended December 31, 2018.

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The CCH Working Capital Facility matures on June 29, 2023 and we may prepay the Revolving Loans at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. We are required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the assets of the Guarantors as well as all of the membership interests in us and the membership interest in each of the Guarantors on a pari passu basis with the CCH Senior Notes and the CCH Credit Facility.

Restrictive Debt Covenants

As of December 31, 2019, we were in compliance with all covenants related to our debt agreements.

Interest Expense

Total interest expense consisted of the following (in thousands):

	Year Ended December 31,
	2019			2018			2017
Total interest cost	$	538,677		$	451,135		$	360,932
Capitalized interest, including amounts capitalized as an Allowance for Funds Used During Construction	(260,642		)	(451,135		)	(360,932		)
Total interest expense, net	$	278,035		$	—		$	—

Fair Value Disclosures

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

	December 31, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	5,750,000	$	6,329,200	$	4,250,000	$	4,228,750
4.80% CCH Senior Notes (2)	727,000		830,203		—		—
3.925% CCH Senior Notes (2)	475,000		495,291		—		—
Credit facilities (3)	3,282,655		3,282,655		5,323,737		5,323,737

(1) Includes 144A CCH Senior Notes. 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) Includes CCH Credit Facility and CCH Working Capital Facility. 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.

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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, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018		2017
LNG revenues	$	678,843	$	—	$	—
LNG revenues—affiliate	726,100		—		—
Total revenues from customers	1,404,943		—		—
Net derivative gains (1)	227		—		—
Total revenues	$	1,405,170	$	—	$	—

(1)    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 equal to approximately 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.

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.

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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, 2019 and 2018:

	December 31, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	33.6	11	$	33.9	12
LNG revenues—affiliate	1.0		13	1.0		14
Total revenues	$	34.6		$	34.9

(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 44% during the year ended December 31, 2019 of our LNG revenues were related to variable consideration received from customers. All of our LNG revenues—affiliate were related to variable consideration received from customers during the year ended December 31, 2019.

We have entered 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.

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NOTE 12—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018			2017
LNG revenues—affiliate
Cheniere Marketing Agreements	$	719,069	$	—		$	—
Contracts for Sale and Purchase of Natural Gas and LNG	7,031		—			—
Total LNG revenues—affiliate	726,100		—			—
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	3,015		—			—
Cost of sales—related party
Natural Gas Supply Agreement	85,429		—			—
Operating and maintenance expense—affiliate
Services Agreements	58,576		3,412			2,075
Land Agreements	743		874			326
Other Agreements	—		(3		)	—
Total operating and maintenance expense—affiliate	59,319		4,283			2,401
Development expense—affiliate
Services Agreements	61		—			8
General and administrative expense—affiliate
Services Agreements	11,352		2,201			1,173

We had $26.9 million and $25.1 million due to affiliates as of December 31, 2019 and 2018, respectively, under agreements with affiliates, as described below.

Cheniere Marketing Agreements

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 an approximate term of 23 years with Cheniere Marketing which allows them to purchase volumes of approximately 15 TBtu per annum of LNG and (2) an SPA for 0.85 mtpa of LNG with a term of up to seven years associated with the integrated production marketing gas supply agreement between CCL and EOG Resources, Inc. As of December 31, 2019 and 2018, CCL had $57.2 million and $21.1 million of accounts receivable—affiliate, respectively, under these agreements.

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

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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. 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 has entered into a natural gas supply contract to obtain feed gas for the operation of the Liquefaction Project through March 2022 with a related party in the ordinary course of business. CCL recorded $85.4 million in cost of sales—related party under this contract during the year ended December 31, 2019. Of this amount, $2.5 million and zero was included in accrued liabilities—related party as of December 31, 2019 and 2018, respectively. CCL did not have any deliveries during the year ended December 31, 2018 under this contract. CCL also has recorded derivative assets—related party of $2.6 million and $2.1 million and non-current derivative assets—related party of $1.9 million and $3.4 million as of December 31, 2019 and 2018, respectively, related to this contract.

Agreements with Midship Pipeline

CCL has entered into a transportation precedent agreement and a negotiated rate agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) to secure firm pipeline transportation capacity for a period of 10 years following commencement of the approximately 200-mile natural gas pipeline project which Midship Pipeline is constructing. In May 2018, CCL issued a letter of credit to Midship Pipeline for drawings up to an aggregate maximum amount of $16.2 million. Midship Pipeline had not made any drawings on this letter of credit as of December 31, 2019.

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Natural Gas Transportation Agreement

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 that allows them to sell and purchase natural gas with each other. CCL did not have any transactions under this agreement during the year ended December 31, 2019.

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 five 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.

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 for which Cheniere could have demanded payment from CCL under this agreement; therefore, Cheniere has not demanded any such payments from CCL. The agreement is effective for tax returns due on or after May 2015.

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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 for which Cheniere could have demanded payment from CCP under this agreement; therefore, Cheniere has not demanded any such payments from CCP. 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, 2019, we have received $557.9 million in contributions under the Equity Contribution Agreement and Cheniere has posted $585.0 million of 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.

Early Works Equity Contribution Agreement

In conjunction with the amendment and restatement of the Equity Contribution Agreement, we terminated the early works equity contribution agreement with Cheniere entered into in December 2017. Prior to termination in May 2018, we had received $250.0 million in contributions from Cheniere under the early works equity contribution agreement.

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 purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2019, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contracts

CCL has a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 3 of the Liquefaction Project. The EPC contract price for Train 3 of the Liquefaction Project is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2019. As of December 31, 2019, we have incurred $2.0 billion under this contract. CCL has the right to terminate each of the EPC contracts for its convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.

Obligations under SPAs

CCL has third-party SPAs which obligate CCL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project. CCL has also entered into SPAs with Cheniere Marketing, as further described in Note 12—Related Party Transactions.

Obligations under 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 8 years, some of which commence upon the satisfaction of certain events or states of affairs. As of December 31, 2019, CCL had secured up to approximately 2,999 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the certain events or states of affairs are satisfied.

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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, 2019, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in thousands): 

Years Ending December 31,	Payments Due (1)
2020	$	1,255,512
2021	1,047,335
2022	711,428
2023	591,844
2024	483,856
Thereafter	2,072,188
Total	$	6,162,163

(1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2019. 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. 

State Tax Sharing Agreement

CCL and CCP have a state tax sharing agreement with Cheniere.  See Note 12—Related Party Transactions for information regarding this agreement.

Other Commitments

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.

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. In the opinion of management, as of December 31, 2019, 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.

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NOTE 14—CUSTOMER CONCENTRATION

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

	Percentage of Total Revenues from External Customers			Percentage of Accounts Receivable from External Customers
	Year Ended December 31,			December 31,
	2019	2018	2017	2019	2018
Customer A	57%	—%	—%	38%	—%
Customer B	23%	—%	—%	39%	—%

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in thousands). 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,
	2019		2018		2017
Spain	$	451,199	$	—	$	—
Indonesia	154,584		—		—
United States	73,287		—		—
Total	$	679,070	$	—	$	—

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2019		2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	258,491	$	104,811	$	—
Non-cash capital contribution for conveyance of property, plant and equipment from affiliate	—		83,058		—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $186.7 million, $178.3 million and $274.3 million as of December 31, 2019, 2018 and 2017, respectively.

NOTE 16—SUPPLEMENTAL GUARANTOR INFORMATION

Our CCH Senior Notes are jointly and severally guaranteed by our subsidiaries, CCL, CCP and CCP GP (each a “Guarantor” and collectively, the “Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) the designation of the Guarantor as an “unrestricted subsidiary” in accordance with the indentures governing each of 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. See Note 10—Debt for additional information regarding the CCH Senior Notes.

The following is condensed consolidating financial information for CCH (“Parent Issuer”) and the Guarantors. We did not have any non-guarantor subsidiaries as of December 31, 2019.

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Condensed Consolidating Balance Sheet
December 31, 2019
(in thousands)
	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	68,787		10,954		—			79,741
Accounts and other receivables	—		57,712		—			57,712
Accounts receivable—affiliate	—		57,211		—			57,211
Advances to affiliate	—		115,476		—			115,476
Inventory	—		69,179		—			69,179
Derivative assets	—		73,809		—			73,809
Derivative assets—related party	—		2,623		—			2,623
Other current assets	249		14,603		—			14,852
Other current assets—affiliate	—		5		—			5
Total current assets	69,036		401,572		—			470,608
Property, plant and equipment, net	1,330,748		11,176,671		—			12,507,419
Debt issuance and deferred financing costs, net	14,705		—		—			14,705
Non-current derivative assets	—		61,217		—			61,217
Non-current derivative assets—related party	—		1,933		—			1,933
Investments in subsidiaries	11,224,400		—		(11,224,400		)	—
Other non-current assets, net	—		55,630		—			55,630
Total assets	$	12,638,889	$	11,697,023	$	(11,224,400	)	$	13,111,512
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	32	$	7,258	$	—		$	7,290
Accrued liabilities	9,488		360,492		—			369,980
Accrued liabilities—related party	—		2,531		—			2,531
Due to affiliates	337		26,563		—			26,900
Derivative liabilities	39,566		6,920		—			46,486
Other current liabilities	—		364		—			364
Other current liabilities—affiliate	—		519		—			519
Total current liabilities	49,423		404,647		—			454,070
Long-term debt, net	10,093,480		—		—			10,093,480
Non-current derivative liabilities	48,661		86,006		—			134,667
Other non-current liabilities	—		10,433		—			10,433
Other non-current liabilities—affiliate	—		1,284		—			1,284
Member’s equity	2,447,325		11,194,653		(11,224,400		)	2,417,578
Total liabilities and member’s equity	$	12,638,889	$	11,697,023	$	(11,224,400	)	$	13,111,512

67

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Balance Sheet
December 31, 2018
(in thousands)
	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	282,248		6,893		—			289,141
Accounts and other receivables	—		24,989		—			24,989
Accounts receivable—affiliate	—		21,060		—			21,060
Advances to affiliate	—		94,397		—			94,397
Inventory	—		26,198		—			26,198
Derivative assets	10,556		5,071		—			15,627
Derivative assets—related party	—		2,132		—			2,132
Other current assets	178		15,039		—			15,217
Other current assets—affiliate	—		634		(1		)	633
Total current assets	292,982		196,413		(1		)	489,394
Property, plant and equipment, net	1,094,671		10,044,154		—			11,138,825
Debt issuance and deferred financing costs, net	38,012		—		—			38,012
Non-current derivative assets	7,917		11,115		—			19,032
Non-current derivative assets—related party	—		3,381		—			3,381
Investments in subsidiaries	10,194,296		—		(10,194,296		)	—
Other non-current assets, net	1		31,708		—			31,709
Total assets	$	11,627,879	$	10,286,771	$	(10,194,297	)	$	11,720,353
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	71	$	16,131	$	—		$	16,202
Accrued liabilities	1,242		160,963		—			162,205
Current debt	168,000		—		—			168,000
Due to affiliates	—		25,086		—			25,086
Derivative liabilities	6		13,570		—			13,576
Total current liabilities	169,319		215,750		—			385,069
Long-term debt, net	9,245,552		—		—			9,245,552
Non-current derivative liabilities	398		8,197		—			8,595
Member’s equity	2,212,610		10,062,824		(10,194,297		)	2,081,137
Total liabilities and member’s equity	$	11,627,879	$	10,286,771	$	(10,194,297	)	$	11,720,353

68

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Operations
Year Ended December 31, 2019
(in thousands)
	Parent Issuer			Guarantors		Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	679,070	$	—		$	679,070
LNG revenues—affiliate	—			726,100		—			726,100
Total revenues	—			1,405,170		—			1,405,170
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			691,301		—			691,301
Cost of sales—affiliate	—			3,015		—			3,015
Cost of sales—related party	—			85,429		—			85,429
Operating and maintenance expense	—			242,027		—			242,027
Operating and maintenance expense—affiliate	—			59,319		—			59,319
Development expense	—			596		—			596
Development expense—affiliate	—			61		—			61
General and administrative expense	2,082			4,024		—			6,106
General and administrative expense—affiliate	—			11,352		—			11,352
Depreciation and amortization expense	24,297			206,483		—			230,780
Impairment expense and loss on disposal of assets	—			364		—			364
Total operating costs and expenses	26,379			1,303,971		—			1,330,350
Income (loss) from operations	(26,379		)	101,199		—			74,820
Other income (expense)
Interest expense, net of capitalized interest	(278,035		)	—		—			(278,035		)
Loss on modification or extinguishment of debt	(41,296		)	—		—			(41,296		)
Derivative loss, net	(133,427		)	—		—			(133,427		)
Other income	3,387			528		(273		)	3,642
Total other income (expense)	(449,371		)	528		(273		)	(449,116		)
Net income (loss)	$	(475,750	)	$	101,727	$	(273	)	$	(374,296	)

69

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Operations
Year Ended December 31, 2018
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Revenues	$	—		$	—		$	—		$	—
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			172			—			172
Operating and maintenance recovery	—			(96		)	—			(96		)
Operating and maintenance expense—affiliate	—			4,283			—			4,283
Development expense	—			177			—			177
General and administrative expense	1,513			3,750			—			5,263
General and administrative expense—affiliate	—			2,201			—			2,201
Depreciation and amortization expense	239			9,620			—			9,859
Impairment expense and gain on disposal of assets	—			20			—			20
Total operating costs and expenses	1,752			20,127			—			21,879
Loss from operations	(1,752		)	(20,127		)	—			(21,879		)
Other income (expense)
Loss on modification or extinguishment of debt	(15,332		)	—			—			(15,332		)
Derivative gain, net	43,105			—			—			43,105
Other income	352			7,952			(7,912		)	392
Total other income	28,125			7,952			(7,912		)	28,165
Net income (loss)	$	26,373		$	(12,175	)	$	(7,912	)	$	6,286

70

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Operations
Year Ended December 31, 2017
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Revenues	$	—		$	—		$	—		$	—
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			91			—			91
Operating and maintenance expense	—			3,024			—			3,024
Operating and maintenance expense—affiliate	—			2,401			—			2,401
Development expense	—			516			—			516
Development expense—affiliate	—			8			—			8
General and administrative expense	1,360			4,191			—			5,551
General and administrative expense—affiliate	—			1,173			—			1,173
Depreciation and amortization expense	13			879			—			892
Impairment expense and gain on disposal of assets	—			5,505			—			5,505
Total operating costs and expenses	1,373			17,788			—			19,161
Loss from operations	(1,373		)	(17,788		)	—			(19,161		)
Other income (expense)
Loss on modification or extinguishment of debt	(32,480		)	—			—			(32,480		)
Derivative gain, net	3,249			—			—			3,249
Other income (expense)	(265		)	15,580			(15,575		)	(260		)
Total other income (expense)	(29,496		)	15,580			(15,575		)	(29,491		)
Net loss	$	(30,869	)	$	(2,208	)	$	(15,575	)	$	(48,652	)

71

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2019
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(237,471	)	$	250,856		$	(46,758	)	$	(33,373	)
Cash flows from investing activities
Property, plant and equipment, net	(242,322		)	(1,274,840		)	—			(1,517,162		)
Investments in subsidiaries	(2,711,350		)	—			2,711,350			—
Distributions received from affiliates	1,634,489			—			(1,634,489		)	—
Other	—			(2,058		)	—			(2,058		)
Net cash used in investing activities	(1,319,183		)	(1,276,898		)	1,076,861			(1,519,220		)
Cash flows from financing activities
Proceeds from issuances of debt	4,203,550			—			—			4,203,550
Repayments of debt	(3,543,757		)	—			—			(3,543,757		)
Debt issuance and deferred financing costs	(16,210		)	—			—			(16,210		)
Debt extinguishment cost	(11,127		)	—			—			(11,127		)
Capital contributions	710,737			2,711,350			(2,711,350		)	710,737
Distributions	—			(1,681,247		)	1,681,247			—
Net cash provided by financing activities	1,343,193			1,030,103			(1,030,103		)	1,343,193
Net increase (decrease) in cash, cash equivalents and restricted cash	(213,461		)	4,061			—			(209,400		)
Cash, cash equivalents and restricted cash—beginning of period	282,248			6,893			—			289,141
Cash, cash equivalents and restricted cash—end of period	$	68,787		$	10,954		$	—		$	79,741

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2019
	Parent Issuer		Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—
Restricted cash	68,787		10,954		—		79,741
Total cash, cash equivalents and restricted cash	$	68,787	$	10,954	$	—	$	79,741

72

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2018
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows used in operating activities	$	(6,854	)	$	(51,913	)	$	(1,395	)	$	(60,162	)
Cash flows from investing activities
Property, plant and equipment, net	(555,946		)	(2,406,990		)	—			(2,962,936		)
Investments in subsidiaries	(2,532,266		)	—			2,532,266			—
Distributions received from affiliates	67,744			—			(67,744		)	—
Other	—			2,669			—			2,669
Net cash used in investing activities	(3,020,468		)	(2,404,321		)	2,464,522			(2,960,267		)
Cash flows from financing activities
Proceeds from issuances of debt	3,114,800			—			—			3,114,800
Repayments of debt	(301,455		)	—			—			(301,455		)
Debt issuance and deferred financing costs	(45,743		)	—			—			(45,743		)
Debt extinguishment cost	(9,108		)	—			—			(9,108		)
Capital contributions	324,517			2,532,266			(2,532,266		)	324,517
Distributions	—			(69,139		)	69,139			—
Net cash provided by financing activities	3,083,011			2,463,127			(2,463,127		)	3,083,011
Net increase in cash, cash equivalents and restricted cash	55,689			6,893			—			62,582
Cash, cash equivalents and restricted cash—beginning of period	226,559			—			—			226,559
Cash, cash equivalents and restricted cash—end of period	$	282,248		$	6,893		$	—		$	289,141

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2018
	Parent Issuer		Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—
Restricted cash	282,248		6,893		—		289,141
Total cash, cash equivalents and restricted cash	$	282,248	$	6,893	$	—	$	289,141

73

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows used in operating activities	$	(52,633	)	$	(11,683	)	$	—		$	(64,316	)
Cash flows from investing activities
Property, plant and equipment, net	(253,612		)	(1,733,642		)	—			(1,987,254		)
Investments in subsidiaries	(1,720,280		)	—			1,720,280			—
Other	—			25,045			—			25,045
Net cash used in investing activities	(1,973,892		)	(1,708,597		)	1,720,280			(1,962,209		)
Cash flows from financing activities
Proceeds from issuances of debt	3,040,000			—			—			3,040,000
Repayments of debt	(1,436,050		)	—			—			(1,436,050		)
Debt issuance and deferred financing costs	(23,496		)	—			—			(23,496		)
Debt extinguishment cost	(29		)	—			—			(29		)
Capital contributions	402,119			1,720,437			(1,720,437		)	402,119
Distributions	—			(157		)	157			—
Net cash provided by financing activities	1,982,544			1,720,280			(1,720,280		)	1,982,544
Net decrease in cash, cash equivalents and restricted cash	(43,981		)	—			—			(43,981		)
Cash, cash equivalents and restricted cash—beginning of period	270,540			—			—			270,540
Cash, cash equivalents and restricted cash—end of period	$	226,559		$	—		$	—		$	226,559

74

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

SUMMARIZED QUARTERLY FINANCIAL DATA

(unaudited)

Summarized Quarterly Financial Data—(in thousands)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2019:
Revenues	$	106,081		$	300,073		$	386,559		$	612,457
Income (loss) from operations	(25,402		)	(43,388		)	(90,951		)	234,561
Net income (loss)	(71,277		)	(188,907		)	(272,410		)	158,298
Year ended December 31, 2018:
Revenues	$	—		$	—		$	—		$	—
Income (loss) from operations	(3,090		)	(5,941		)	2,345			(15,193		)
Net income (loss)	65,692			7,319			24,388			(91,113		)

75

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, 2019, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

Management’s Report on Internal Control Over Financial Reporting

Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements on page 39 and is incorporated herein by reference.

ITEM 9B. OTHER INFORMATION

None.

76

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

KPMG LLP served as our independent auditor for the fiscal years ended December 31, 2019 and 2018. The following table sets forth the fees paid to KPMG LLP for professional services rendered for 2019 and 2018 (in thousands): 

	Fiscal 2019		Fiscal 2018
Audit Fees	$	1,625	$	950
Tax Fees	—		128
Total	$	1,625	$	1,078

Audit Fees—Audit fees for 2019 and 2018 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 2019 and 2018.

Tax Fees—Tax fees for 2018 was for tax consultation services with respect to a sales and use tax analysis for the Liquefaction Project. There were no tax fees in 2019.

Other Fees—There were no other fees in 2019 and 2018.

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, 2019 and 2018.

77

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	39
Report of Independent Registered Public Accounting Firm	40
Consolidated Balance Sheets	41
Consolidated Statements of Operations	42
Consolidated Statements of Member’s Equity	43
Consolidated Statements of Cash Flows	44
Notes to Consolidated Financial Statements	45
Supplemental Information to Consolidated Financial Statements—Quarterly Financial Data	75

(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
3.6	Certificate of Formation of CCP GP	CCH	S-4	3.6	1/5/2017
3.7	Certificate of Correction to Certificate of Formation of CCP GP	CCH	S-4	3.7	1/5/2017

78

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
3.8	Amended and Restated Limited Liability Company Agreement of CCP GP	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 CCP GP, 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 CCP GP, 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 CCP GP, 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 CCP GP, 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 CCP GP, as guarantors, and the Bank of New York Mellon, as trustee	CCH	8-K	4.1	9/30/2019
4.9	Indenture, dated as of October 17, 2019, among the Company, as issuer, and CCL, CCP and CCP GP, as guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	10/18/2019
4.10	Fourth Supplemental Indenture, dated as of November 13, 2019, among the Company, as issuer, CCL, CCP and CCP GP, as guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	11/13/2019
10.1	Amended and Restated Term Loan Facility Agreement, dated May 22, 2018, among the Company, CCP, CCP GP, CCL, the lenders party thereto from time to time and Société Générale as the Term Loan Facility Agent	CCH	8-K	10.1	5/24/2018
10.2	Amended and Restated Common Terms Agreement, dated May 22, 2018, among the Company, CCP, CCP GP, 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 CCP GP, 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 CCP GP, 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

79

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.5	Amended and Restated Common Security and Account Agreement, dated May 22, 2018, among the Company, CCP, CCP GP, 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
10.6	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 CCP GP, 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
10.7	Second Amendment to Common Security and Account Agreement, dated as of August 30, 2019, by and among the Company, CCL, CCP, CCP GP, 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
10.8	Amended and Restated Pledge Agreement, dated May 22, 2018, among CCH HoldCo I and Société Générale as Security Trustee	CCH	8-K	10.4	5/24/2018
10.9	Amended and Restated Equity Contribution Agreement, dated May 22, 2018, among the Company and Cheniere	CCH	8-K	10.5	5/24/2018
10.10	Amended and Restated Working Capital Facility Agreement, dated June 29, 2018, among the Company, CCP, CCP GP, 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
10.11	Registration Rights Agreement, dated as of November 13, 2019, among the Company and CCL, CCP and CCP GP, as guarantors, and BofA Securities, Inc., for itself and as representative of the purchasers	CCH	8-K	10.10	11/13/2019
10.12	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
10.13	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	10.10	11/8/2018

80

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.14	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
10.15	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	10.20	5/9/2019
10.16	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	10.20	8/8/2019
10.17	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	10.50	11/1/2019
10.18*	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.)

81

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.19	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
10.20	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
10.21	LNG Sale and Purchase Agreement (FOB), dated April 1, 2014, between CCL (Seller) and Endesa Generación, S.A. (Buyer)	Cheniere	8-K	10.10	4/2/2014
10.22	LNG Sale and Purchase Agreement (FOB), dated April 7, 2014, between CCL (Seller) and Endesa S.A. (Buyer)	Cheniere	8-K	10.10	4/8/2014
10.23	Assignment and Amendment Agreement, dated April 7, 2014, among Endesa Generación S.A., Endesa S.A. and CCL	Cheniere	10-Q	10.30	5/1/2014
10.24	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	10.90	10/30/2015
10.25	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
10.26	Amended and Restated LNG Sale and Purchase Agreement (FOB), dated March 20, 2015, between CCL (Seller) and PT Pertamina (Persero) (Buyer)	Cheniere	10-Q	10.50	4/30/2015
10.27	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
10.28	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	10.10	11/1/2019
10.29	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	10.10	6/2/2014
10.30	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	10.50	5/4/2018
10.31	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
10.32	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
10.33	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
10.34*	LNG Sale and Purchase Agreement (EOG Early IPM), dated December 30, 2019, between CCL (Seller) and Cheniere Marketing (Buyer)
21.1*	Subsidiaries of the Company
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

82

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
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 — See Index to Financial Statements on page S-1.

The accompanying Financial Statements of our subsidiaries, CCL, CCP and CCP GP, are being provided pursuant to Rule 3-16 of Regulation S-X, which requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities.

83

ITEM 16. FORM 10-K SUMMARY

None.

84

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/ Michael J. Wortley
	Michael J. Wortley
	President and Chief Financial Officer
	(Principal Executive and Financial Officer)
Date:	February 24, 2020

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/ Michael J. Wortley	Manager, President and Chief Financial Officer (Principal Executive and Financial Officer)	February 24, 2020
Michael J. Wortley
/s/ Aaron Stephenson	Manager	February 24, 2020
Aaron Stephenson
/s/ Leonard E. Travis	Chief Accounting Officer (Principal Accounting Officer)	February 24, 2020
Leonard E. Travis

85

CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS OF SUBSIDIARIES INCLUDED

PURSUANT TO RULE 3-16 OF REGULATION S-X

AUDITED FINANCIAL STATEMENTS OF CORPUS CHRISTI LIQUEFACTION, LLC	S-2
Independent Auditors’ Report	S-4
Balance Sheets	S-5
Statements of Operations	S-6
Statements of Member’s Equity	S-7
Statements of Cash Flows	S-8
Notes to Financial Statements	S-9
AUDITED FINANCIAL STATEMENTS OF CHENIERE CORPUS CHRISTI PIPELINE, L.P.	S-24
Independent Auditors’ Report	S-26
Balance Sheets	S-27
Statements of Operations	S-28
Statements of Partners’ Equity	S-29
Statements of Cash Flows	S-30
Notes to Financial Statements	S-31
AUDITED FINANCIAL STATEMENTS OF CORPUS CHRISTI PIPELINE GP, LLC	S-39
Independent Auditors’ Report	S-41
Balance Sheets	S-42
Statements of Operations	S-43
Statements of Member’s Equity (Deficit)	S-44
Statements of Cash Flows	S-45
Notes to Financial Statements	S-46

S-1

Corpus Christi Liquefaction, LLC

Financial Statements

As of December 31, 2019 and 2018

and for the years ended December 31, 2019, 2018 and 2017

S-2

CORPUS CHRISTI LIQUEFACTION, LLC

FINANCIAL STATEMENTS

DEFINITIONS

As used in these Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

EPC	engineering, procurement and construction
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
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, an energy unit
mtpa	million tonnes per annum
SEC	U.S. Securities and Exchange Commission
SPA	LNG sale and purchase agreement
TBtu	trillion British thermal units, an energy unit
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2019 and the references to these entities used in these Financial Statements:

Unless the context requires otherwise, references to “the Company,” “we,” “us,” and “our” refer to Corpus Christi Liquefaction, LLC.

S-3

Independent Auditors’ Report

To the Member and Managers of

Corpus Christi Liquefaction, LLC:

We have audited the accompanying financial statements of Corpus Christi Liquefaction, LLC (the Company), which comprise the balance sheets as of December 31, 2019 and 2018, and the related statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Corpus Christi Liquefaction, LLC as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the financial statements, in 2019, 2018, and 2017, the Company adopted new accounting guidance ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. Our opinion is not modified with respect to this matter.

/s/    KPMG LLP

KPMG LLP

Houston, Texas

February 24, 2020

S-4

CORPUS CHRISTI LIQUEFACTION, LLC

BALANCE SHEETS

(in thousands)

	December 31,
	2019		2018
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	10,954		6,893
Accounts receivable	57,712		24,989
Accounts receivable—affiliate	57,547		27,241
Advances to affiliate	108,126		78,805
Inventory	66,947		25,093
Derivative assets	73,809		5,071
Derivative assets—related party	2,623		2,132
Other current assets	14,075		8,717
Other current assets—affiliate	4		633
Total current assets	391,797		179,574
Property, plant and equipment, net	10,798,568		9,662,863
Non-current derivative assets	61,217		11,114
Non-current derivative assets—related party	1,933		3,381
Other non-current assets, net	51,066		27,918
Total assets	$	11,304,581	$	9,884,850
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	6,610	$	15,186
Accrued liabilities	356,031		148,920
Accrued liabilities—related party	2,531		—
Due to affiliates	34,211		24,500
Derivative liabilities	6,920		13,569
Other current liabilities	364		—
Other current liabilities—affiliate	519		—
Total current liabilities	407,186		202,175
Non-current derivative liabilities	86,006		8,197
Other non-current liabilities	4,802		—
Other non-current liabilities—affiliate	1,284		—
Commitments and contingencies (see Note 11)
Member’s equity	10,805,303		9,674,478
Total liabilities and member’s equity	$	11,304,581	$	9,884,850

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

S-5

CORPUS CHRISTI LIQUEFACTION, LLC

STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2019		2018			2017
Revenues
LNG revenues	$	679,070	$	—		$	—
LNG revenues—affiliate	726,100		—			—
Total revenues	1,405,170		—			—
Expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	691,301		172			91
Cost of sales—affiliate	14,626		—			—
Cost of sales—related party	85,429		—			—
Operating and maintenance expense	220,715		2,089			3,008
Operating and maintenance expense—affiliate	104,597		1,178			2,331
Development expense	596		177			516
Development expense—affiliate	61		—			8
General and administrative expense	2,986		3,016			3,951
General and administrative expense—affiliate	11,260		2,087			1,127
Depreciation and amortization expense	195,809		3,460			810
Impairment expense and loss on disposal of assets	364		20			5,500
Total operating costs and expenses	1,327,744		12,199			17,342
Income (loss) from operations	77,426		(12,199		)	(17,342		)
Other income
Other income	260		40			5
Other income—affiliate	—		12			12
Total other income	260		52			17
Net income (loss)	$	77,686	$	(12,147	)	$	(17,325	)

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

S-6

CORPUS CHRISTI LIQUEFACTION, LLC

STATEMENTS OF MEMBER'S EQUITY

(in thousands)

	Cheniere Corpus Christi Holdings, LLC			Total Member’s Equity
Balance at December 31, 2016	$	5,687,512		$	5,687,512
Capital contributions	1,516,772			1,516,772
Net loss	(17,325		)	(17,325		)
Balance at December 31, 2017	7,186,959			7,186,959
Capital contributions	2,567,410			2,567,410
Distributions	(67,744		)	(67,744		)
Net loss	(12,147		)	(12,147		)
Balance at December 31, 2018	9,674,478			9,674,478
Capital contributions	2,670,627			2,670,627
Distributions	(1,617,488		)	(1,617,488		)
Net income	77,686			77,686
Balance at December 31, 2019	$	10,805,303		$	10,805,303

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

S-7

CORPUS CHRISTI LIQUEFACTION, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities
Net income (loss)	$	77,686		$	(12,147	)	$	(17,325	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization expense	195,809			3,460			810
Total losses (gains) on derivatives, net	(45,375		)	(23		)	91
Total losses on derivatives, net—related party	957			—			—
Net cash used for settlement of derivative instruments	(2,306		)	—			—
Impairment expense and loss on disposal of assets	364			20			5,500
Other	1,473			—			—
Changes in operating assets and liabilities:
Accounts receivable	(57,654		)	(51		)	—
Accounts receivable—affiliate	(53,622		)	—			—
Advances to affiliate	(59,999		)	—			—
Inventory	(35,758		)	(23,746		)	—
Accounts payable and accrued liabilities	169,619			7,417			58
Accounts payable—related party	2,531			—			—
Due to affiliates	23,913			(459		)	1,561
Other, net	(6,681		)	(9,689		)	(1,202		)
Other, net—affiliate	94			(109		)	(667		)
Net cash provided by (used in) operating activities	211,051			(35,327		)	(11,174		)
Cash flows from investing activities
Property, plant and equipment, net	(1,258,348		)	(2,379,990		)	(1,530,642		)
Other	(1,781		)	4,843			25,045
Net cash used in investing activities	(1,260,129		)	(2,375,147		)	(1,505,597		)
Cash flows from financing activities
Capital contributions	2,670,627			2,485,111			1,516,771
Distributions	(1,617,488		)	(67,744		)	—
Net cash provided by financing activities	1,053,139			2,417,367			1,516,771
Net increase in cash, cash equivalents and restricted cash	4,061			6,893			—
Cash, cash equivalents and restricted cash—beginning of period	6,893			—			—
Cash, cash equivalents and restricted cash—end of period	$	10,954		$	6,893		$	—

Balances per Balance Sheets:

	December 31,
	2019		2018
Cash and cash equivalents	$	—	$	—
Restricted cash	10,954		6,893
Total cash, cash equivalents and restricted cash	$	10,954	$	6,893

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

S-8

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

CCL is a Delaware limited liability company formed in 2011 by Cheniere to develop, construct and operate natural gas liquefaction and export facilities at the Corpus Christi LNG terminal near Corpus Christi, Texas (the “Liquefaction Facilities”). CCP owns and operates a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) that interconnects the Liquefaction Facilities with several interstate and intrastate natural gas pipelines. We are currently operating two Trains and are constructing one additional Train for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain three LNG storage tanks and two marine berths.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements have been prepared in accordance with GAAP.

Recent Accounting Standards

We adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), and subsequent amendments thereto on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. The adoption of the standard did not materially impact our Financial Statements. Upon adoption of the standard, we recorded right-of-use assets of $8.1 million in other non-current assets, net, and lease liabilities of $0.5 million in other current liabilities—affiliate, $5.2 million other non-current liabilities and $1.2 million in other non-current liabilities—affiliate.

In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The new guidance retrospectively eliminates the requirement to allocate the consolidated amount of current and deferred tax expense to entities that are not subject to income tax such as us, as further described under Income Taxes in this note. We early adopted this guidance effective December 31, 2019 and recorded a cumulative-effect adjustment to retained earnings of $144 thousand. The provision for income taxes, taxes payable and deferred income tax balances have been retrospectively removed from our Financial Statements.

Use of Estimates

The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements, revenue recognition, property, plant and equipment and derivative instruments, 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.

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Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 6—Derivative Instruments. The carrying amount of restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximate fair value.

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. Revenues from the sale of LNG are recognized as LNG revenues. See Note 9—Revenues from Contracts with Customers for further discussion of revenues.

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

Restricted cash 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 Balance Sheets. As of December 31, 2019 and 2018, restricted cash consisted of funds restricted for the development, construction and operation of the Liquefaction Project.

Accounts Receivable

Accounts receivable is reported net of any allowances for doubtful accounts. We periodically review the collectability on our accounts receivable and recognize an allowance if there is probability of non-collection, based on historical write-off and customer-specific factors. We did not have an allowance on our accounts receivable as of December 31, 2019 and 2018.

Inventory

LNG and natural gas inventory is 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 and subsequently charged to expense when issued.

Accounting for LNG Activities

Generally, we begin capitalizing the costs of a Train once it meets the following criteria: (1) regulatory approval has been received, (2) financing for the Train is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a Train 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 the Train.

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. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.

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. 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. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in impairment expense and loss (gain) on disposal of assets.

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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 is identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. During the year ended December 31, 2017, we recognized $5.5 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our 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. When we have the contractual right and intend 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, 2019, 2018 and 2017. See Note 6—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

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 as other current asset. 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.

We have entered into fixed price SPAs generally with terms of 20 years with nine third parties and have entered into agreements with Cheniere Marketing International LLP (“Cheniere Marketing”). We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 12—Customer Concentration for additional details about our customer concentration.

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 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 Financial Statements.

Business Segment

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

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2019 and 2018, accounts and other receivables consisted of the following (in thousands):

	December 31,
	2019		2018
Trade receivable	$	44,403	$	51
Other accounts receivable	13,309		24,938
Total accounts and other receivables	$	57,712	$	24,989

NOTE 4—INVENTORY

As of December 31, 2019 and 2018, inventory consisted of the following (in thousands):

	December 31,
	2019		2018
Natural gas	$	6,870	$	1,326
LNG	6,103		—
Materials and other	53,974		23,767
Total inventory	$	66,947	$	25,093

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

As of December 31, 2019 and 2018, property, plant and equipment, net consisted of the following (in thousands):

	December 31,
	2019			2018
LNG terminal costs
LNG terminal	$	8,564,732		$	218,288
LNG site and related costs	273,646			42,551
LNG terminal construction-in-process	2,142,452			9,392,758
Accumulated depreciation	(192,577		)	(1,503		)
Total LNG terminal costs, net	10,788,253			9,652,094
Fixed assets
Fixed assets	16,535			13,366
Accumulated depreciation	(6,220		)	(2,597		)
Total fixed assets, net	10,315			10,769
Property, plant and equipment, net	$	10,798,568		$	9,662,863

 

Depreciation expense was $195.0 million, $3.2 million and $0.7 million during the years ended December 31, 2019, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $156.1 million and $48.7 million during the years ended December 31, 2019 and 2018, respectively, that were related to the sales 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 . We did not realize any offsets to LNG terminal costs during the year ended December 31, 2017.

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 10 and 50 years, as follows:

Components	Useful life (yrs)
Water pipelines	30
Liquefaction processing equipment	10-50
Other	15-30

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 6—DERIVATIVE INSTRUMENTS

We have entered into 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 Statements of Operations to the extent not utilized for the commissioning process.

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, 2019 and 2018, which are classified as derivative assets, derivative assets—related party, non-current derivative assets, non-current derivative assets—related party, derivative liabilities or non-current derivative liabilities in our Balance Sheets (in thousands):

	Fair Value Measurements as of
	December 31, 2019								December 31, 2018
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total
Liquefaction Supply Derivatives asset (liability)	$	2,383	$	9,198	$	35,075	$	46,656	$	1,299	$	2,990	$	(4,357	)	$	(68	)

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 conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of December 31, 2019 and 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

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.

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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 prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2019:

	Net Fair Value Asset (in thousands)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$35,075	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.718) - $0.050
		Option pricing model	International LNG pricing spread, relative to Henry Hub (1)	86% - 191%

(1)    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.

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, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018			2017
Balance, beginning of period	$	(4,357	)	$	(91	)	$	—
Realized and mark-to-market gains (losses):
Included in cost of sales	(82,645		)	(9,944		)	—
Purchases and settlements:
Purchases	120,755			5,678			(91		)
Settlements	1,432			—			—
Transfers out of Level 3 (1)	(110		)	—			—
Balance, end of period	$	35,075		$	(4,357	)	$	(91	)
Change in unrealized losses relating to instruments still held at end of period	$	(82,645	)	$	(9,944	)	$	—

(1) Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. 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.

The forward notional for our Liquefaction Supply Derivatives was approximately 3,153 TBtu and 2,854 TBtu as of December 31, 2019 and 2018, respectively, of which 120 TBtu and 55 TBtu, respectively, were for a natural gas supply contract CCL has with a related party. The remaining terms of the physical natural gas supply contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent.

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

	Fair Value Measurements as of (1)
Balance Sheet Location	December 31, 2019			December 31, 2018
Derivative assets	$	73,809		$	5,071
Derivative assets—related party	2,623			2,132
Non-current derivative assets	61,217			11,114
Non-current derivative assets—related party	1,933			3,381
Total derivative assets	139,582			21,698
Derivative liabilities	(6,920		)	(13,569		)
Non-current derivative liabilities	(86,006		)	(8,197		)
Total derivative liabilities	(92,926		)	(21,766		)
Derivative asset (liability), net	$	46,656		$	(68	)

(1) Does not include collateral posted with counterparties by us of $4.5 million for such contracts, which are included in other current assets in our Balance Sheets as of both December 31, 2019 and 2018.

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Statements of Operations during the years ended December 31, 2019, 2018 and 2017 (in thousands):

		Year Ended December 31,
	Statements of Operations Location (1)	2019			2018		2017
Liquefaction Supply Derivatives gain	LNG revenues	$	227		$	—	$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	45,148			23		(91		)
Liquefaction Supply Derivatives loss	Cost of sales—related party	(957		)	—		—

(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.

Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amounts Presented in the Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of December 31, 2019
Liquefaction Supply Derivatives	$	145,135		$	(5,553	)	$	139,582
Liquefaction Supply Derivatives	(98,625		)	5,699			(92,926		)
As of December 31, 2018
Liquefaction Supply Derivatives	$	31,770		$	(10,072	)	$	21,698
Liquefaction Supply Derivatives	(29,996		)	8,230			(21,766		)

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NOTE 7—OTHER NON-CURRENT ASSETS

As of December 31, 2019 and 2018, other non-current assets, net consisted of the following (in thousands):

	December 31,
	2019		2018
Advances and other asset conveyances to third parties to support LNG terminal	$	18,703	$	18,209
Operating lease assets	7,215		—
Tax-related payments and receivables	3,200		3,783
Information technology service prepayments	2,720		2,251
Advances made under EPC and non-EPC contracts	14,067		—
Other	5,161		3,675
Total other non-current assets, net	$	51,066	$	27,918

NOTE 8—ACCRUED LIABILITIES

As of December 31, 2019 and 2018, accrued liabilities consisted of the following (in thousands): 

	December 31,
	2019		2018
Accrued natural gas purchases	$	132,148	$	—
Liquefaction Project costs	191,093		129,633
Other	32,790		19,287
Total accrued liabilities	$	356,031	$	148,920

NOTE 9—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018		2017
LNG revenues	$	678,843	$	—	$	—
LNG revenues—affiliate	726,100		—		—
Total revenues from customers	1,404,943		—		—
Net derivative gains (1)	227		—		—
Total revenues	$	1,405,170	$	—	$	—

(1)    See Note 6—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 equal to approximately 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 10—Related Party Transactions for additional information regarding these agreements.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, 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

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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.

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, 2019 and 2018:

	December 31, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	33.6	11	$	33.9	12
LNG revenues—affiliate	1.0		13	1.0		14
Total revenues	$	34.6		$	34.9

(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 44% during the year ended December 31, 2019 of our LNG revenues were related to variable consideration received from customers. All of our LNG revenues—affiliate were related to variable consideration received from customers during the year ended December 31, 2019.

We have entered 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.

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NOTE 10—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Operations for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018		2017
LNG revenues—affiliate
SPAs and Base SPAs	$	719,069	$	—	$	—
Contracts for Sale and Purchase of Natural Gas and LNG	7,031		—		—
Total LNG revenue—affiliate	726,100		—		—
Cost of sales—affiliate
Transportation Agreement	5,868		—		—
Contracts for Sale and Purchase of Natural Gas and LNG	8,758		—		—
Total cost of sales—affiliate	14,626		—		—
Cost of sales—related party
Natural Gas Supply Agreement	85,429		—		—
Operating and maintenance expense—affiliate
Services Agreements	50,681		298		2,005
Land Agreements	53,916		880		326
Total operating and maintenance expense—affiliate	104,597		1,178		2,331
Development expense—affiliate
Services Agreements	61		—		8
General and administrative expense—affiliate
Services Agreements	11,260		2,087		1,127
Other income—affiliate
Land Agreements	—		12		12

We had $34.2 million and $24.5 million due to affiliates as of December 31, 2019 and 2018, respectively, under agreements with affiliates, as described below.

LNG Sale and Purchase Agreements

We have 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, (2) any LNG produced from the end of the commissioning period for Train 1 until the date of first commercial delivery of LNG from Train 1 and (3) 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, we have: (1) a fixed price SPA with an approximate term of 23 years with Cheniere Marketing which allows them to purchase volumes of approximately 15 TBtu per annum of LNG and (2) an SPA for 0.85 mtpa of LNG with a term of up to seven years associated with the integrated production marketing gas supply agreement between us and EOG Resources, Inc. As of December 31, 2019 and 2018, we had $57.2 million and $21.1 million of accounts receivable—affiliate, respectively, under these agreements.

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Services Agreements

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

We have 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 our gas and power procurement requirements. The services include, among other services, exercising the day-to-day management of our natural gas and power supply requirements, negotiating agreements on our 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, we 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 Agreement (“O&M Agreement”)

We have an O&M Agreement with Cheniere LNG O&M Services, LLC (“O&M Services”), a wholly owned subsidiary of Cheniere, pursuant to which we receive 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, we 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.

Management Services Agreement (“MSA”)

We have an 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 O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our 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, we 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.

Natural Gas Supply Agreement

We entered into a natural gas supply contract to obtain feed gas for the operation of the Liquefaction Project through March 2022 with a related party in the ordinary course of business. We have recorded $85.4 million in cost of sales—related party under this contract during the year ended December 31, 2019. Of this amount, $2.5 million and zero was included in accrued liabilities—related party as of December 31, 2019 and 2018, respectively. We did not have any deliveries during the year ended December 31, 2018 under this contract. We also have recorded derivative assets—related party of $2.6 million and $2.1 million and non-current derivative assets—related party of $1.9 million and $3.4 million as of December 31, 2019 and 2018, respectively, related to this contract.

Agreements with Midship Pipeline

We have entered into a transportation precedent agreement and a negotiated rate agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) to secure firm pipeline transportation capacity for a period of 10 years following commencement of the approximately 200-mile natural gas pipeline project which Midship Pipeline is constructing. In May 2018, we issued a letter of credit to Midship Pipeline for drawings up to an aggregate maximum amount of $16.2 million. Midship Pipeline had not made any drawings on this letter of credit as of December 31, 2019.

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CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Contracts for Sale and Purchase of Natural Gas and LNG

We have agreements with Sabine Pass Liquefaction, LLC and CCP that allows us to sell and purchase natural gas with each party. Natural gas purchased under these agreements are 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 these agreements are recorded as LNG revenues—affiliate.

We also have an agreement with Midship Pipeline that allows us to sell and purchase natural gas with Midship Pipeline. We did not have any transactions under this agreement during the years ended December 31, 2019, 2018 and 2017.

Land Agreements

We had $4.0 thousand and $0.3 million as of December 31, 2019 and 2018, respectively, of prepaid expense related to these agreements in other current assets—affiliate.

Lease Agreements

We have 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 five years.

CCP has an agreement with us to lease a portion of the Liquefaction Facilities site for the purpose of the construction and operation of a meter station to measure the amount of natural gas delivered to the Liquefaction Facilities. The annual lease payment is $12,000, which is recorded as an offset to operating and maintenance expense—affiliate, upon adoption of ASC 842. The initial term of the lease is 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In conjunction with this lease, we also have a pipeline right of way easement agreement with CCP granting CCP the right to construct, install and operate a natural gas pipeline on the Liquefaction Facilities site.

Easement Agreements

We have agreements with Cheniere Land Holdings which grant us 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.

Access Road Use License Agreement

In February 2018, we entered into an agreement with CCP which grants them a limited license to enter the access road owned by us for access to the Liquefaction Facilities. The annual payment for this agreement is $5 thousand, and the term of the agreement is five years.

Dredge Material Disposal Agreement

We have a dredge material disposal agreement with Cheniere Land Holdings that terminates in 2042 which grants us 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, we 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, we 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 us for any third party costs incurred by us in connection with providing the goods and services.

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CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Natural Gas Transportation Agreements

We have a transportation precedent agreement, a firm transportation service agreement and a negotiated rate agreement with CCP for firm gas transportation capacity for up to three Trains on both a forward and back haul basis from the interstate and intrastate pipeline grid to the Liquefaction Facilities. These agreements have a primary term of 20 years from April 2019, and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CCP has advised us that it has agreed otherwise. We had $7.4 million and $1.1 million included in due to affiliate as of December 31, 2019 and 2018, respectively, under the transportation agreement.

Operational Balancing Agreement

We have an amended Operational Balancing Agreement (“OBA”) with CCP that provides for the resolution of any operational imbalances (1) during the term of the agreement on an in-kind basis and (2) upon termination of the agreement by cash-out at a rate equivalent to the average of the midpoint prices for East Texas—Houston Ship Channel pricing published in Platts’ “Gas Daily Price Guide - Final Daily Price Survey” for each day of the month following termination. As of December 31, 2019 and 2018 we had $1.8 million and $6.2 million in accounts receivable—affiliate, respectively, under the amended OBA.

State Tax Sharing Agreement

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

NOTE 11—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2019, are not recognized as liabilities but require disclosures in our Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contracts

We have lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 3 of the Liquefaction Project. The EPC contract prices for Train 3 of the Liquefaction Project is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2019. As of December 31, 2019, we have incurred $2.0 billion under this contract. We have the right to terminate each of the EPC contracts for our convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.

Obligations under SPAs

We have third-party SPAs which obligate us to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project. We also have entered into SPAs with Cheniere Marketing, as further described in Note 10—Related Party Transactions.

Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

We have physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to eight years, some of which commence upon the satisfaction of certain events or states of affairs.

S-21

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

As of December 31, 2019, we had secured up to approximately 2,999 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the certain events or states of affairs are satisfied.

Additionally, we have 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, 2019, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in thousands): 

Years Ending December 31,	Payments Due (1)
2020	$	1,255,512
2021	1,047,335
2022	711,428
2023	591,844
2024	483,856
Thereafter	2,072,188
Total	$	6,162,163

(1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2019.

Services Agreements

We have certain services agreements with affiliates. See Note 10—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere.  See Note 10—Related Party Transactions for information regarding this agreement.

Obligations under Guarantee Contract

The subsidiaries of CCH, including us, have jointly and severally guaranteed the debt obligations of CCH. See Note 14—Guarantees and Collateralization for information regarding these guarantees.

Other Commitments

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.

Environmental and Regulatory Matters

The Liquefaction Facilities 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

S-22

CORPUS CHRISTI LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

disposition of these matters. In the opinion of management, as of December 31, 2019, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

NOTE 12—CUSTOMER CONCENTRATION

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

	Percentage of Total Revenues from External Customers			Percentage of Accounts Receivable from External Customers
	Year Ended December 31,			December 31,
	2019	2018	2017	2019	2018
Customer A	57%	—%	—%	38%	—%
Customer B	23%	—%	—%	39%	—%

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

	Revenues from External Customers
	Year Ended December 31,
	2019		2018		2017
Spain	$	451,199	$	—	$	—
Indonesia	154,584		—		—
United States	73,287		—		—
Total	$	679,070	$	—	$	—

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2019		2018		2017
Non-cash capital contribution for conveyance of property, plant and equipment from affiliate	$	—	$	82,299	$	—
Non-cash capital contribution of net operating losses from affiliate	—		144		—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $182.5 million, $168.9 million and $110.3 million as of December 31, 2019, 2018 and 2017, respectively.

NOTE 14—GUARANTEES AND COLLATERIZATION

The subsidiaries of CCH, including us, have jointly and severally guaranteed and collaterized the debt obligations of CCH, including: (1) $1.25 billion of the 7.000% Senior Secured Notes due 2024, (2) $1.5 billion of the 5.875% Senior Secured Notes due 2025, (3) $1.5 billion of the 5.125% Senior Secured Notes due 2027, (4) $727 million of the 4.80% Senior Secured Notes due 2039, (5) $475 million of the 3.925% Senior Secured Notes due 2039, (6) $1.5 billion of the 3.700% Senior Secured Notes due 2029, (7) a term loan facility of which CCH had no available commitments and approximately $3.3 billion of outstanding borrowings as of December 31, 2019 and (8) a $1.2 billion working capital facility of which CCH had $729.2 million of available commitments and no outstanding borrowings as of December 31, 2019. CCH entered into the above debt instruments and its use is solely to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project and related business purposes. As of December 31, 2019, we had no liability recorded related to these guarantees.

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Cheniere Corpus Christi Pipeline, L.P.

Financial Statements

As of December 31, 2019 and 2018

and for the years ended December 31, 2019, 2018 and 2017

S-24

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

FINANCIAL STATEMENTS

DEFINITIONS

As used in these Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

GAAP	generally accepted accounting principles in the United States
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
SEC	U.S. Securities and Exchange Commission
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2019 and the references to these entities used in these Financial Statements:

Unless the context requires otherwise, references to “CCP,” “the Partnership,” “we,” “us,” and “our” refer to Cheniere Corpus Christi Pipeline, L.P.

S-25

Independent Auditors’ Report

To the Managers of Corpus Christi Pipeline GP, LLC and

Partners of Cheniere Corpus Christi Pipeline, L.P.:

We have audited the accompanying financial statements of Cheniere Corpus Christi Pipeline, L.P. (the Partnership), which comprise the balance sheets as of December 31, 2019 and 2018, and the related statements of operations, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cheniere Corpus Christi Pipeline, L.P. as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the financial statements, in 2019, 2018, and 2017, the Partnership adopted new accounting guidance ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. Our opinion is not modified with respect to this matter.

/s/    KPMG LLP

KPMG LLP

Houston, Texas

February 24, 2020

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

BALANCE SHEETS

(in thousands)

	December 31,
	2019		2018
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash	—		—
Accounts receivable—affiliate	7,372		1,100
Advances to affiliate	7,350		15,592
Inventory	2,232		1,105
Operational balancing assets	190		6,106
Operational balancing assets—affiliate	1,819		—
Other current assets	338		216
Total current assets	19,301		24,119
Property, plant and equipment, net	383,457		376,658
Other non-current assets, net	4,746		3,790
Total assets	$	407,504	$	404,567
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	648	$	945
Accrued liabilities	4,451		12,033
Due to affiliates	1,879		1,679
Operational balancing liabilities—affiliate	—		6,189
Other current liabilities—affiliate	12		—
Total current liabilities	6,990		20,846
Other non-current liabilities	5,631		—
Other non-current liabilities—affiliate	170		—
Commitments and contingencies (see Note 7)
Partners’ equity	394,713		383,721
Total liabilities and partners’ equity	$	407,504	$	404,567

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

S-27

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2019			2018			2017
Revenues
Pipeline revenues—affiliate	$	61,875		$	1,559		$	—
Other revenues—affiliate	4,241			—			—
Total revenues	66,116			1,559			—
Expenses
Operating and maintenance expense (recovery)	21,312			(2,185		)	16
Operating and maintenance expense (recovery)—affiliate	(806		)	9,315			82
General and administrative expense	1,028			718			234
General and administrative expense—affiliate	92			114			46
Depreciation and amortization expense	10,725			6,160			69
Other expense	—			—			5
Total expenses	32,351			14,122			452
Income (loss) from operations	33,765			(12,563		)	(452		)
Other income
Other income	268			7,912			15,575
Other income—affiliate	5			5			—
Total other income	273			7,917			15,575
Net income (loss)	$	34,038		$	(4,646	)	$	15,123

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

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.

STATEMENTS OF PARTNERS’ EQUITY

(in thousands)

	Corpus Christi Pipeline GP, LLC		Cheniere Corpus Christi Holdings, LLC			Total Partners’ Equity
Balance at December 31, 2016	$	1	$	123,228		$	123,229
Capital contributions	—		203,660			203,660
Distributions	—		(157		)	(157		)
Net income	—		15,123			15,123
Balance at December 31, 2017	1		341,854			341,855
Capital contributions	—		47,907			47,907
Distributions	—		(1,395		)	(1,395		)
Net loss	—		(4,646		)	(4,646		)
Balance at December 31, 2018	1		383,720			383,721
Capital contributions	—		40,713			40,713
Distributions	—		(63,759		)	(63,759		)
Net income	—		34,038			34,038
Balance at December 31, 2019	$	1	$	394,712		$	394,713

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

S-29

CHENIERE CORPUS CHRISTI PIPELINE, L.P.

STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities
Net income (loss)	$	34,038		$	(4,646	)	$	15,123
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization expense	10,726			6,160			69
Allowance for funds used during construction	(268		)	(7,912		)	(15,575		)
Other	131			—			5
Changes in operating assets and liabilities:
Accounts receivable—affiliate	(6,272		)	(1,100		)	—
Advances to affiliate	6,769			(10,911		)	—
Inventory	(1,127		)	(1,105		)	—
Operational balancing assets	5,916			(6,106		)	—
Regulatory assets	(635		)	(158		)	—
Accounts payable and accrued liabilities	1,450			2,862			26
Due to affiliates	629			989			6
Operational balancing assets and liabilities—affiliate	(8,007		)	6,189			—
Regulatory liabilities	5,631			—			—
Other, net	(296		)	(379		)	(157		)
Other, net—affiliate	(3		)	—			—
Net cash provided by (used in) operating activities	48,682			(16,117		)	(503		)
Cash flows from investing activities
Property, plant and equipment, net	(25,359		)	(27,463		)	(203,000		)
Other	(277		)	(2,174		)	—
Net cash used in investing activities	(25,636		)	(29,637		)	(203,000		)
Cash flows from financing activities
Capital contributions	40,713			47,149			203,660
Distributions	(63,759		)	(1,395		)	(157		)
Net cash provided by (used in) financing activities	(23,046		)	45,754			203,503
Net increase (decrease) in cash, cash equivalents and restricted cash	—			—			—
Cash, cash equivalents and restricted cash—beginning of period	—			—			—
Cash, cash equivalents and restricted cash—end of period	$	—		$	—		$	—

Balances per Balance Sheets:

	December 31,
	2019		2018
Cash and cash equivalents	$	—	$	—
Restricted cash	—		—
Total cash, cash equivalents and restricted cash	$	—	$	—

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

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CHENIERE CORPUS CHRISTI PIPELINE, L.P. 

NOTES TO FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

CCP, a Delaware limited partnership, is a Houston based partnership formed by Cheniere. In November 2014, Cheniere contributed CCP to CCP GP as the general partner, and CCH as the limited partner, both of which are wholly owned subsidiaries of Cheniere. CCH was formed in September 2014 by Cheniere to hold its limited partner interest in us and its equity interests in CCL and CCP GP.

We own and operate a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline”) that interconnects the natural gas liquefaction and export facility at the Corpus Christi LNG terminal being operated and constructed by CCL (the “Liquefaction Facilities” and together with the Corpus Christi Pipeline, the “Liquefaction Project”) with several interstate and intrastate natural gas pipelines. CCL is currently operating two Trains and is constructing one additional Train for a total production capacity of approximately 15 mtpa of LNG.

CCL has entered into transportation precedent and other agreements to secure firm pipeline capacity with us, which supplement enabling agreements and long-term natural gas supply contracts CCL has executed with third parties to secure natural gas feedstock for the Liquefaction Project.

The development, construction, operation and maintenance of the Liquefaction Project is funded through contributions received from our parent, CCH.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements have been prepared in accordance with GAAP, which for regulated companies, includes specific accounting guidance for regulated operations.

Recent Accounting Standards

We adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), and subsequent amendments thereto on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. The adoption of the standard did not materially impact our Financial Statements. Upon adoption of the standard, we recorded right-of-use assets of $0.2 million in other non-current assets, net, and lease liabilities of $0.2 million in other non-current liabilities—affiliate.

In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The new guidance retrospectively eliminates the requirement to allocate the consolidated amount of current and deferred tax expense to entities that are not subject to income tax such as us, as further described under Income Taxes in this note. We early adopted this guidance effective December 31, 2019 and recorded a cumulative-effect adjustment to retained earnings of $2.0 million. The provision for income taxes, taxes payable and deferred income tax balances have been retrospectively removed from our Financial Statements.

Use of Estimates

The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to 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.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Revenue Recognition

We transport natural gas for CCL under a negotiated rate contract, as further discussed in Note 6—Related Party Transactions. See Note 5—Revenues from Contracts with Customers for further discussion of revenues.

Cash, Cash Equivalents and Restricted Cash

We did not have any cash and cash equivalents or restricted cash as of December 31, 2019. Our operations are funded through contributions from CCH.

Accounts Receivable

Accounts receivable is reported net of any allowances for doubtful accounts. We periodically review the collectability on our accounts receivable and recognize an allowance if there is probability of non-collection, based on historical write-off and customer-specific factors. We did not have an allowance on our accounts receivable as of December 31, 2019 and 2018.

Inventory

Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued.

Operational Imbalances

Our balance sheets include natural gas imbalance receivables and payables resulting from differences in volumes received into the Corpus Christi Pipeline and volumes we delivered to our customers and vendors. Volumes owed to or by us that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by us are valued in accordance with the contractual requirements of the respective pipelines’ tariff and are settled in-kind. Operational imbalances are reported in operational balancing assets and operational balancing liabilities in our balance sheets.

Accounting for Pipeline Activities

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

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.

Property, Plant and Equipment 

Property, plant and equipment are recorded at cost. Expenditures for construction 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. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in accumulated depreciation. All of our long-lived assets are located in the United States.

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CHENIERE CORPUS CHRISTI PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction (“AFUDC”) represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC is calculated based on the average cost of debt of CCH, which is contributed to us to fund the construction of the Corpus Christi Pipeline. AFUDC is included in “other income” on our Statements of Operations and was $0.3 million, $7.9 million and $15.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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 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 Financial Statements.

Business Segment

Our pipeline business represents a single reportable segment. Our chief operating decision maker reviews the financial results of CCP in total when evaluating financial performance and for purposes of allocating resources.

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

As of December 31, 2019 and 2018, property, plant and equipment, net consisted of the following (in thousands):

	December 31,
	2019			2018
Natural gas pipeline costs
Natural gas pipeline	$	383,668		$	369,653
Natural gas pipeline construction-in-process	11,746			9,022
Land	2,313			2,174
Accumulated depreciation	(15,491		)	(5,726		)
Total natural gas pipeline costs	382,236			375,123
Fixed assets
Fixed assets	2,396			2,017
Accumulated depreciation	(1,175		)	(482		)
Total fixed assets, net	1,221			1,535
Property, plant and equipment, net	$	383,457		$	376,658

 

Depreciation expense was $10.7 million, $6.1 million and $0.1 million during the years ended December 31, 2019, 2018 and 2017, respectively.

S-33

CHENIERE CORPUS CHRISTI PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Our natural gas pipeline cost is depreciated using the straight-line depreciation method with an estimated useful life of 40 years. Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 4—ACCRUED LIABILITIES

As of December 31, 2019 and 2018, accrued liabilities consisted of the following (in thousands): 

	December 31,
	2019		2018
Pipeline costs	$	1,122	$	9,241
Other	3,329		2,792
Total accrued liabilities	$	4,451	$	12,033

NOTE 5—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts from customers during the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018		2017
Pipeline revenues—affiliate	$	61,875	$	1,559	$	—
Other revenues—affiliate	4,241		—		—
Total revenues	$	66,116	$	1,559	$	—

Pipeline revenues—affiliate

CCL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of natural gas feedstock to the Liquefaction Facilities. These agreements have a primary term of 20 years from April 2019 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. CCL has continuous access to its firm transportation capacity during the contract term but has no ability to defer unused capacity to future periods. CCL pays fixed fees of approximately $78 million per year to reserve the right to transport natural gas up to maximum contractually specified levels, regardless of the quantities that CCL actually transports.

Because we are continuously available to provide transportation service on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to CCL on a continuous basis over time. Because our rights to consideration correspond directly with the value of the incremental service performed, we have elected to recognize revenue when we have the right to invoice CCL for services performed to date, which results in a substantially straight-line recognition pattern over the term of the contract.

Transaction Price Allocated to Future Performance Obligations

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, 2019 and 2018:

	December 31, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
Pipeline revenues—affiliate	$	1.4	9	$	1.5	10

(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.

S-34

CHENIERE CORPUS CHRISTI PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

We omit from the table above all variable consideration expected to be recognized through our use of the right to invoice election.

NOTE 6—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Operations for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018		2017
Pipeline revenues—affiliate
Transportation Agreements	$	61,875		$	1,556	$	—
Operational Balancing Agreement	—			3		—
Total revenues—affiliate	61,875			1,559		—
Other revenues—affiliate
Transportation Agreements	4,241			—		—
Operating and maintenance expense (recovery)—affiliate
Services Agreements	7,189			3,114		70
Land Agreements	12			12		12
Operational Balancing Agreement	(8,007		)	6,189		—
Total operating and maintenance expense (recovery)—affiliate	(806		)	9,315		82
General and administrative expense—affiliate
Services Agreements	92			114		46
Other income—affiliate
Land Agreements	5			5		—

Services Agreements

We had $1.9 million and $1.7 million due to affiliates as of December 31, 2019 and 2018, respectively, under the agreements below.

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

We have an O&M Agreement with Cheniere LNG O&M Services, LLC (“O&M Services”), a wholly owned subsidiary of Cheniere, pursuant to which we receive 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. We are required to reimburse O&M Services for all operating expenses incurred on our behalf.

Management Services Agreement (“MSA”)

We have an MSA with Cheniere Energy Shared Services, Inc. (“Shared Services”), a wholly owned subsidiary of Cheniere, pursuant to which Shared Services manages our operations and business, excluding those matters provided for under the O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, preparing status reports, providing contract administration services for all contracts associated with the Corpus Christi Pipeline and obtaining insurance. We are required to reimburse Shared Services for the aggregate of all costs and expenses incurred in the course of performing the services under the MSA.

S-35

CHENIERE CORPUS CHRISTI PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Land Agreements

Lease and Right of Way Easement Agreements

We have an agreement with CCL to lease from them a portion of the Liquefaction Facilities site for the purpose of the construction and operation of a meter station to measure the amount of natural gas delivered to the Liquefaction Facilities. The annual lease payment is $12 thousand. The initial term of the lease is 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In conjunction with this lease, we also entered into a pipeline right of way easement agreement with CCL granting us the right to construct, install and operate a natural gas pipeline on the Liquefaction Facilities site.

Access Road Use License Agreement

We have an agreement with CCL which grants us a limited license to enter the access road owned by CCL for access to the Liquefaction Facilities. The annual payment for this agreement is $5 thousand, and the terms of the agreement is five years from the effective date of February 2018.

Natural Gas Transportation Agreements

CCL has a transportation precedent agreement, a firm transportation service agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of natural gas feedstock to the Liquefaction Facilities. These agreements have a primary term of 20 years from April 2019, and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. CCL pays fixed fees of approximately $78 million per year to reserve the right to transport natural gas up to maximum contractually specified levels, regardless of the quantities that CCL actually transports. Additionally, CCL reimburses us for the electric power cost that is incurred for our services, which is recorded in other revenues—affiliate. Prior to the commencement of the primary term of the agreement, CCL paid variable fees based on the volume of gas transported during the period. As of December 31, 2019 and 2018, we had $7.4 million and $1.1 million of accounts receivable—affiliate, respectively, under the transportation agreements.

Cheniere Corpus Christi Liquefaction Stage III, LLC, a wholly owned subsidiary of Cheniere, has a transportation precedent agreement with us 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.

Contract for Sale and Purchase of Natural Gas

We have an agreement with CCL that allows us to sell and purchase natural gas with CCL. Natural gas sold under this agreement is recorded as revenues—affiliate.

Operational Balancing Agreement

We have an amended Operational Balancing Agreement (“OBA”) with CCL that provides for the resolution of any operational imbalances (1) during the term of the agreement on an in-kind basis and (2) upon termination of the agreement by cash-out at a rate equivalent to the average of the midpoint prices for East Texas—Houston Ship Channel pricing published in Platts’ “Gas Daily Price Guide - Final Daily Price Survey” for each day of the month following termination. As of December 31, 2019 and 2018, we had $1.8 million in operational balancing assets—affiliate and $6.2 million in operational balancing liabilities—affiliate, respectively, under the amended OBA.

State Tax Sharing Agreement

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

S-36

CHENIERE CORPUS CHRISTI PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 7—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2019, are not recognized as liabilities but require disclosures in our Financial Statements.

Services Agreements

We have certain services agreements with affiliates. See Note 6—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere.  See Note 6—Related Party Transactions for information regarding this agreement.

Obligations under Guarantee Contract

The subsidiaries of CCH, including us, have jointly and severally guaranteed the debt obligations of CCH. See Note 9—Guarantees and Collaterization for information regarding these guarantees.

Other Commitments

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.

Environmental and Regulatory Matters

The Corpus Christi Pipeline 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. In the opinion of management, as of December 31, 2019, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

NOTE 8—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2019		2018		2017
Non-cash capital contribution for conveyance of property, plant and equipment from affiliate	$	—	$	758	$	—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $0.7 million, $10.4 million and $28.5 million as of December 31, 2019, 2018 and 2017, respectively.

S-37

CHENIERE CORPUS CHRISTI PIPELINE, L.P.  

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 9—GUARANTEES AND COLLATERIZATION

The subsidiaries of CCH, including us, have jointly and severally guaranteed and collaterized the debt obligations of CCH, including: (1) $1.25 billion of the 7.000% Senior Secured Notes due 2024, (2) $1.5 billion of the 5.875% Senior Secured Notes due 2025, (3) $1.5 billion of the 5.125% Senior Secured Notes due 2027, (4) $727 million of the 4.80% Senior Secured Notes due 2039, (5) $475 million of the 3.925% Senior Secured Notes due 2039, (6) $1.5 billion of the 3.700% Senior Secured Notes due 2029, (7) a term loan facility of which CCH had no available commitments and approximately $3.3 billion of outstanding borrowings as of December 31, 2019 and (8) a $1.2 billion working capital facility of which CCH had $729.2 million of available commitments and no outstanding borrowings as of December 31, 2019. CCH entered into the above debt instruments and its use is solely to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project and related business purposes. As of December 31, 2019, we had no liability recorded related to these guarantees.

S-38

Corpus Christi Pipeline GP, LLC

Financial Statements

As of December 31, 2019 and 2018

and for the years ended December 31, 2019, 2018 and 2017

S-39

CORPUS CHRISTI PIPELINE GP, LLC

FINANCIAL STATEMENTS

DEFINITIONS

As used in these Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms

GAAP	generally accepted accounting principles in the United States
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
SEC	U.S. Securities and Exchange Commission
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2019 and the references to these entities used in these Financial Statements:

Unless the context requires otherwise, references to “CCP GP,” “the Company,” “we,” “us,” and “our” refer to Corpus Christi Pipeline GP, LLC.

S-40

Independent Auditors’ Report

To the Member and Managers of

Corpus Christi Pipeline GP, LLC:

We have audited the accompanying financial statements of Corpus Christi Pipeline GP, LLC (the Company), which comprise the balance sheets as of December 31, 2019 and 2018, and the related statements of operations, member’s equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Corpus Christi Pipeline GP, LLC as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in Note 2 to the financial statements, in 2019, 2018, and 2017, the Company adopted new accounting guidance ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. Our opinion is not modified with respect to this matter.

/s/    KPMG LLP

KPMG LLP

Houston, Texas

February 24, 2020

S-41

CORPUS CHRISTI PIPELINE GP, LLC

BALANCE SHEETS

	December 31,
	2019			2018
ASSETS
Cash and cash equivalents	$	—		$	—
Restricted cash	—			—
Investment in affiliate	1,000			1,000
Total assets	$	1,000		$	1,000
LIABILITIES AND MEMBER’S DEFICIT
Accrued liabilities	$	10,000		$	10,000
Total current liabilities	10,000			10,000
Commitments and contingencies (see Note 3)
Member’s deficit	(9,000		)	(9,000		)
Total liabilities and member’s deficit	$	1,000		$	1,000

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

S-42

CORPUS CHRISTI PIPELINE GP, LLC

STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2019			2018			2017
Revenues	$	—		$	—		$	—
General and administrative expense	10,350			15,594			5,585
Net loss	$	(10,350	)	$	(15,594	)	$	(5,585	)

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

S-43

CORPUS CHRISTI PIPELINE GP, LLC

STATEMENTS OF MEMBER'S EQUITY (DEFICIT)

	Cheniere Corpus Christi Holdings, LLC			Total Member’s Equity
Balance at December 31, 2016	$	1,000		$	1,000
Capital contributions	5,585			5,585
Net loss	(5,585		)	(5,585		)
Balance at December 31, 2017	1,000			1,000
Capital contributions	5,594			5,594
Net loss	(15,594		)	(15,594		)
Balance at December 31, 2018	(9,000		)	(9,000		)
Capital contributions	10,350			10,350
Net loss	(10,350		)	(10,350		)
Balance at December 31, 2019	$	(9,000	)	$	(9,000	)

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

S-44

CORPUS CHRISTI PIPELINE GP, LLC

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities
Net loss	$	(10,350	)	$	(15,594	)	$	(5,585	)
Changes in operating assets and liabilities:
Accrued liabilities	—			10,000			—
Net cash used in operating activities	(10,350		)	(5,594		)	(5,585		)
Cash flows from investing activities	—			—			—
Cash flows from financing activities
Capital contributions	10,350			5,594			5,585
Net increase (decrease) in cash, cash equivalents and restricted cash	—			—			—
Cash, cash equivalents and restricted cash—beginning of period	—			—			—
Cash, cash equivalents and restricted cash—end of period	$	—		$	—		$	—

Balances per Balance Sheets:

	December 31,
	2019		2018
Cash and cash equivalents	$	—	$	—
Restricted cash	—		—
Total cash, cash equivalents and restricted cash	$	—	$	—

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

S-45

CORPUS CHRISTI PIPELINE GP, LLC

NOTES TO FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF BUSINESS

CCP GP is a Houston-based Delaware limited liability company formed in September 2014 by CCH, which is a wholly owned subsidiary of Cheniere. Cheniere contributed CCP to us in November 2014. CCP owns and operates a 23-mile natural gas supply pipeline (the “Corpus Christi Pipeline”) that interconnects the natural gas liquefaction and export facility at the Corpus Christi LNG terminal being operated and constructed by CCL (the “Liquefaction Facilities” and together with the Corpus Christi Pipeline, the “Liquefaction Project”) with several interstate and intrastate natural gas pipelines. CCL is currently operating two Trains and is constructing one additional Train for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain three LNG storage tanks and two marine berths.

Our only business consists of owning and holding CCP’s general partner interest. As the sole general partner, we have complete responsibility and discretion in the day-to-day management of CCP. Since we control but have only a non-economic interest in CCP, we have determined that CCP is a variable interest entity. As we are not the primary beneficiary of CCP, we do not consolidate CCP into our Financial Statements. We have no indebtedness, although we do guarantee certain debt of our immediate parent, CCH, and we do not have any publicly traded equity. Our operations is funded through contributions received from our parent, CCH.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements have been prepared in accordance with GAAP.

Recent Accounting Standards

In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The new guidance retrospectively eliminates the requirement to allocate the consolidated amount of current and deferred tax expense to entities that are not subject to income tax such as us, as further described under Income Taxes in this note. We early adopted this guidance effective December 31, 2019 and the provision for income taxes, taxes payable and deferred income tax balances have been retrospectively removed from our Financial Statements. The deferred tax assets were offset with a full valuation allowance and therefore no cumulative effect adjustment to retained earnings was required on our Financial Statements.

Use of Estimates

The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the recoverability of investment in affiliate. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Cash, Cash Equivalents and Restricted Cash

We did not have any cash and cash equivalents or restricted cash as of December 31, 2019. Our operations are funded through contributions from CCH.

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 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 Financial Statements.

S-46

CORPUS CHRISTI PIPELINE GP, LLC 

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 3—COMMITMENTS AND CONTINGENCIES

As the sole general partner, we have complete responsibility and discretion in the day-to-day management of CCP. As a result, we may be subject to legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

NOTE 4—GUARANTEES AND COLLATERIZATION

The subsidiaries of CCH, including us, have jointly and severally guaranteed and collaterized the debt obligations of CCH, including: (1) $1.25 billion of the 7.000% Senior Secured Notes due 2024, (2) $1.5 billion of the 5.875% Senior Secured Notes due 2025, (3) $1.5 billion of the 5.125% Senior Secured Notes due 2027, (4) $727 million of the 4.80% Senior Secured Notes due 2039, (5) $475 million of the 3.925% Senior Secured Notes due 2039, (6) $1.5 billion of the 3.700% Senior Secured Notes due 2029, (7) a term loan facility of which CCH had no available commitments and approximately $3.3 billion of outstanding borrowings as of December 31, 2019 and (8) a $1.2 billion working capital facility of which CCH had $729.2 million of available commitments and no outstanding borrowings as of December 31, 2019. CCH entered into the above debt instruments and its use is solely to fund a portion of the costs associated with the development, construction, operation and maintenance of the Liquefaction Project and related business purposes. As of December 31, 2019, we had no liability recorded related to these guarantees.

S-47

EX-10.18

Exhibit 10.18

[***] indicates certain identified information has been excluded because it is both (a) not material and (b) would be competitively harmful if publicly disclosed.

CHANGE ORDER

Aircraft Warning Lights

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: 00019 DATE OF CHANGE ORDER: Sep 23, 2019

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Pursuant to Article 6.1 of the Agreement (Change Orders Requested by Owner), Parties agree this Change Order includes Contractor’s cost for changes to the Train 3 aircraft warning lights.

A total of six (6) aircraft warning lights on two (2) GT exhaust stacks (23Z-1411 and 23Z-1621 (3 per stack)), shall be changed to operate (white (day use) /red (night use)) from previous basis (white (day use) / white (night use)).

2. The summary cost breakdown for this Change Order is detailed in Exhibit 1 of this Change Order.

3. The detailed cost breakdown of this Change Order is provided in Exhibit 3 of this Change Order.

4. Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (00001-00018)...............................................................	$	26,202,435
The Contract Price prior to this Change Order was...........................................................................................	$	2,386,202,435
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Contract Price including this Change Order will be...........................................................................	$	2,386,268,002

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00018)...............................................................	$	[***]
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	[***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	[***]

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00018)...............................................................	$	[***]
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Aggregate Labor and Skills Price including this Change Order will be.............................................	$	[***]

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (00001-00018)...............................................................	$	(18,272,757	)
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	277,277,149
The Aggregate Provisional Sum will be changed by this Change Order in the amount of...............................	$	—
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	277,277,149

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement:

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Bhupesh Thakkar
Owner	Contractor
David Craft	Bhupesh Thakkar
Name	Name
SVP, E&C	Program Manager, Cheniere Projects
Title	Title
October 10, 2019	September 23, 2019
Date of Signing	Date of Signing

CHANGE ORDER

Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD) Q2_2019

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: 00020 DATE OF CHANGE ORDER: October 8, 2019

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Pursuant to Article 6 of the Agreement, Parties agree this Change Order includes impacts from Section 232 Tariffs on Steel and Aluminum on Applicable Law, and Change in Law impacts imposing Anti-dumping (ADA) and Countervailing Duties (CVD) on specific steel and aluminum imports, which are based on the following two (2) approved Trends:

i. Trend No. S2-0005c - Impacts of Policy Change/Applicable Law Imposing Tariff on Steel and Aluminum (Section 232); and

ii. Trend No. S2-0006c - Anti-Dumping and Countervailing Duties (ADA/CVD).

2. This Change Order includes the costs during the 2nd Quarter of 2019, and excludes all costs, cost impacts, or effects of the change associated with these trends beyond these dates. Any subsequent costs, cost impacts, or effects of the change associated with these trends beyond these dates will be assessed on a quarterly basis and included in separate, future Change Order(s).

3. The summary cost breakdown for the scope of this Change Order is detailed in Exhibit 1 of this Change Order.

4. The detailed cost breakdown for the scope of this Change Order is detailed in Exhibit 3 (Trend No. S2-0005c) and Exhibit 4 (Trend No. S2-0006c).

5. The detailed costs for Customs Entry for the scope of this Change Order is detailed in Exhibit 5 (Trend No. S2-0005c) and Exhibit 6 (Trend No. S2-0006c).

6. Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (00001-00019)...............................................................	$	26,268,002
The Contract Price prior to this Change Order was...........................................................................................	$	2,386,268,002
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Contract Price including this Change Order will be...........................................................................	$	2,389,688,411

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00019)...............................................................	$	[***]
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	[***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	[***]

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00019)...............................................................	$	[***]
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Aggregate Labor and Skills Price including this Change Order will be.............................................	$	[***]

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (00001-00019)...............................................................	$	(18,272,757	)
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	277,277,149
The Aggregate Provisional Sum will be changed by this Change Order in the amount of...............................	$	—
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	277,277,149

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement:

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Bhupesh Thakkar
Owner	For Contractor
David Craft	Bhupesh Thakkar
Name	Name
SVP, E&C	SVP, Program Manager
Title	Title
October 11, 2019	October 8, 2019
Date of Signing	Date of Signing

CHANGE ORDER

Spare Transition Joints for Potential Future Cold Box Modifications

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: 00021 DATE OF CHANGE ORDER: October 8, 2019

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Pursuant to Article 6 of the Agreement, Parties agree this Change Order includes the cost of engineering and sourcing of spare transition joints for potential future Train 3 cold box modifications. Per this Change Order, a total of seven (7) transition joints: five (5) for Methane Cold Box and two (2) for Ethylene Cold Box - 1504A/B shall be procured and made available at Site should Owner elect to proceed with the field modification of the Train 3 cold boxes to implement the modified design to reduce the number of transition joints.

2. The summary cost breakdown for the total Scope of Work of this Change Order is detailed in Exhibit 1 of this Change Order.

3. The detailed cost breakdown for the Scope of Work of this Change Order is provided in Exhibit 3 of this Change Order.

4. Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (00001-00020)...............................................................	$	29,688,411
The Contract Price prior to this Change Order was...........................................................................................	$	2,389,688,411
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Contract Price including this Change Order will be...........................................................................	$	2,389,888,443

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00020)...............................................................	$	[***]
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	[***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	[***]

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00020)...............................................................	$	[***]
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Aggregate Labor and Skills Price including this Change Order will be.............................................	$	[***]

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (00001-00020)...............................................................	$	(18,272,757	)
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	277,277,149
The Aggregate Provisional Sum will be changed by this Change Order in the amount of...............................	$	—
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	277,277,149

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement:

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Bhupesh Thakkar
Owner	For Contractor
David Craft	Bhupesh Thakkar
Name	Name
SVP, E&C	SVP, Program Manager
Title	Title
October 11, 2019	October 8, 2019
Date of Signing	Date of Signing

CHANGE ORDER

Modification of the Train 3 Methane Cold Box

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: 00022 DATE OF CHANGE ORDER: December 6, 2019

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Pursuant to Article 6.1 of the Agreement (Change Orders Requested by Owner), Parties agree this Change Order sets forth the scope of work to perform modifications to the Train 3 Methane Cold Box (E-1605) as described in more detail in Exhibit 4 of this Change Order (“Cold Box Modification Scope of Work”). Other than Contractor’s costs and expenses pertaining only to the additional Work described in Exhibit 4 for the Cold Box Modification Scope of Work, this Change Order does not set forth the effect, if any, of the Cold Box Modifications Scope of Work on the Changed Criteria. For example, impacts on Project Schedule (such as delays associated with potential damage to the core of the exchanger or other long lead items) and any costs incurred by Contractor arising from such impacts are not covered in this Change Order. If any such impacts occur, then the effects, if any, will be addressed by Owner and Contractor.

2. As further described in Exhibit 4 of this Change Order, Contractor shall reduce the number of transition joints (“TJs”) inside the methane cold box (E-1605) by replacing stainless steel pipe with aluminum and relocating TJs outside of the cold box. The design will have five (5) TJs on the exterior of the cold box in lieu of sixteen (16) TJs inside (original design basis). The Cold Box Modification Scope of Work includes the following activities: scaffolding, rigging, temporary supports, cutting of the cold box roof/walls, opening manways, cutting pipe, welding, testing and closing of the methane cold box (E1605).

3. The summary cost breakdown for the Scope of Work of this Change Order is provided in Exhibit 1 of this Change Order.

4. The detailed cost breakdown for the Scope of Work of this Change Order is provided in Exhibit 3 of this Change Order.

5. Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (00001-00021)...............................................................	$	29,888,443
The Contract Price prior to this Change Order was...........................................................................................	$	2,389,888,443
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Contract Price including this Change Order will be...........................................................................	$	2,395,637,222

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00021)...............................................................	$	[***]
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	[***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	[***]

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00021)...............................................................	$	[***]
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Aggregate Labor and Skills Price including this Change Order will be.............................................	$	[***]

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (00001-00021)...............................................................	$	(18,272,757	)
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	277,277,149
The Aggregate Provisional Sum will be changed by this Change Order in the amount of...............................	$	—
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	277,277,149

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes, see Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: Yes, see Exhibit 4 for the Scope of Work

Other adjustments to liability or obligation of Contractor or Owner under the Agreement:

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Bhupesh Thakkar
Owner	For Contractor
David Craft	Bhupesh Thakkar
Name	Name
SVP, E&C	Program Manager
Title	Title
December 20, 2019	December 9, 2019
Date of Signing	Date of Signing

CHANGE ORDER

Section 232 Steel and Aluminum Tariffs & Anti-dumping (ADA) and Countervailing Duties (CVD) Q3_2019

PROJECT NAME:  Corpus Christi Stage 2 Liquefaction Facility OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: December 12, 2017 CHANGE ORDER NUMBER: 00023 DATE OF CHANGE ORDER: December 10, 2019

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Pursuant to Article 6 of the Agreement, Parties agree this Change Order includes impacts from Section 232 Tariffs on Steel and Aluminum on Applicable Law, and Change in Law impacts imposing Anti-dumping (ADA) and Countervailing Duties (CVD) on specific steel and aluminum imports, which are based on the following two (2) approved Trends:

i. Trend No. S2-0005d - Impacts of Policy Change/Applicable Law Imposing Tariff on Steel and Aluminum (Section 232); and

ii. Trend No. S2-0006d - Anti-Dumping and Countervailing Duties (ADA/CVD).

2. This Change Order includes the costs during the 3rd Quarter of 2019, and excludes all costs, cost impacts, or effects of the change associated with these trends beyond these dates. Any subsequent costs, cost impacts, or effects of the change associated with these trends beyond these dates will be assessed on a quarterly basis and included in separate, future Change Order(s).

3. The summary cost breakdown for the scope of this Change Order is detailed in Exhibit 1 of this Change Order.

4. The detailed cost breakdown for the scope of this Change Order is detailed in Exhibit 3 (Trend No. S2-0005d) and Exhibit 4 (Trend No. S2-0006d).

5. The detailed costs for Customs Entry for the scope of this Change Order is detailed in Exhibit 5 (Trend No. S2-0005d) and Exhibit 6 (Trend No. S2-0006d).

6. Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

Adjustment to Contract Price

The original Contract Price was.........................................................................................................................	$	2,360,000,000
Net change by previously authorized Change Orders (00001-00022)...............................................................	$	35,637,222
The Contract Price prior to this Change Order was...........................................................................................	$	2,395,637,222
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Contract Price including this Change Order will be...........................................................................	$	2,395,690,192

Adjustment to Aggregate Equipment Price

The original Aggregate Equipment Price was...................................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00022)...............................................................	$	[***]
The Aggregate Equipment Price prior to this Change Order was......................................................................	$	[***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of...............................	$	[***]
The new Aggregate Equipment Price including this Change Order will be .....................................................	$	[***]

Adjustment to Aggregate Labor and Skills Price

The original Aggregate Labor and Skills Price was..........................................................................................	$	[***]
Net change by previously authorized Change Orders (00001-00022)...............................................................	$	[***]
The Aggregate Labor and Skills Price prior to this Change Order was.............................................................	$	[***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of......................	$	[***]
The new Aggregate Labor and Skills Price including this Change Order will be.............................................	$	[***]

Adjustment to Aggregate Provisional Sum

The original Aggregate Provisional Sum was....................................................................................................	$	295,549,906
Net change by previously authorized Change Orders (00001-00022)...............................................................	$	(18,272,757	)
The Aggregate Provisional Sum prior to this Change Order was......................................................................	$	277,277,149
The Aggregate Provisional Sum will be changed by this Change Order in the amount of...............................	$	—
The new Aggregate Provisional Sum including this Change Order will be......................................................	$	277,277,149

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement:

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Bhupesh Thakkar
Owner	For Contractor
David Craft	Bhupesh Thakkar
Name	Name
SVP, E&C	Program Manager
Title	Title
December 18, 2019	December 11, 2019
Date of Signing	Date of Signing

EX-10.34

Exhibit 10.34

LNG SALE AND PURCHASE AGREEMENT

(EOG EARLY IPM)

Dated December 30, 2019

BETWEEN

CORPUS CHRISTI LIQUEFACTION, LLC

(Seller)

AND

CHENIERE MARKETING INTERNATIONAL LLP

(Buyer)

Table of Contents

Page No.

1.	Definitions and Interpretation		1
	1.1	Definitions	1
	1.2	Interpretation	15
	1.3	Non-Publication Events	16
	1.4	Errant Price	17
2.	Approvals		17
3.	Subject Matter		18
	3.1	Sale and Purchase	18
	3.2	Facilities	18
	3.3	Destination	18
4.	Term		18
	4.1	Term	18
	4.2	Contract Year	19
5.	Quantities		19
	5.1	ACQ	19
	5.2	Adjusted Annual Contract Quantity	20
	5.3	Major Scheduled Maintenance	20
	5.4	Buyer’s Purchase Obligation	20
	5.5	Seller’s Delivery Obligation	21
	5.6	Cargo Cancellation; Buyer Override	22
6.	Delivery Point, Title and Risk		23
	6.1	Delivery Point	23
	6.2	Title and Risk	23
7.	Transportation and Loading		23
	7.1	Transportation by Buyer	23
	7.2	Corpus Christi Facility	23
	7.3	Compatibility of the LNG Facility with LNG Tankers	25
	7.4	Buyer Inspection Rights in Respect of the Corpus Christi Facility	25
	7.5	LNG Tankers	26
	7.6	LNG Tanker Inspections; LNG Tanker Vetting Procedures; Right to Reject LNG Tanker	29
	7.7	Port Liability Agreement	30
	7.8	Marine Operations Manual	31
	7.9	Loading of LNG Tankers	32
	7.1	Notice of Readiness	33
	7.11	Berthing Assignment	34
	7.12	Berth Laytime	35
	7.13	LNG Transfers at the Loading Facility	37
	7.14	LNG Tanker Not Ready for LNG Transfer; Excess Laytime	37
	7.15	Cooperation	39
	7.16	Cool-Down of LNG Tankers	39
8.	Annual Delivery Program		40
	8.1	Programming Information	40

i

	8.2	Determination of Annual Delivery Program	42
	8.3	Changes to Annual Delivery Program	42
	8.4	Ninety Day Schedule	43
9.	Contract Sales Price		44
	9.1	Contract Sales Price	44
10.	Invoicing and Payment		45
	10.1	Invoices	45
	10.2	Payment	46
	10.3	Disputed Invoice	47
	10.4	Delay in Payment	48
	10.5	Audit Rights	48
	10.6	Seller’s Right to Suspend Performance	49
	10.7	Final Settlement	50
11.	Taxes		50
	11.1	Responsibility	50
	11.2	Seller Taxes	50
	11.3	Buyer Taxes	50
	11.4	Withholding Taxes	51
	11.5	Transfer Tax	51
	11.6	Mitigation	52
	11.7	Refunds	52
12.	Quality		52
	12.1	Specification	52
	12.2	Determining LNG Specifications	53
	12.3	Off-Specification LNG	53
13.	Measurements and Tests		55
	13.1	LNG Measurement and Tests	55
	13.2	Parties to Supply Devices	55
	13.3	Selection of Devices	56
	13.4	Tank Gauge Tables of LNG Tanker	56
	13.5	Gauging and Measuring LNG Volumes Loaded	56
	13.6	Samples for Quality Analysis	56
	13.7	Quality Analysis	56
	13.8	Operating Procedures	56
	13.9	MMBtu Quantity Delivered	57
	13.1	Verification of Accuracy and Correction for Error	57
	13.11	Costs and Expenses	57
14.	Force Majeure		58
	14.1	Force Majeure	58
	14.2	Limitations on Force Majeure	59
	14.3	Notification	61
	14.4	Measures	61
	14.5	No Extension of Term	61
	14.6	Settlement of Industrial Disturbances	61
	14.7	Foundation Customer Priority	62
15.	Liabilities and Indemnification		62

ii

	15.1	General	62
	15.2	Limitations on Liability	62
	15.3	Third Party Liability	64
	15.4	Seller’s Insurance	65
	15.5	Buyer’s Insurance	66
16.	Safety		66
	16.1	General	66
	16.2	Third Parties	66
17.	Representations, Warranties and Undertakings		67
	17.1	Representations and Warranties of Buyer	67
	17.2	Representations and Warranties of Seller	67
	17.3	Business Practices	68
18.	Exchange of Information		68
19.	Confidentiality		68
	19.1	Duty of Confidentiality	68
	19.2	Permitted Disclosures	68
	19.3	Duration of Confidentiality	70
20.	Default and Termination		70
	20.1	Termination Events	70
	20.2	Termination	72
	20.3	Survival	73
21.	Dispute Resolution and Governing Law		73
	21.1	Dispute Resolution	73
	21.2	Expert Determination	76
	21.3	Governing Law	77
	21.4	Immunity	77
22.	Assignments		78
	22.1	Merger, Consolidation	78
	22.2	Assignment by Buyer	78
	22.3	Assignments by Seller	78
	22.4	Financing by Seller or its Affiliates	79
23.	Contract Language		80
24.	Miscellaneous		80
	24.1	Disclaimer of Agency	80
	24.2	Entire Agreement	80
	24.3	Third Party Beneficiaries	80
	24.4	Amendments and Waiver	80
	24.5	Exclusion	81
	24.6	Further Assurances	81
	24.7	Severability	81
	24.8	Multiple SPAs	81
	24.9	Safe Harbor Provisions	83
25.	Notices		84
	25.1	Form of Notice	84
	25.2	Effective Time of Notice	85
26.	Business Practices		85

iii

	26.1	Trade Law Compliance.	85
	26.2	Use of LNG	87
	26.3	Prohibited Practices	87
	26.4	Records; Audit	88
	26.5	Indemnity	88
Exhibit A		Measurements
Exhibit B		Form of Port Liability Agreement

iv

LNG SALE AND PURCHASE AGREEMENT

THIS LNG SALE AND PURCHASE AGREEMENT (“Agreement”) is made and entered into as of December 30, 2019 (the “Effective Date”), by and between Corpus Christi Liquefaction, LLC, a Delaware limited liability company whose principal place of business is located at 700 Milam St., Suite 1900, Houston, TX 77002 (“Seller”), and Cheniere Marketing International LLP, a UK limited liability partnership whose principal place of business is located at Berkeley Square House, Fifth Floor, Berkeley Square, London W1J 6BY (United Kingdom) (“Buyer”). Buyer and Seller are each referred to herein as a “Party” and collectively as the “Parties”.

Recitals

(1) Seller and its Affiliates are developing, constructing and operating the Corpus Christi Facility;

(2) Seller and EOG Resources, Inc. (“EOG”) entered into a Gas Supply Agreement (Early Volumes), dated September 12, 2019, pursuant to which EOG will sell and Seller will purchase a specified quantity of Gas starting from January 1, 2020 (as may be supplemented, amended, modified, changed, superseded or replaced from time to time, the “GSA”);

(3) Buyer desires to purchase LNG from Seller and transport such LNG to one or more Discharge Terminals; and

(4) Seller and Buyer have agreed to execute a definitive agreement setting out the Parties’ respective rights and obligations in relation to the sale and purchase of LNG.

It is agreed:

1. Definitions and Interpretation

1.1 Definitions

The words and expressions below shall, unless the context otherwise requires, have the meanings respectively assigned to them:

AAA: as defined in Section 21.1.2;

ACQ: as defined in Section 5.1.1;

Actual Laytime: as defined in Section 7.12.2;

Adjusted Annual Contract Quantity

or AACQ: as defined in Section 5.2;

Adverse Weather Conditions: weather or sea conditions actually experienced at or near the Corpus Christi Facility (or alternate source, as applicable) that are sufficiently severe: (i) to prevent

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an LNG Tanker from proceeding to berth, or loading or departing from berth, in accordance with one or more of the following: (a) regulations published by a Governmental Authority; (b) an Approval; or (c) an order of a Pilot; (ii) to cause an actual determination by the master of an LNG Tanker, acting reasonably, that it is unsafe for such LNG Tanker to berth, load, or depart from berth; or (iii) to prevent or severely limit the production capability of the Corpus Christi Facility (or alternate source, as applicable);

Affected Quantity: a quantity of MMBtus equal to the quantity of Gas affected by the relevant GSA Event, divided by one hundred fifteen percent (115%);

Affiliate: with respect to any Person, any other Person which directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with such Person; provided that Buyer and Seller shall not be considered Affiliates of one another for purposes of this Agreement; provided further that if Seller, directly or indirectly through one or more intermediaries, is under common control with Buyer, then for purposes of Section 11 only, the term “Affiliate” shall mean (i) in the case of Seller, any Person that directly or indirectly through one or more intermediaries is controlled by Seller, and (ii) in the case of Buyer, any Person that directly owns an equity interest in Buyer or directly or indirectly through one or more intermediaries is controlled by Buyer or is under common control with Buyer (other than Seller and Seller’s Affiliates as set forth in clause (i) of this definition); for purposes of this definition, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”) means the direct or indirect ownership of fifty percent (50%) or more of the voting rights in a Person or the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities or otherwise;

Agreement: this agreement, including the Exhibits hereto, as the same may be amended, modified or replaced from time to time;

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Allotted Laytime: as defined in Section 7.12.1;

Alternative CSP: as defined in Section 9.1.1;

Alternative Quantity: as defined in Section 9.1.3;

Annual Delivery Program or ADP: as defined in Section 8.2.3;

Applicable Laws: in relation to matters covered by this Agreement, all applicable laws, statutes, rules, regulations, ordinances, codes, standards and rules of common law, and judgments, decisions, interpretations, orders, directives, injunctions, writs, decrees, stipulations, or awards of any applicable Governmental Authority or duly authorized official, court or arbitrator thereof, in each case, now existing or which may be enacted or issued after the Effective Date;

Approvals: any and all permits (including work permits), franchises, authorizations, approvals, grants, licenses, visas, waivers, exemptions, consents, permissions, registrations, decrees, privileges, variances, validations, confirmations or orders granted by or filed with any Governmental Authority, including the Export Authorizations;

AQ: in respect of a cargo, a quantity of MMBtus equal to: (a) if Buyer has elected to purchase the relevant cargo at the alternative price in accordance with Section 5.6, DSCQ; or (b) if sub-part (a) does not apply, the Alternative Quantity applicable to such cargo;

Bankruptcy Code: Title 11 of the United States Code (11 U.S.C. § 101 et. seq.);

Bankruptcy Event: with respect to any Person: (i) such Person’s suspension of payment of, or request to any court for a moratorium on payment of, all or a substantial part of such Person’s debts, (ii) such Person’s making of a general assignment or any composition with or for the benefit of its creditors except to the extent otherwise permitted by Section 22, (iii) any filing, or consent by answer by such Person to the filing against it, of a petition for relief or reorganization or arrangement or any other petition in bankruptcy, for liquidation or to take advantage of any bankruptcy, insolvency,

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reorganization, moratorium or other similar law of any jurisdiction, or (iv) any order under the bankruptcy or insolvency laws of any jurisdiction: (a) entered for the winding up, bankruptcy, liquidation, dissolution, custodianship or administration with respect to such Person or any substantial part of such Person’s property; (b) constituting an order for relief with respect to such Person; (c) approving a petition for relief or reorganization or any other petition in bankruptcy or insolvency law with respect to such Person; or (d) approving any petition filed in bankruptcy or insolvency law against such Person;

Btu: the amount of heat equal to one thousand fifty-five decimal zero five six (1,055.056) Joules;

Business Day: any Day (other than Saturdays, Sundays and national holidays in the United States of America) on which commercial banks are normally open to conduct business in the United States of America;

Buyer: as defined in the Preamble;

Buyer Taxes: as defined in Section 11.3;

Cargo DoP Payment: as defined in Section 5.5.2;

Cargo DoP Quantity: as defined in Section 5.5.2;

Cargo Payment: as defined in Section 9.1.1;

Central Time: the time of the sixth time zone west of Greenwich that includes the central United States of America;

Claim: all claims, demands, legal proceedings, or actions that may exist, arise, or be threatened currently or in the future at any time following the Effective Date, whether or not of a type contemplated by any Party, and whether based on federal, state, local, statutory or common law or any other Applicable Law;

CMILLP Base SPA: that certain Amended and Restated Base LNG Sale and Purchase Agreement, dated November 28, 2014, between Corpus Christi Liquefaction, LLC and Cheniere Marketing International LLP, as amended, and any other LNG sale and purchase agreement

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entered into between Corpus Christi Liquefaction, LLC and Cheniere Marketing International LLP after the Effective Date;

Confidential Information: as defined in Section 19.1;

Connecting Pipeline: any pipeline as may be directly interconnected to the Corpus Christi Facility, including the Corpus Christi Pipeline, or to an alternate LNG supply source (as applicable);

Contract Year: as defined in Section 4.2;

Corpus Christi Facility: the facilities that Seller and/or its Affiliates are developing and constructing and own and operate (or will have operated on their behalf) in the vicinity of Portland, Texas, on the La Quinta Channel in the Corpus Christi Bay, including the Gas pretreatment and processing facilities, liquefaction facilities, storage tanks, utilities, terminal facilities, and associated port and marine facilities, and all other related facilities both inside and outside the LNG plant, including any expansions or modifications made thereto;

Corpus Christi Marine Operations

Manual: as defined in Section 7.8;

Corpus Christi Pipeline: that certain Gas pipeline owned and operated, as of the Effective Date, by Cheniere Corpus Christi Pipeline, L.P., which interconnects the Corpus Christi Facility with interstate and intrastate Gas pipelines in Texas;

Cubic Meter: in relation to Gas, the quantity of dry ideal Gas, at a temperature of fifteen (15) degrees Celsius and a pressure of one hundred one decimal three two five (101.325) kilopascals absolute contained in a volume of one (1) cubic meter;

Day: a period of twenty-four (24) consecutive hours starting at 00:00 hours Central Time;

Delivery Month: the Month in which the relevant cargo’s Delivery Window is scheduled to begin;

Delivery Point: as defined in Section 6.1;

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Delivery Window: a twenty-four (24) hour period starting at 6:00 a.m. Central Time on a specified Day and ending twenty-four (24) consecutive hours thereafter that is allocated to Buyer under the ADP or Ninety Day Schedule, as applicable;

Demurrage Event: as defined in Section 7.12.3;

Direct Agreement: as defined in Section 22.4.2;

Discharge Terminal: with respect to each cargo of LNG taken or scheduled to be taken by Buyer pursuant to this Agreement, the facilities intended by Buyer to be utilized for the unloading, reception, discharge, storage, treatment (if necessary), and regasification of the LNG and the processing and send-out of Gas or regasified LNG, and other relevant infrastructure, including associated port and marine facilities for the safe passage to berth of LNG Tankers, terminal facilities for the berthing and discharging of LNG Tankers, LNG storage tanks and the regasification plant as specified in the ADP or Ninety Day Schedule, as applicable;

Dispute: any dispute or difference of whatsoever nature arising under, out of, in connection with or in relation (in any manner whatsoever) to this Agreement or the subject matter of this Agreement, including (a) any dispute or difference concerning the initial or continuing existence of this Agreement or any provision of it, or as to whether this Agreement or any provision of it is invalid, illegal or unenforceable (whether initially or otherwise); or (b) any dispute or claim which is ancillary or connected, in each case in any manner whatsoever, to the foregoing;

DQ: in respect of a cargo, DSCQ minus the quantity of MMBtus taken by Buyer in respect of such cargo; provided that DQ shall be no less than zero (0);

DSCQ: three million seven hundred two thousand eight hundred ninety-nine (3,702,899) MMBtus;

Effective Date: as defined in the Preamble;

EOG: as defined in the Recitals;

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EQ: in respect of a cargo, the quantity of MMBtus taken by Buyer in respect of such cargo minus DSCQ; provided that EQ shall never be less than zero (0);

ETA: with respect to an LNG Tanker, the estimated time of arrival of such LNG Tanker at the PBS;

Expert: a Person agreed upon or appointed in accordance with Section 21.2.1;

Export Authorizations: the FTA Export Authorization and the Non-FTA Export Authorization, either individually or together (as the context requires);

Final Contract Year: as defined in Section 4.2(b);

First Contract Year: as defined in Section 4.2(a);

Force Majeure: as defined in Section 14.1;

Foundation Customer: any customer of Seller that enters into an LNG purchase agreement with an annual contract quantity of no less than zero decimal seven (0.7) million metric tonnes per annum of LNG on a firm basis from the Corpus Christi Facility, with a minimum term of twenty (20) years. Buyer acknowledges and agrees that it is not a Foundation Customer for purposes of this Agreement;

Foundation Customer Priority: as defined in Section 14.7;

FTA Export Authorization: DOE/FE Order No. 3164 issued October 16, 2012 in FE Docket No. 12-99-LNG from the Office of Fossil Energy of the U.S. Department of Energy granting to Seller or an Affiliate of Seller the long-term authorization to export at least the volume per annum of LNG sold and delivered pursuant to this Agreement by vessel from the Corpus Christi Facility to countries that have entered into a free trade agreement with the United States of America requiring the national treatment for trade in natural gas, for a specific term, as the same may be supplemented, amended, modified, changed, superseded or replaced from time to time;

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Gas: any hydrocarbon or mixture of hydrocarbons consisting predominantly of methane that is in a gaseous state;

Governmental Authority: any national, regional, state, or local government, or any subdivision, agency, commission or authority thereof (including any maritime authorities, port authority or any quasi-governmental agency), having jurisdiction over a Party (or any Affiliate or direct or indirect owner thereof), a Connecting Pipeline, Gas in a Connecting Pipeline or the Corpus Christi Facility (or alternate source, as applicable), the Corpus Christi Facility (or alternate source, as applicable), LNG in the Corpus Christi Facility (or alternate source, as applicable), an LNG Tanker, a Transporter, the last disembarkation port of an LNG Tanker, a Discharge Terminal, or any Gas pipeline which interconnects with a Connecting Pipeline and which transports Gas to or from a Connecting Pipeline, as the case may be, and acting within its legal authority;

Gross Heating Value: the quantity of heat expressed in Btu produced by the complete combustion in air of one (1) cubic foot of anhydrous gas, at a temperature of sixty (60) degrees Fahrenheit and at an absolute pressure of fourteen decimal six nine six (14.696) pounds per square inch, with the air at the same temperature and pressure as the gas, after cooling the products of the combustion to the initial temperature of the gas and air, and after condensation of the water formed by combustion;

GSA: as defined in the Recitals;

GSA Event: an event of force majeure claimed or declared under the GSA or any reduction in the daily contract quantity under the GSA as a result of an event of force majeure claimed or declared under the GSA, as notified by Seller to Buyer;

HH: 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 the relevant cargo’s Delivery Window is scheduled to begin;

ICC: as defined in Section 21.2.1;

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Indemnified Party: as defined in Section 15.3(a);

Indemnifying Party: as defined in Section 15.3(a);

International LNG Terminal Standards: to the extent not inconsistent with the express requirements of this Agreement, the international standards and practices applicable to the design, construction, equipment, operation or maintenance of LNG liquefaction terminals, established by the following (such standards to apply in the following order of priority): (i) a Governmental Authority having jurisdiction over the Corpus Christi Facility (or alternate source, as applicable), Seller, or the operator of the relevant LNG facility; (ii) the Society of International Gas Tanker and Terminal Operators (SIGTTO) (to the extent applicable); and (iii) any other internationally recognized non-governmental agency or organization with whose standards and practices it is customary for Reasonable and Prudent Operators of LNG liquefaction terminals, to comply; provided, however, that in the event of a conflict between any of the priorities noted above, the priority with the lowest roman numeral noted above shall prevail;

International LNG Vessel Standards: the standards and practices from time to time in force applicable to the ownership, design, equipment, operation or maintenance of LNG vessels established by: (i) Governmental Authorities; (ii) the International Maritime Organization; (iii) the Oil Companies International Marine Forum (OCIMF); (iv) the Society of International Gas Tanker and Terminal Operators (SIGTTO) (or any successor body of the same); (v) the International Navigation Association (PIANC); (vi) the International Association of Classification Societies; and (vii) any other internationally recognized agency or non-governmental organization with whose standards and practices it is customary forReasonable and Prudent Operators of LNG vessels similar to those applicable to this Agreement, to comply; provided, however, that in the event of a conflict between any of the priorities noted above, the priority with the lowest roman numeral noted above shall prevail;

9

International Standards: (i) with respect to Buyer, the International LNG Vessel Standards; (ii) with respect to Seller, the International LNG Terminal Standards;

In-Transit Final Notice: as defined in Section 7.9.3(c);

In-Transit First Notice: as defined in Section 7.9.2;

In-Transit Second Notice: as defined in Section 7.9.3(a);

In-Transit Third Notice: as defined in Section 7.9.3(b);

Lender: any Person that does or proposes to lend money, finance or provide financial support or equity in any form in respect of all or any portion of the Corpus Christi Facility and/or the general business and operations of Seller or its Affiliates (including any refinancing thereof), including any export credit agency, funding agency, bondholder, insurance agency, underwriter, investor, commercial lender or similar institution, together with any agent or trustee for such Person;

Lenders’ Agent: as defined in Section 22.4.1;

LIBOR: on or from any Day, the percentage rate per annum published two (2) London Banking Days before that Day (or, if that Day is not a London Banking Day, published two (2) London Banking Days before the nearest preceding London Banking Day) at 11:00 a.m. London time, by the ICE Benchmark Administration Ltd that appears on the Reuters Screen LIBOR01 page as three (3) Month USD LIBOR or, if no such rate is published, such other rate representing the cost of three (3) Month USD funds in the London interbank lending market on that Day as reasonably agreed by the Parties;

LNG: Gas in a liquid state at or below its point of boiling and at or near atmospheric pressure;

LNG Tanker(s): an ocean-going vessel suitable for transporting LNG which complies with the requirements of this Agreement and which Buyer uses, or intends to use, in connection with this Agreement;

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Loading Port: the port where the Corpus Christi Facility is located, in the vicinity of Portland, Texas, or the port at an alternate source (as applicable);

London Banking Day: any Day (other than Saturdays, Sundays and national holidays in London, England) on which banks are normally open to conduct business in London, England;

Losses: any and all losses, liabilities, damages, costs, judgments, settlements and expenses (whether or not resulting from Claims by Third Parties), including interest and penalties with respect thereto and reasonable attorneys’ and accountants’ fees and expenses;

Major Scheduled Maintenance Quantity: as defined in Section 5.3;

Measurement Dispute: as defined in Section 21.2.1;

MMBtu: one million (1,000,000) Btus;

Month: each period of time which starts at 00:00 Central Time on the first Day of each calendar month and ends at 24:00 Central Time, on the last Day of the same calendar month;

Ninety Day Schedule: as defined in Section 8.4;

Non-FTA Export Authorization: DOE/FE Order No. 3638 issued May 12, 2015 in FE Docket No. 12-97-LNG from the Office of Fossil Energy of the U.S. Department of Energy granting to Seller or an Affiliate of Seller the long-term authorization to export at least the volume per annum of LNG sold and delivered pursuant to this Agreement by vessel from the Corpus Christi Facility to countries that have entered into a free trade agreement with the United States of America requiring the national treatment for trade in natural gas, for a specific term, as the same may be supplemented, amended, modified, changed, superseded or replaced from time to time;

Non-Publication Period: as defined in Section 1.3.2;

Notice of Readiness or NOR: the notice of readiness issued by an LNG Tanker in accordance with Section 7.10.1;

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Off-Spec LNG: as defined in Section 12.3.1;

Operational Tolerance: two percent (2%) of the Scheduled Cargo Quantity;

P&I Club: a Protection and Indemnity Club that is a member of the International Group of P&I Clubs;

P&I Insurance: as defined in Section 15.5(b);

Party: Buyer or Seller, and Parties means both Buyer and Seller;

Payment Due Date: as defined in Section 10.2.1;

Payor: as defined in Section 11.4;

PBS: the customary Pilot boarding station at the Loading Port where the Pilot boards the LNG Tanker, as determined by the applicable Governmental Authority or other entity with authority to regulate transit and berthing of vessels at the Loading Port;

Person: any individual, corporation, partnership, trust, unincorporated organization or other legal entity, including any Governmental Authority;

Pilot: any Person engaged by Transporter to come on board the LNG Tanker to assist the master in pilotage, mooring and unmooring of such LNG Tanker;

Port Charges: all charges of whatsoever nature (including rates, tolls, dues, fees, and imposts of every description) in respect of an LNG Tanker entering or leaving the Loading Port or loading LNG, including wharfage fees, in-and-out fees, franchise fees, line handling charges, and charges imposed by fire boats, tugs and escort vessels, the U.S. Coast Guard, a Pilot, and any other authorized Person assisting an LNG Tanker to enter or leave the Loading Port, and further including port use fees, throughput fees and similar fees payable by users of the Loading Port (or by Seller or the operator of the LNG facility on behalf of such users);

Port Liability Agreement: an agreement for use of the port and marine facilities located at the Loading Port, to be entered into as described in Section 7.7.1, which shall be substantially in the form attached in Exhibit B hereto as may be

12

amended pursuant to Section 7.7.4 (modified as appropriate for an alternate source, as applicable);

Pricing Month: in respect of a cargo: (a) subject to sub-part (b), the Month in which the relevant cargo’s Delivery Window is scheduled to begin; or (b) the Month nominated by Seller pursuant to Section 9.1.2;

Provisional Invoice: as defined in Section 10.1.6(a);

Reasonable and Prudent Operator: a Person seeking in good faith to perform its contractual obligations, and in so doing, and in the general conduct of its undertaking, exercising that degree of skill, diligence, prudence and foresight which would reasonably and ordinarily be expected from a skilled and experienced operator, complying with all applicable International Standards and practices and regulations and approvals of Governmental Authorities, engaged in the same type of undertaking under the same or similar circumstances and conditions;

Replacement Index Difference: the difference between the amount owed by the owing Party as calculated based on the Replacement Rate/Index during the Non-Publication Period minus the amount that has been actually paid by the owing Party during such Non-Publication Period;

Replacement Index Difference Interest: the lower of: (i) the then-effective prime rate of interest published under Money Rates by The Wall Street Journal, plus 2% per annum; and (ii) the maximum interest rate permitted under Applicable Laws;

Replacement Rate Index: as defined in Section 1.3.2;

Rules: as defined in Section 21.1.2;

Sabine Pass Facility: the facilities that Sabine Pass Liquefaction, LLC and/or its Affiliates are developing and constructing and own and operate (or have operated on their behalf) in Cameron Parish, Louisiana, including the Gas pretreatment and processing facilities, liquefaction facilities, storage tanks, utilities, terminal facilities, and associated port and marine facilities, and all other related facilities both inside and outside the LNG plant,

13

including any expansions or modifications made thereto;

SCF: for Gas, the quantity of anhydrous Gas that occupies one (1) cubic foot of space at a temperature of sixty (60) degrees Fahrenheit and a pressure of fourteen decimal six nine six (14.696) pounds per square inch absolute;

Scheduled Cargo Quantity: in respect of a cargo, the quantity of LNG (in MMBtus) identified in the ADP or Ninety Day Schedule in respect of such cargo, subject always to modification in accordance with Section 8;

Seller: as defined in the Preamble;

Seller Aggregate Liability: as defined in Section 15.2.6(b);

Seller Liability Cap: as defined in Section 15.2.6(c);

Seller Taxes: as defined in Section 11.2;

SI: the International System of Units;

Specifications: as defined in Section 12.1.1;

Start Date: January 1, 2020;

Term: as defined in Section 4.1.1;

Terminating Party: as defined in Section 20.2.1;

Termination Events: as defined in Section 20.1;

Third Party: a Person other than a Party;

Third Party Claim: as defined in Section 15.3(a);

Transporter: any Person who is a registered or disponent owner of the LNG Tanker, or any Person who contracts with the same or with Buyer for the purposes of providing, operating, or chartering any of the LNG Tankers;

U.S. Gulf Coast: the states of Texas, Louisiana, Mississippi, Alabama, and Florida and the United States of America state and federal waters of the Gulf of Mexico; and

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USD or US$: the lawful currency from time to time of the United States of America.

1.2 Interpretation

For purposes of this Agreement:

1.2.1 The titles, headings, and numbering in this Agreement are included for convenience only and will have no effect on the construction or interpretation of this Agreement.

1.2.2 References in this Agreement to Sections and Exhibits are to those of this Agreement unless otherwise indicated. References to this Agreement and to agreements and contractual instruments will be deemed to include all exhibits, schedules, appendices, annexes, and other attachments thereto and all subsequent amendments and other modifications to such instruments, to the extent such amendments and other modifications are not prohibited by the terms of this Agreement.

1.2.3 The word “include” or “including” will be deemed to be followed by “without limitation.” The term “will” has the same meaning as “shall,” and thus imposes an obligation.

1.2.4 Whenever the context so requires, the singular includes the plural and the plural includes the singular, and the gender of any pronoun includes the other gender.

1.2.5 Unless otherwise indicated, (a) references to any statute, regulation, law or Approval will be deemed to refer to such statute, regulation, law or Approval as may be amended from time to time, or any successor statute, regulation, law or Approval and (b) references to any recognized industry publication will be deemed to refer to such publication, as may be amended from time to time, or any successor publication.

1.2.6 All references to a Person shall include such Person’s successors and permitted assigns. All references to the masculine, feminine or neuter shall include the other genders.

1.2.7 Unless otherwise indicated, any reference to a time of Day shall be to Central Time in the United States of America.

1.2.8 Approximate conversions of any unit of measurement contained in parenthesis following the primary unit of measurement included in Sections 1 through 26 of this Agreement are inserted as a matter of operational convenience only to show the approximate equivalent in such different measurement. The obligations of the Parties under Sections 1 through 26

15

of this Agreement will be undertaken in respect of the primary unit of measurement and not in respect of any such approximate conversion.

1.3 Non-Publication Events

The provisions of this Section 1.3 shall apply only in respect of GCM (as defined in Section 9.1), HH, LIBOR and sub-part ‘(i)’ of the definition of Replacement Index Difference Interest.

1.3.1 Subject to Section 1.3.3 and Section 1.3.4, if (a) a publication that contains a rate or index used in this Agreement ceases to be published for any reason or (b) such a rate or index ceases to exist, is materially modified, or no longer is used as a liquid trading point for Gas (as applicable), so as systematically to change its economic result, or is disaggregated, displaced or abandoned, for any reason, then the Parties shall promptly discuss, with the aim of jointly selecting a rate or index or rates or indices to be used in place of such rate or index that maintains the intent and economic effect of the original rate or index.

1.3.2 If the Parties fail to agree on a replacement rate or index pursuant to Section 1.3.1 within thirty (30) Days, the Parties may submit such Dispute to, and in such case the Parties hereby agree that such Dispute shall be resolved by, an Expert appointed pursuant to Section 21.2 and the provisions of Section 21.2 shall apply to such Dispute. Any Expert selected shall be instructed to select the published rate or index, or a combination of published rates or indices, with adjustments as necessary or appropriate, that most nearly preserves the intent and economic result of the original rate or index (the “Replacement Rate/Index”). In the event a Dispute under this Section 1.3 is pending resolution by an Expert, notwithstanding any provision in this Agreement to the contrary, each Party shall continue to fulfill its payment obligations to the other Party based on a rate or index that is determined by calculating the preceding six (6) month average of the rate or index used prior to the non-publication event described in Section 1.3.1 for any payments owed by the owing Party between such non-publication event and the designation of a replacement rate or index by the Expert (the “Non-Publication Period”). If the Replacement Index Difference is positive, the owing Party shall pay the Replacement Index Difference to the owed Party within five (5) Business Days, together with the Replacement Index Difference Interest. If the Replacement Index Difference is negative, the owed Party shall pay the Replacement Index Difference to the owing Party within five (5) Business Days, together with the Replacement Index Difference Interest.

1.3.3 If any rate used in this Agreement is not published for a particular date, but the publication containing such rate continues to be published and the rate itself continues to exist, the Parties shall use the published rate in effect for

16

the date such rate was most recently published prior to the particular date, unless otherwise provided in this Agreement.

1.3.4 If any index used in this Agreement is not published for a particular date, but the publication containing such index continues to be published and the index itself continues to exist, the Parties shall use the index from the geographic location closest in proximity to the unpublished index from the same publication in effect for the particular date adjusted by the difference between the same indices from the most recent publication published prior to the particular date, unless otherwise provided in this Agreement.

1.4 Errant Price

If an incorrect value is published for any rate or index used in this Agreement and such error is corrected and published within ninety (90) Days of the date of the publication of such incorrect rate or index, such corrected rate or index will be substituted for the incorrect rate or index and any calculations involving such rate or index will be recalculated and the Parties will take any necessary actions based upon these revised calculations, including adjustments of amounts previously invoiced and/or paid.

2. Approvals

(a) Except as may be excused by Force Majeure, (i) Seller or an Affiliate of Seller shall obtain and maintain, or cause to be obtained and maintained, in force the Export Authorizations at all times commencing no later than the Start Date and (ii) in case either of the Export Authorizations is to expire before the expiration of the Term, Seller or an Affiliate of Seller shall use its reasonable efforts to obtain one or more extensions of the same in aggregate up to or beyond the end of the Term. Buyer and Seller shall use reasonable efforts to obtain and maintain in force, and shall use reasonable efforts to cause their respective Affiliates to obtain and maintain in force, the other Approvals (other than the Export Authorizations) which are required for the performance of this Agreement, and shall cooperate fully with each other whenever necessary for this purpose.

(b) If the laws of the United States of America do not require maintenance of or compliance with one or both Export Authorization(s) to export LNG from the United States of America, then for so long as the laws of the United States of America do not require such maintenance or compliance, the Parties agree that this Agreement shall be read and construed to omit those provisions of this Agreement relating to such affected Export Authorization(s) and neither Party shall have any rights or obligations (including obligations to maintain such affected Export Authorization(s), rights to terminate this Agreement and claims of Force Majeure) in respect of any such Export Authorization(s).

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3. Subject Matter

3.1 Sale and Purchase

3.1.1 Seller shall sell and make available for delivery, or compensate Buyer if not made available for delivery, LNG in cargoes at the Delivery Point, and Buyer shall take and pay for, or compensate Seller if not taken, such LNG, in the quantities and at the prices set forth in and otherwise in accordance with and subject to the provisions of this Agreement.

3.1.2 Seller intends to load cargoes under this Agreement from the Corpus Christi Facility, but Seller may, subject to Section 8.3.3, elect to load any cargo(es) under this Agreement at other LNG facilities.

3.1.3 All savings, profits and optimizations realized by Seller as a result of delivering cargoes from an alternate source shall remain for the benefit of Seller without profit sharing.

3.2 Facilities

Subject to Section 2(a), Seller covenants that, acting as a Reasonable and Prudent Operator, it shall at all relevant times from the Start Date and continuing throughout the Term own (either directly or indirectly through one or more Affiliates), or have access to and use of, and maintain and operate or cause to be maintained and operated, consistent with International Standards and subject to all Applicable Laws, the Corpus Christi Facility so as to enable Seller to fulfill its obligations to Buyer under this Agreement.

3.3 Destination

Subject to Section 26.1 and notwithstanding the Discharge Terminal corresponding to any cargo in the ADP or Ninety Day Schedule, Buyer shall be free to (i) sell such LNG free on board at the Corpus Christi Facility (or alternate source, as applicable) or at any other point during a voyage, or at or after the unloading of any LNG purchased hereunder and (ii) transport the LNG to, and market the LNG at, any destination of its choosing, in accordance with the provisions of this Agreement.

4. Term

4.1 Term

4.1.1 This Agreement shall enter into force and effect on the Effective Date and, subject to Section 4.1.2 and Section 20, shall continue in force and effect until December 31, 2026 (the “Term”).

4.1.2 If, prior to December 31, 2026, the GSA terminates pursuant to section 2(a), section 2(b) or section 2(c) therein, this Agreement shall automatically

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terminate on the date the GSA terminates. In such case, Seller shall promptly notify Buyer.

4.2 Contract Year

References to a “Contract Year” mean a period of time from and including January 1^st through and including December 31^st of the same calendar year, provided that:

(a) the first Contract Year is the period of time beginning on the Start Date and ending on December 31, 2020 (the “First Contract Year”); and

(b) the final Contract Year is the period of time beginning on the January 1^st immediately preceding the final Day of the Term and ending on the final Day of the Term (the “Final Contract Year”).

5. Quantities

5.1 ACQ

5.1.1 Subject to Section 5.1.4 and Section 5.1.5, the annual contract quantity (“ACQ”) for any Contract Year shall be an amount equal to forty-four million four hundred thirty-four thousand seven hundred eighty-eight (44,434,788) MMBtu.

5.1.2 The ACQ for purposes of determining all obligations under this Agreement shall be the amount expressed in MMBtus. All references in this Agreement to cargoes or other quantities are solely for operational convenience.

5.1.3 With respect to each Contract Year, the AACQ for the relevant Contract Year shall be scheduled for delivery in the relevant ADP on a reasonably even and ratable basis throughout the relevant Contract Year, taking into consideration planned maintenance at the Corpus Christi Facility and any Major Scheduled Maintenance Quantities in accordance with Section 5.3.

5.1.4 If the Final Contract Year does not end on December 31^st, then the ACQ for the Final Contract Year shall be reduced by Seller, acting reasonably, to equal an amount of LNG approximately equivalent to the amount of Gas Seller is taking delivery of under the EOG GSA in respect of such Contract Year divided by one hundred fifteen percent (115%).

5.1.5 Seller may, from time to time by providing notice to Buyer, reduce the ACQ for a Contract Year by a quantity equal to the amount of LNG that Seller has committed to sell to a Third Party in an agreement for the sale and purchase of LNG that directly replaces in whole or in part the annual contract quantity of this Agreement, provided that such notice is provided no later than sixty (60) Days before an affected cargo’s Delivery Window is

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scheduled to begin. If Seller provides any such notice, Seller may also specify a change in the delivery profile set out in Section 5.1.3.

5.2 Adjusted Annual Contract Quantity

The “Adjusted Annual Contract Quantity” or “AACQ”, expressed in MMBtu, for each Contract Year shall be equal to the ACQ for the relevant Contract Year, less Major Scheduled Maintenance Quantities for such Contract Year, if any, determined in accordance with Section 5.3;

5.3 Major Scheduled Maintenance

Seller shall be entitled to reduce the AACQ in case of scheduled maintenance to the Corpus Christi Facility (the “Major Scheduled Maintenance Quantity”), subject to the following conditions:

(a) Seller may only exercise its right to such reduction in a Contract Year to the extent it or its Affiliate determines, as a Reasonable and Prudent Operator, that major scheduled maintenance is required for operational reasons;

(b) Seller shall notify Buyer of its exercise of Major Scheduled Maintenance Quantity pursuant to Section 8.1.3(b), such quantity being limited to one (1) cargo per Contract Year;

(c) any Major Scheduled Maintenance Quantity reduction elected by Seller shall result in the removal of one (1) cargo from the ADP proposed by Buyer in accordance with Section 8.1.2 (Seller to identify the cargo being removed from the schedule) and Seller shall be relieved of its obligation to make available a cargo in respect of the Month in which such removed cargo had been preliminarily scheduled; and

(d) the cumulative amount of all Major Scheduled Maintenance Quantity reductions elected by Seller pursuant to this Section 5.3 shall not exceed three (3) cargoes during any six (6) consecutive Contract Years.

5.4 Buyer’s Purchase Obligation

5.4.1 In respect of each Contract Year, Buyer shall take and pay for the Scheduled Cargo Quantity with respect to each cargo included in the AACQ and scheduled in the ADP for such Contract Year, less:

(a) quantities of LNG not made available by Seller for any reason attributable to Seller (other than quantities for which Seller is excused

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pursuant to this Agreement from making available due to Buyer’s breach of this Agreement), including Force Majeure affecting Seller;

(b) quantities of LNG not taken by Buyer for reasons of Force Majeure;

(c) quantities of LNG for which Seller has provided a notice of cancellation pursuant to Section 5.6, except where Buyer has provided notice of its election pursuant to Section 5.6 to purchase such quantities of LNG at the alternative price; and

(d) any quantity of LNG that the relevant LNG Tanker is not capable of loading due to Seller’s delivery of LNG that has a Gross Heating Value that is less than the value identified by Seller pursuant to Section 8.1.

5.5 Seller’s Delivery Obligation

5.5.1 In respect of each Contract Year, Seller shall make available to Buyer the Scheduled Cargo Quantity with respect to each cargo included in the AACQ and scheduled in the ADP for such Contract Year, less:

(a) quantities of LNG not taken by Buyer for any reason attributable to Buyer (other than quantities for which Buyer is excused pursuant to this Agreement from taking due to Seller’s breach of this Agreement), including Force Majeure affecting Buyer;

(b) quantities of LNG for which Seller has provided a notice of cancellation pursuant to Section 5.6, except where Buyer has provided notice of its election pursuant to Section 5.6 to purchase such quantities of LNG at the alternative price; and

(c) quantities of LNG not made available by Seller due to Force Majeure.

5.5.2 Except as otherwise excused in accordance with the provisions of this Agreement, if, with respect to any cargo identified in Section 5.5.1, Seller does not make available the Scheduled Cargo Quantity of such cargo, and such failure to make available is not otherwise excused pursuant to Section 5.5.1, then the amount by which the Scheduled Cargo Quantity exceeds the quantity of LNG made available by Seller in relation to such cargo shall be the “Cargo DoP Quantity”. Seller shall make a payment to Buyer for each MMBtu of the Cargo DoP Quantity in an amount equal to: (a) the actual, documented price incurred by Buyer (in USD per MMBtu) for the purchase of a replacement quantity of LNG or Gas (not to exceed the MMBtu equivalent of the Cargo DoP Quantity), or, in respect of any Cargo DoP Quantity for which a replacement quantity cannot be purchased, the market price (in USD per MMBtu) of LNG at such time for delivery FOB in the

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United States of America Gulf Coast; less (b) (i) the Alternative CSP or (ii) if Seller fails to make a cargo available, then (A) the Cargo Payment (calculated in accordance with Section 9.1.1 as if such cargo had been made available in the Pricing Month) divided by (B) the Scheduled Cargo Quantity; plus (c) actual, reasonable, and verifiable incremental costs (if any) incurred by Buyer as a result of such failure to make the Scheduled Cargo Quantity available (in USD per MMBtu), including costs associated with transportation; less (d) actual and verifiable cost savings (if any) realized by Buyer as a result of such failure to make the Scheduled Cargo Quantity available (in USD per MMBtu) (the “Cargo DoP Payment”); provided that the total Cargo DoP Payment payable in respect of the Cargo DoP Quantity shall not exceed an amount equal to (x) the Cargo DoP Quantity multiplied by (i) GSA CSP (calculated in accordance with Section 9.1.1 as if such cargo had been made available in the Pricing Month) or (ii) if Buyer has elected to purchase the relevant cargo at the alternative price in accordance with Section 5.6, then the Alternative CSP; or (y) if Seller fails to make a cargo available, then the Cargo Payment (calculated in accordance with Section 9.1.1 as if such cargo had been made available in the Pricing Month).

5.5.3 Buyer shall use reasonable efforts to mitigate Seller’s liability to make any payments pursuant to this Section 5.5.

5.5.4 In the event the ability of the Corpus Christi Facility to produce and deliver LNG is impaired due to an unscheduled services interruption that does not constitute Force Majeure, then during such event of interruption, Seller may comply with the Foundation Customer Priority in allocating the LNG that is available from the Corpus Christi Facility.

5.5.5 Any payment that Seller makes under this Section 5.5 shall not be treated as an indirect, incidental, consequential or exemplary loss or a loss of income or profits for purposes of Section 15.2.1.

5.6 Cargo Cancellation; Buyer Override

Seller may notify Buyer that it intends to cancel delivery of any cargo scheduled in the ADP by providing notice of such intention to Buyer on or before the first (1^st) Business Day after the twentieth (20th) Day of the Month that is two (2) Months prior to the Month in which the relevant cargo’s Delivery Window is scheduled to begin. Upon receipt of any such notice, Buyer shall have the right to elect to purchase the relevant cargo at the Alternative CSP, subject to exercising such election by providing notice to Seller within five (5) Days after receipt of Seller’s notice. If Buyer does not provide notice in accordance with this Section 5.6 of its election to purchase the relevant cargo at the alternative price, then such cargo shall be deemed cancelled and each Party shall be relieved of its obligation to make available (in the

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case of Seller) such cargo pursuant to Section 5.5 and take and pay for (in the case of Buyer) such cargo pursuant to Section 5.4.

6. Delivery Point, Title and Risk

6.1 Delivery Point

Seller shall deliver LNG to Buyer, subject to the terms and conditions of this Agreement, at the point at which the flange coupling of the LNG loading line at the Corpus Christi Facility (or alternate source, as applicable) joins the flange coupling of the LNG intake manifold of the relevant LNG Tanker (“Delivery Point”).

6.2 Title and Risk

Title to, and all risks in respect of, the LNG sold by Seller pursuant to this Agreement shall pass from Seller to Buyer as the LNG passes the Delivery Point.

7. Transportation and Loading

7.1 Transportation by Buyer

Buyer shall, in accordance with this Agreement, Applicable Laws, Approvals and International Standards, provide, or cause to be provided, transportation from the Delivery Point of all quantities of LNG delivered hereunder to Buyer. Buyer shall, no later than the fifteenth (15^th) Day following the end of each calendar quarter, provide a report to Seller stating, in respect of each cargo loaded hereunder during such calendar quarter, whether Buyer or an Affiliate of Buyer owned or operated the LNG Tanker used to transport each such cargo. If requested by Seller, Buyer shall use reasonable efforts to provide additional information regarding LNG Tanker delivery terms. Buyer shall cause any Third Party that has purchased a cargo that is the subject of this Agreement to provide the information required by this Section 7.1 as if such Third Party were Buyer.

7.2 Corpus Christi Facility

7.2.1 During the Term, Seller shall at all times cause to be provided, maintained and operated the Corpus Christi Facility in accordance with the following: (a) International Standards; (b) all terms and conditions set forth in this Agreement; (c) Applicable Laws; and (d) to the extent not inconsistent with International Standards, such good and prudent practices as are generally followed in the LNG industry by Reasonable and Prudent Operators of similar LNG liquefaction terminals.

7.2.2 The Corpus Christi Facility shall include the following:

(a) appropriate systems for communications with LNG Tankers;

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(b) a berth, capable of berthing an LNG Tanker having a displacement of no more than one hundred sixty-six thousand (166,000) tons, an overall length of no more than one thousand one hundred forty (1,140) feet (approximately 347 meters), a beam of no more than one hundred seventy-five (175) feet (approximately 53 meters), and a draft of no more than forty (40) feet (approximately 12 meters), which LNG Tankers can safely reach, at which LNG Tankers can lie safely berthed and load safely afloat, and safely depart, fully laden;

(c) lighting sufficient to permit loading operations by day or by night, to the extent permitted by Governmental Authorities and Pilots (it being acknowledged, however, that Seller shall in no event be obligated to allow nighttime berthing operations at the Corpus Christi Facility if Seller or the operator of the relevant facility determines that such operations during nighttime hours could pose safety or operational risks to the Corpus Christi Facility, an LNG Tanker, or a Third Party);

(d) facilities capable of transferring LNG at a rate of up to an average of twelve thousand (12,000) Cubic Meters per hour at the Delivery Point, with three (3) LNG transfer arms each having a reasonable operating envelope to allow for ship movement and manifold strainers of sixty (60) mesh;

(e) a vapor return line system of sufficient capacity to allow for transfer of Gas necessary for safe cargo operations of an LNG Tanker at the required rates, pressures and temperatures;

(f) facilities allowing ingress and egress between the Corpus Christi Facility and the LNG Tanker by (i) representatives of Governmental Authorities for purposes of LNG transfer operations; and (ii) an independent surveyor for purposes of conducting tests and measurements of LNG on board the LNG Tanker;

(g) emergency shut down systems;

(h) LNG storage facilities;

(i) LNG liquefaction facilities; and

(j) qualified and competent personnel, fluent in English to coordinate with the LNG Tanker during loading operations.

7.2.3 Services and facilities not provided by Seller include the following: (a) facilities and loading lines for liquid or gaseous nitrogen to service an LNG Tanker; (b) facilities for providing bunkers; (c) facilities for the handling and delivery to the LNG Tanker of ship’s stores, provisions and

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spare parts; and (d) nitrogen rejection or natural gas liquids (NGL) removal. Buyer shall be required to obtain towing, escort, line handling, and pilot services as described in Section 7.5.3.

7.3 Compatibility of the LNG Facility with LNG Tankers

7.3.1 Buyer shall ensure, at no cost to Seller, that each of the LNG Tankers is fully compatible with the general specifications set forth in Section 7.2.2 and any modifications made to the Corpus Christi Facility in accordance with Section 7.3.2. Should an LNG Tanker fail materially either to be compatible with the Corpus Christi Facility (or alternate source, as applicable), or to be in compliance with the provisions of Section 7.5 and Section 7.6, Buyer shall not employ such LNG Tanker until it has been modified to be so compatible or to so comply.

7.3.2 The Parties agree that, after the Effective Date, Seller and its Affiliates shall be entitled to modify the Corpus Christi Facility in any manner whatsoever, provided that: (x) such modifications do not render the Corpus Christi Facility incompatible with an LNG Tanker that is compatible with the general specifications set forth in Section 7.2.2 and is scheduled in the applicable ADP or Ninety Day Schedule; (y) such modifications, once finalized, do not reduce the ability of Seller to make available LNG in accordance with the terms of this Agreement; and (z) such modifications do not otherwise conflict with Seller’s obligations hereunder. Notwithstanding the foregoing, Seller and its Affiliates may modify the Corpus Christi Facility in a manner that would render it incompatible with an LNG Tanker provided that such modification is required by and is made pursuant to a change in Applicable Laws, Approvals, or International Standards, or is required for safety or environmental reasons.

7.3.3 In the event the LNG Tanker fails to be compatible with the Corpus Christi Facility due to a modification of the facility that is not provided for in Section 7.3.2, the reasonable cost of the modifications of the LNG Tanker directly caused by such modification shall be reimbursed by Seller to Buyer.

7.4 Buyer Inspection Rights in Respect of the Corpus Christi Facility

7.4.1 Upon obtaining Seller’s prior written consent, which consent shall not be unreasonably withheld or delayed, a reasonable number of Buyer’s designated representatives (of which at least one must be an employee of Buyer or its Affiliate) may from time to time (including during the period of construction of the liquefaction facilities), but no more than once in any three hundred sixty-five (365) Day period, inspect the operation of the Corpus Christi Facility so long as such inspection occurs from 8:00 a.m. Central Time to 5:00 p.m. Central Time on a Business Day in the United States of America. Any such inspection shall be at Buyer’s sole risk and

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expense. In conjunction with any such inspection, Seller shall provide Buyer access at reasonable times and places (taking into consideration cost and schedule impacts) to (a) relevant qualified employees and contractors of Seller in order to discuss the operation and maintenance of the Corpus Christi Facility and (b) relevant documentation, if any, available to Seller in support of such discussions to the extent Seller is permitted to disclose the same. Buyer (and its designees) shall carry out any such inspection without any interference with or hindrance to the safe and efficient operation of the Corpus Christi Facility. Buyer’s right to inspect and examine the Corpus Christi Facility shall be limited to verifying that the Corpus Christi Facility is in compliance with the requirements of Section 7.2. No inspection (or lack thereof) of the Corpus Christi Facility by Buyer hereunder, or any requests or observations made to Seller or its representatives by or on behalf of Buyer in connection with any such inspection, shall (x) modify or amend Seller’s obligations, representations, warranties and covenants hereunder; or (y) constitute an acceptance or waiver by Buyer of Seller’s obligations hereunder.

7.4.2 Buyer shall indemnify and hold Seller and its Affiliates harmless from any Claims and Losses resulting from Buyer’s inspection of the Corpus Christi Facility pursuant to Section 7.4.1.

7.5 LNG Tankers

7.5.1 Buyer shall cause each LNG Tanker to comply with the requirements of this Section 7.5 and the requirements of Section 7.6 in all respects.

7.5.2 Each LNG Tanker shall comply with the regulations of, and obtain all Approvals required by, Governmental Authorities to enable such LNG Tanker to enter, leave and carry out all required operations at the Corpus Christi Facility (or alternate source, as applicable). Each LNG Tanker shall at all times have on board valid documentation evidencing all such Approvals. Each LNG Tanker shall comply fully with the International Safety Management Code for the Safe Operation of Ships and Pollution Prevention effective July 1, 1998, as amended from time to time, and at all times be in possession of valid documents of compliance and safety management certificates, and can demonstrate that the LNG Tanker has an effective management system in operation that addresses all identified risks, and provides proper controls for dealing with these risks.

7.5.3 Buyer shall cause Transporter to enter into a tug services agreement to provide such number and types of tugs, fireboats and escort vessels as are (i) acceptable to Seller and the operator of the LNG facility, (ii) required by Governmental Authorities to attend the LNG Tanker and (iii) necessary and appropriate to permit safe and efficient movement of the LNG Tanker within the maritime safety areas located in the approaches to and from the LNG

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facility. An Affiliate of Seller has elected to procure tug services at the Corpus Christi Facility and, in respect of loadings at the Corpus Christi Facility, Buyer shall cause Transporter to enter into a tug services agreement with such Affiliate of Seller. Such tug services agreement shall provide that the fees for tug services shall be applied on a non-discriminatory basis among all long-term customers. Seller shall not be required to provide tugs, fireboats and escort vessels to attend any LNG Tanker and shall not be liable to Buyer in connection with Transporter’s failure to enter into such arrangements.

7.5.4 Buyer shall pay or cause to be paid: (a) all Port Charges directly to the appropriate Person (including reimbursing Seller for any Port Charges paid by Seller or the operator of the LNG facility on Buyer’s behalf); and (b) all charges payable by reason of any LNG Tanker having to shift from berth at the Corpus Christi Facility (or alternate source, as applicable) unless such charges are incurred solely as a result of Seller’s fault.

7.5.5 Each LNG Tanker must satisfy the following requirements:

(a) Except as otherwise mutually agreed in writing by the Parties, each LNG Tanker shall be compatible with the general specifications set forth in Section 7.2.2(a)-(j) and any modifications to the Corpus Christi Facility pursuant to Section 7.3.2, and shall be of a sufficient size to load the applicable Scheduled Cargo Quantity (subject to the Operational Tolerance). If Buyer’s LNG Tanker is not capable of loading the applicable Scheduled Cargo Quantity (subject to the Operational Tolerance), the portion of the Scheduled Cargo Quantity that cannot be loaded onto such alternate LNG Tanker shall be considered DQ, except to the extent that such failure is attributable to Seller’s delivery of LNG that has a Gross Heating Value that is less than the value identified by Seller pursuant to Section 8.1.

(b) Except as otherwise agreed in writing by Seller, which agreement shall not be unreasonably withheld, each LNG Tanker shall have a gross volumetric capacity between one hundred sixty thousand (160,000) Cubic Meters and one hundred eighty thousand (180,000) Cubic Meters.

(c) Each LNG Tanker shall be, in accordance with International Standards, (i) fit in every way for the safe loading, unloading, handling and carrying of LNG in bulk at atmospheric pressure; and (ii) tight, staunch, strong and otherwise seaworthy with cargo handling and storage systems (including instrumentation) necessary for the safe loading, unloading, handling, carrying and measuring of LNG in good order and condition.

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(d) Each LNG Tanker shall at all times be maintained in class with any of the following: American Bureau of Shipping, Lloyd’s Register, Bureau Veritas, Det Norske Veritas or any other classification society that is (i) a member of International Association of Classification Societies Ltd. (IACS) and (ii) mutually agreed upon by the Parties.

(e) Each LNG Tanker shall have been constructed to all applicable International Standards (including the International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk).

(f) Each LNG Tanker shall comply with, and shall be fully equipped, supplied, operated, and maintained to comply with, all applicable International Standards and Applicable Laws, including those that relate to seaworthiness, design, safety, environmental protection, navigation, and other operational matters, and all procedures, permits, and approvals of Governmental Authorities for LNG vessels that are required for the transportation and loading of LNG at the Loading Port. Unless approved by Seller in writing, which approval shall not be unreasonably withheld or delayed, an LNG Tanker shall be prohibited from engaging in any maintenance, repair or in-water surveys while berthed at the Corpus Christi Facility (or alternate source, as applicable). Each LNG Tanker shall comply fully with the guidelines of any Governmental Authority of the United States of America, including the National Oceanographic and Atmospheric Administration (NOAA), in relation to actions to avoid strikes in the waters of the United States of America with protected sea turtles and cetaceans (e.g., whales and other marine mammals) and with regard to the reporting of any strike by the LNG Tanker which causes injury to such protected species.

(g) The officers and crew of each LNG Tanker shall have the ability, experience, licenses and training commensurate with the performance of their duties in accordance with internationally accepted standards with which it is customary for Reasonable and Prudent Operators of LNG vessels to comply and as required by Governmental Authorities and any labor organization having jurisdiction over the LNG Tanker or her crew. Without in any way limiting the foregoing, the master, chief engineer, all cargo engineers and all deck officers shall be fluent in written and oral English and shall maintain all records and provide all reports with respect to the LNG Tanker in English.

(h) Each LNG Tanker shall have communication equipment complying with applicable regulations of Governmental Authorities and

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permitting such LNG Tanker to be in constant communication with the Corpus Christi Facility (or alternate source, as applicable) and with other vessels in the area (including fireboats, escort vessels and other vessels employed in port operations).

(i) Provided that the Corpus Christi Facility (or alternate source, as applicable) supplies a suitable vapor return line meeting the requirements of Section 7.2.2(e), then each LNG Tanker shall be capable of loading a full cargo of LNG in the number of hours derived after applying the following formula:

15 + x = maximum LNG transferring time (in hours)

where:

x = y/12,000 Cubic Meters; and

y = the LNG cargo containment capacity of the LNG Tanker minus one hundred forty thousand (140,000) Cubic Meters, provided that “y” shall be no less than zero (0).

Time for connecting, cooling, draining, purging and disconnecting of liquid arms shall not be included in the computation of loading time.

(j) Each LNG Tanker shall procure and maintain Hull and Machinery Insurance and P&I Insurance in accordance with Section 15.5.

7.6 LNG Tanker Inspections; LNG Tanker Vetting Procedures; Right to Reject LNG Tanker

7.6.1 During the Term, on prior reasonable notice to Buyer, Seller may, at its sole risk, send its representatives (including an independent internationally recognized maritime consultant) to inspect during normal working hours any LNG Tanker as Seller may consider necessary to ascertain whether the LNG Tanker complies with this Agreement. Seller shall bear the costs and expenses in connection with any inspection conducted under this Section 7.6.1. Any such inspection may include, as far as is practicable having regard to the LNG Tanker’s operational schedule, examination of the records related to the LNG Tanker’s hull, cargo and ballast tanks, machinery, boilers, auxiliaries and equipment; examination of the LNG Tanker’s deck, engine and official log books; review of records of surveys by the LNG Tanker’s classification society and relevant Governmental Authorities; and review of the LNG Tanker’s operating procedures and performance of surveys, both in port and at sea. Any inspection carried out pursuant to this Section 7.6.1: (a) shall not interfere with, or hinder, any LNG Tanker’s safe and efficient

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construction or operation; and (b) shall not entitle Seller or any of its representatives to make any request or recommendation directly to Transporter except through Buyer. No inspection (or lack thereof) of an LNG Tanker hereunder shall: (i) modify or amend Buyer’s obligations, representations, warranties, and covenants hereunder; or (ii) constitute an acceptance or waiver by Seller of Buyer’s obligations hereunder.

7.6.2 Seller shall indemnify and hold Buyer and its Affiliates harmless from any Claims and Losses resulting from Seller’s inspection of any LNG Tanker pursuant to Section 7.6.1.

7.6.3 Buyer shall comply with all LNG Tanker vetting procedures, as set forth in (a) in respect of loadings at the Corpus Christi Facility, the Corpus Christi Marine Operations Manual; and (b) in respect of loadings at any other LNG loading facility, the vetting procedures applied by the operator of such LNG loading facility and associated port.

7.6.4 Seller shall have the right to reject any LNG vessel that Buyer intends to use to take delivery of LNG hereunder if such LNG vessel does not comply materially with the provisions of this Agreement (including the vetting procedures described in Section 7.6.3), provided that:

(a) neither the exercise nor the non-exercise of such right shall reduce the responsibility of Buyer to Seller in respect of such LNG vessel and her operation, nor increase Seller’s responsibilities to Buyer or Third Parties for the same; and

(b) Buyer’s obligations under this Agreement shall not be excused or suspended by reason of Buyer’s inability (pursuant to the foregoing) to use a vessel as an LNG Tanker.

7.7 Port Liability Agreement

7.7.1 Buyer shall cause Transporter or the master of each LNG Tanker (acting on behalf of the ship-owner and charterer) making use of the port or marine facilities at the Corpus Christi Facility (or alternate source, as applicable) or the Loading Port thereof on behalf of Buyer, to execute the Port Liability Agreement prior to such LNG Tanker’s arrival at the Corpus Christi Facility (or alternate source, as applicable) or the Loading Port thereof. In the event the master of an LNG Tanker fails to execute such Port Liability Agreement, Buyer shall indemnify and hold Seller, the owner and operator of the applicable LNG loading facility, and their respective Affiliates harmless from any Claims brought against, or Losses incurred by any such Persons arising from such failure.

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7.7.2 Subject to Section 7.7.1 and without prejudice to the terms of the Port Liability Agreement, Seller releases Buyer, its Affiliates, and their respective shareholders, officers, members, directors, employees, designees, representatives, and agents from liability to Seller incident to all Claims and Losses that may exist, arise or be threatened currently or in the future at any time following the Effective Date and whether or not of a type contemplated by either Party at any time, brought by any Person for injury to, illness or death of any employee of Seller, or for damage to or loss of the relevant LNG loading facility, which injury, illness, death, damage or loss arises out of, is incident to, or results from the performance or failure to perform this Agreement by Buyer, or any of its Affiliates, shareholders, officers, members, directors, employees, designees, representatives and agents.

7.7.3 Subject to Section 7.7.1 and without prejudice to the terms of Section 12 or the Port Liability Agreement, Buyer releases Seller, its Affiliates, and their respective shareholders, officers, members, directors, employees, designees, representatives, and agents from liability to Buyer incident to all Claims and Losses that may exist, arise or be threatened currently or in the future at any time following the Effective Date and whether or not of a type contemplated by either Party at any time, brought by any Person for injury to, illness or death of any employee of Buyer, or for damage to or loss of any LNG Tanker, which injury, illness, death, damage or loss arises out of, is incident to, or results from the performance or failure to perform this Agreement by Seller or its Affiliates, shareholders, officers, members, directors, employees, designees, representatives and agents.

7.7.4 The form of Port Liability Agreement may be amended from time to time without consent of Buyer only if after any such amendment the revised terms of such Port Liability Agreement: (a) do not negatively impact Buyer’s ability to perform its obligations or exercise its rights under this Agreement, (b) treat Transporter in a non-discriminatory manner in comparison to all other owners and charterers of LNG vessels that use or transit the Loading Port, and (c) do not prevent any Transporter from obtaining, on commercially reasonable terms, full P&I indemnity coverage from a P&I Club, and such P&I indemnity will cover all Claims and Losses pursuant to such Port Liability Agreement in relation to use of the Loading Port by an LNG Tanker. Seller shall promptly notify Buyer upon any amendment to the Port Liability Agreement and shall provide a copy of the amended Port Liability Agreement to Buyer.

7.8 Marine Operations Manual

Seller shall, not later than the Start Date, deliver to Buyer a copy of the marine operations manual developed for the Corpus Christi Facility (as amended from time

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to time, the “Corpus Christi Marine Operations Manual”) which governs activities at the Corpus Christi Facility and which applies to each LNG Tanker and each other LNG vessel berthing at the Corpus Christi Facility. In the event of a conflict between this Agreement and the Corpus Christi Marine Operations Manual, the provisions of this Agreement shall control. Seller shall promptly notify Buyer upon any amendment to the Corpus Christi Marine Operations Manual and shall provide a copy of the amended Corpus Christi Marine Operations Manual to Buyer.

7.9 Loading of LNG Tankers

7.9.1 Except as otherwise specifically provided, the terms of this Section 7.9 shall apply to all LNG Tankers calling at the Corpus Christi Facility (or alternate source, as applicable).

7.9.2 As soon as practicable after the LNG Tanker’s departure from the point of departure en route to the Corpus Christi Facility (or alternate source, as applicable), Buyer shall notify, or cause the master of the LNG Tanker to notify, Seller of the information specified below (“In-Transit First Notice”):

(a) name of the LNG Tanker and, in reasonable detail, the dimensions, specifications, tank temperatures, volume of LNG onboard, operator, and owner of such LNG Tanker;

(b) any operational deficiencies in the LNG Tanker that may affect its performance at the Corpus Christi Facility (or alternate source, as applicable) or berth; and

(c) the ETA.

7.9.3 With respect to each LNG Tanker scheduled to call at the Corpus Christi Facility (or alternate source, as applicable), Buyer shall give, or cause the master of the LNG Tanker to give, to Seller the following notices:

(a) A second notice (“In-Transit Second Notice”), which shall be sent ninety-six (96) hours prior to the ETA set forth in the In-Transit First Notice or as soon as practicable prior to such ETA if the sea time between the point of departure of the LNG Tanker and the Loading Port is less than ninety-six (96) hours, stating the LNG Tanker’s then ETA. If, thereafter, such ETA changes by more than six (6) hours, Buyer shall give promptly, or cause the master of the LNG Tanker to give promptly, to Seller notice of the corrected ETA;

(b) A third notice (“In-Transit Third Notice”), which shall be sent twenty-four (24) hours prior to the ETA set forth in the In-Transit Second Notice (as corrected), confirming or amending such ETA. If,

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thereafter, such ETA changes by more than three (3) hours, Buyer shall give promptly, or cause the master of the LNG Tanker to give promptly, to Seller notice of the corrected ETA;

(c) A fourth notice (“In-Transit Final Notice”), which shall be sent twelve (12) hours prior to the ETA set forth in the In-Transit Third Notice (as corrected), confirming or amending such ETA. If, thereafter, such ETA changes by more than one (1) hour, Buyer shall give promptly, or cause the master of the LNG Tanker to give promptly, to Seller notice of the corrected ETA;

(d) Any other notice as required by the operator of the relevant liquefaction facility and/or port; and

(e) An NOR, which shall be given at the time prescribed in Section 7.10.

7.9.4 Buyer shall have the right to cause a LNG Tanker to burn Gas as fuel during operations at the Corpus Christi Facility (including while conducting cargo transfer operations). The quantity of Gas burned as fuel pursuant to this Section 7.9.4 shall be determined in accordance with Exhibit A. If Buyer exercises its right pursuant to this Section 7.9.4, all amounts of Gas burned as fuel shall be added to the quantity loaded included in Seller’s invoice pursuant to Section 10.1.1, but shall have no impact in respect of Buyer’s obligations under Section 5.

7.9.5 All vapor returned to Seller (or the operator of the LNG facility) during cool-down or loading operations may be used or disposed of by Seller (or the operator of the LNG facility) without compensation to Buyer. For the avoidance of doubt, the number of MMBtus sold and delivered in respect of any cargo shall be determined in accordance with Section 13.9.

7.10 Notice of Readiness

7.10.1 The master of an LNG Tanker arriving at the Corpus Christi Facility (or alternate source, as applicable), or such master’s agent, shall give to Seller its NOR for loading upon arrival of such LNG Tanker at the PBS; provided that, in order for such NOR to be considered valid, such LNG Tanker must have, at the time of such NOR issuance, all required Approvals from the relevant Governmental Authorities, and be ready, willing, and able, to proceed to berth and load LNG or to commence cool-down operations (as applicable).

7.10.2 A valid NOR given under Section 7.10.1 shall become effective as follows:

(a) For an LNG Tanker arriving at the PBS at any time prior to the Delivery Window allocated to such LNG Tanker, a valid NOR shall

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be deemed effective at the earlier of (i) the time at which the LNG Tanker is all fast at the berth; and (ii) the later of (A) 6:00 a.m. Central Time on such Delivery Window, and (B) six (6) hours after the time of its issuance;

(b) For an LNG Tanker arriving at the PBS at any time during the Delivery Window allocated to such LNG Tanker, a valid NOR shall become effective six (6) hours after the time of its issuance; or

(c) For an LNG Tanker arriving at the PBS at any time after the expiration of the Delivery Window, a valid NOR shall become effective only once the LNG Tanker is all fast at the berth.

7.11 Berthing Assignment

7.11.1 Seller shall berth an LNG Tanker which has tendered a valid NOR before or during its Delivery Window promptly after Seller and the operator of the relevant LNG facility determine such LNG Tanker will not interfere with berthing and loading or unloading of any other scheduled LNG vessel with a higher berthing priority but in no event later than the end of the Delivery Window allocated to such LNG Tanker; provided, however, that if Seller does not berth such LNG Tanker by the end of the Delivery Window, but berths such LNG Tanker within seventy-two (72) hours after the end of its Delivery Window, Buyer’s sole recourse and remedy for Seller’s failure to berth the LNG Tanker by the end of the Delivery Window is demurrage pursuant to Section 7.12.3, payment for excess boil-off pursuant to Section 7.12.4 and provision by Seller of a cool-down pursuant to Section 7.16.1(b). If, as of the seventy-second (72^nd) hour after the end of the Delivery Window, Seller has not berthed the LNG Tanker, and such delay is not attributable to a reason that would result in an extension of Allotted Laytime under Section 7.12.1, Seller shall be deemed to have failed to make the Scheduled Cargo Quantity of the relevant cargo available for delivery and the provisions of Section 5.5.2 shall apply.

7.11.2 For each delivery window period, Seller shall determine the berthing priority among LNG vessels which have tendered valid NOR before or during their scheduled delivery window as follows:

(a) The first berthing priority for a delivery window period shall be for an LNG vessel scheduled for such delivery window period. Priority within this group shall be given to the LNG vessel which has first tendered its valid NOR. Once an LNG vessel achieves a first berthing priority pursuant to this Section 7.11.2(a) or 7.11.2(b), such LNG vessel shall maintain such priority until such LNG vessel is berthed, so long as its tendered NOR remains valid; and

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(b) The second berthing priority for a delivery window period shall be for an LNG vessel scheduled for arrival after such delivery window period. Priority within this group shall be given to the LNG vessel which has first tendered its valid NOR. An LNG vessel with second berthing priority pursuant to this Section 7.11.2(b) will achieve a first berthing priority on its scheduled delivery window pursuant to Section 7.11.2(a) if such LNG vessel has not been berthed prior to such date, so long as its tendered NOR remains valid.

7.11.3 If an LNG Tanker tenders valid NOR after the end of its Delivery Window, Seller shall use reasonable efforts to berth such LNG Tanker as soon as reasonably practical; provided, however, that, unless otherwise agreed with Buyer, Seller shall have no obligation to use such efforts to berth an LNG Tanker that tenders NOR more than seventy-two (72) hours after the end of its Delivery Window. If, as of the seventy-second (72^nd) hour after the end of the Delivery Window, the LNG Tanker has not tendered a valid NOR, and such delay is not attributable to a reason that would result in an extension of allowed berth time under Section 7.14.2(b), Buyer shall be deemed to have failed to take delivery of the Scheduled Cargo Quantity of the relevant cargo and the entire Scheduled Cargo Quantity shall be considered DQ.

7.12 Berth Laytime

7.12.1 The allotted laytime for each LNG Tanker (“Allotted Laytime”) shall be determined in accordance with the following formula:

36 + x = Allotted Laytime (in hours)

where:

x = y/12,000 Cubic Meters; and

y = the LNG cargo containment capacity of the LNG Tanker minus one hundred forty thousand (140,000) Cubic Meters), provided that “y” shall be no less than zero (0).

Allotted Laytime shall be extended by any period of delay that is caused by:

(a) (i) reasons attributable to Buyer, a Governmental Authority, Transporter, the LNG Tanker or its master, crew, owner or operator; and (ii) reasons attributable to any Third Party outside of the reasonable control of Seller;

(b) Force Majeure or Adverse Weather Conditions;

(c) unscheduled curtailment or temporary discontinuation of operations at the Corpus Christi Facility (or alternate source, as applicable)

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necessary for reasons of safety, except to the extent such unscheduled curtailment or temporary discontinuation of operations is due to Seller’s failure to operate and maintain its facilities as a Reasonable and Prudent Operator;

(d) time at berth during cool-down pursuant to Section 7.16.1; and

(e) nighttime transit restrictions.

7.12.2 The actual laytime for each LNG Tanker (“Actual Laytime”) shall commence when the NOR is effective and shall end when (i) the LNG transfer and return lines of the LNG Tanker are disconnected from the Corpus Christi Facility’s (or alternate source’s, as applicable) LNG transfer and return lines, (ii) the cargo documents are on board of the LNG Tanker and (iii) the LNG Tanker is cleared for departure and able to depart.

7.12.3 In the event Actual Laytime exceeds Allotted Laytime (including any extension in accordance with Section 7.12.1) (“Demurrage Event”), Seller shall pay to Buyer as liquidated damages demurrage in USD (which shall be prorated for a portion of a Day) at a rate of USD seventy-five thousand (US$75,000) per Day. If a Demurrage Event occurs, Buyer shall invoice Seller for such demurrage within one hundred eighty (180) Days pursuant to Section 10.1.3.

7.12.4 If an LNG Tanker is delayed in berthing at the Corpus Christi Facility (or alternate source, as applicable) and/or commencement of LNG transfer due to an event occurring at the Corpus Christi Facility (or alternate source, as applicable) and for a reason that would not result in an extension of Allotted Laytime under Section 7.12.1, and if, as a result thereof, the commencement of LNG transfer is delayed beyond twenty-four (24) hours after NOR is effective, then, for each full hour by which commencement of LNG transfer is delayed beyond such twenty-four (24) hour period, Seller shall pay Buyer as liquidated damages an amount, on account of excess boil-off, equal to GCM (calculated in accordance with Section 9.1.1 as if such cargo had been made available in the Delivery Month) for such cargo multiplied by a quantity (in MMBtu) equal to zero decimal zero zero three three three percent (0.00333%) of the cargo containment capacity of such LNG Tanker; provided that in no event shall the quantity of MMBtu used in the calculation of this Section 7.12.4 exceed the quantity of LNG on board the LNG Tanker at the time it issued its valid NOR. Buyer shall invoice Seller for such excess boil-off within one hundred eighty (180) Days after the applicable event pursuant to Section 10.1.3.

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7.13 LNG Transfers at the Loading Facility

7.13.1 Seller shall cooperate with Transporters (or their agents) and with the master of each LNG Tanker to facilitate the continuous and efficient transfer of LNG hereunder.

7.13.2 During LNG transfer, Seller shall cause the operator of the LNG facility to provide or take receipt of (as applicable), through the facility’s vapor return line, Gas in such quantities as are necessary for the safe transfer of LNG at such rates, pressures and temperatures as may be required by the design of the LNG Tanker.

7.13.3 Promptly after completion of loading of each cargo, Seller shall send to Buyer a certificate of origin, together with such other documents concerning the cargo as may reasonably be requested by Buyer.

7.13.4 Buyer, in cooperation with Seller, shall cause the LNG Tanker to depart safely and expeditiously from the berth upon completion of LNG transfer.

7.14 LNG Tanker Not Ready for LNG Transfer; Excess Laytime

7.14.1 If any LNG Tanker previously believed to be ready for LNG transfer is determined to be not ready after being berthed, the NOR shall be invalid, and Seller (or the LNG facility’s operator) may direct the LNG Tanker’s master to vacate the berth and proceed to anchorage, whether or not other LNG vessels are awaiting the berth, unless it appears reasonably certain to Seller (and the LNG facility’s operator) that such LNG Tanker can be made ready without disrupting the overall berthing schedule of the Corpus Christi Facility (or alternate source, as applicable) or operations of the Corpus Christi Facility (or alternate source, as applicable). When an unready LNG Tanker at anchorage becomes ready for LNG transfer, its master shall notify Seller. If, as a result of such LNG Tanker’s not being ready to load, Buyer fails to take a cargo, the entire Scheduled Cargo Quantity shall be considered DQ.

7.14.2 The following shall apply with respect to berthing:

(a) An LNG Tanker shall complete LNG transfer and vacate the berth as soon as possible but not later than the end of its allowed laytime. An LNG Tanker’s allowed laytime shall commence when such LNG Tanker is all fast at the berth and shall end a number of consecutive hours thereafter determined in accordance with the following formula:

24 + x = allowed laytime (in hours)

where:

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x = y/12,000 Cubic Meters; and

y = the LNG cargo containment capacity of the LNG Tanker minus one hundred forty thousand (140,000) Cubic Meters, provided that “y” shall be no less than zero (0).

(b) Notwithstanding the foregoing, the allowed laytime shall be extended for: (i) reasons attributable to Seller or the operator of the Corpus Christi Facility (or alternate source, as applicable); (ii) reasons attributable to a Governmental Authority outside of the reasonable control of Buyer or the Transporter; (iii) reasons attributable to any Third Party outside of the reasonable control of Buyer or the Transporter; (iv) time at berth during any cool-down pursuant to Section 7.16.1; (v) unscheduled curtailment or temporary discontinuation of operations at the Corpus Christi Facility (or alternate source, as applicable) necessary for reasons of safety, except to the extent attributable to Buyer or Transporter; (vi) Force Majeure; and (vii) nighttime transit restrictions.

(c) If an LNG Tanker fails to depart at the end of its allowed laytime (as extended pursuant to Section 7.14.2(b)), another LNG vessel is awaiting the berth and the LNG Tanker’s continued occupancy of the berth will disrupt the overall berthing schedule of the Corpus Christi Facility (or alternate source, as applicable) or operations of the Corpus Christi Facility (or alternate source, as applicable), Seller (or the LNG facility’s operator) may direct the LNG Tanker to vacate the berth and proceed to sea at utmost dispatch.

(d) If an LNG Tanker fails to depart the berth at the end of its allowed laytime (as extended pursuant to Section 7.14.2(b)) and as a result the subsequent LNG vessel is prevented from or delayed in loading or unloading, Buyer shall reimburse Seller for any and all actual documented demurrage or excess boil-off that Seller becomes contractually obligated to pay to any Third Party with respect to such subsequent LNG vessel, as a result of the LNG Tanker not completing LNG transfer and vacating the berth as required by this Section 7.14.2; provided that Buyer shall not be required to reimburse Seller for any amounts based on a demurrage rate or excess boil-off rate or price in excess of the amounts specified in Section 7.12.3 and Section 7.12.4, as applicable. Seller shall invoice Buyer for any amounts due under this Section 7.14.2(d) pursuant to Section 10.1.3 within one hundred eighty (180) Days after the relevant Delivery Window.

(e) In the event an LNG Tanker fails to vacate the berth pursuant to this Section 7.14 and Buyer is not taking actions to cause it to vacate the

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berth, Seller (or the LNG facility’s operator) may effect such removal at the expense of Buyer.

7.15 Cooperation

7.15.1 If any circumstance occurs or is foreseen to occur so as to cause delay to an LNG Tanker or any other LNG vessel in berthing, loading, unloading or departing, Buyer and Seller shall, without prejudice to any other provision of this Agreement, discuss the problem in good faith with each other and, if appropriate, with other users of the Loading Port, and the Parties shall use reasonable efforts to minimize or to avoid the delay, and at the same time shall cooperate with each other and with such other users of the Loading Port, as appropriate, to find countermeasures to minimize or to avoid the occurrence of any similar delay in the future.

7.15.2 With respect to an LNG Tanker scheduled to load a cargo at the Corpus Christi Facility (or alternate source, as applicable), if such LNG Tanker is unable to berth at the Corpus Christi Facility (or alternate source, as applicable) within forty-eight (48) hours after the end of its Delivery Window solely due to a Force Majeure event, then the relevant cargo shall be cancelled, to the extent affected; provided, however, that if requested by Buyer or Seller, each Party shall use reasonable efforts to agree to changes to the ADP or Ninety Day Schedule in order to maximize the safe, reliable and efficient usage of the Corpus Christi Facility (or alternate source, as applicable).

7.16 Cool-Down of LNG Tankers

7.16.1 Buyer shall be solely responsible for ensuring that each LNG Tanker elected by Buyer for taking a cargo arrives at the Corpus Christi Facility (or alternate source, as applicable) cold and in a state of readiness. Notwithstanding the foregoing and subject to Section 7.16.2, with respect to any cargo scheduled to load hereunder at the Corpus Christi Facility:

(a) Seller shall use reasonable efforts (taking into account, among other things, availability of sufficient berth time and whether such requested cool-down is operationally feasible) to accept Buyer’s request to provide cool-down service for any LNG Tanker, subject to Buyer requesting such cool-down service by notice to Seller no less than thirty (30) Days before the relevant cargo’s Delivery Window; and

(b) Seller shall provide cool-down service to any LNG Tanker requiring cool-down solely as a result of a delay caused by Seller, but only if such LNG Tanker made no other call between the original Delivery Window and the requested cool-down time, provided that if Seller

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provides a cool-down under this Section 7.16.1(b), Seller shall have no obligation to pay Buyer in respect of excess boil-off pursuant to Section 7.12.4.

7.16.2 The following shall apply to any cool-down service provided by Seller pursuant to Section 7.16.1:

(a) all LNG provided by Seller for cooling LNG Tankers shall be sold, delivered and invoiced by Seller, and paid for by Buyer, at a price equal to GCM (calculated in accordance with Section 9.1.1 as if such cargo had been made available in the Delivery Month);

(b) the MMBtu content of the total liquid quantities delivered for cooling, measured before evaporation (without deduction of the quantity of vapor returned from the LNG Tanker), shall be determined by reference to the relevant LNG Tanker’s cool-down tables;

(c) the Parties will determine by mutual agreement the rates and pressures for delivery of LNG for cool-down, but always in full accordance with safe operating parameters and procedures mutually established and agreed by both the LNG Tanker and the Corpus Christi Facility; and

(d) LNG provided during cool down by Seller pursuant to Section 7.16.1 shall not be applied against the Scheduled Cargo Quantity for the relevant cargo.

8. Annual Delivery Program

8.1 Programming Information

8.1.1 No later than one hundred seventy (170) Days before the start of each Contract Year, Seller shall provide Buyer with Seller’s good faith estimate of the Gross Heating Value of LNG to be delivered during the coming Contract Year.

8.1.2 No less than one hundred twenty (120) Days before the start of each Contract Year, Buyer shall notify Seller of Buyer’s proposed schedule of receipt of cargoes for each Month of such Contract Year. Such schedule shall be on a reasonably even and ratable basis in accordance with Section 5.1.3, and Buyer’s notice shall include the following information:

(a) the LNG Tanker (if known) for each proposed cargo;

(b) the proposed Delivery Window for each cargo, provided that Buyer shall propose a total of twelve (12) cargoes each Contract Year with one (1) Delivery Window occurring in each Month;

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(c) the Scheduled Cargo Quantity for each cargo, which shall be three million seven hundred two thousand eight hundred ninety-nine (3,702,899) MMBtus;

(d) the anticipated Discharge Terminal for each proposed cargo, subject to Section 26.1; and

(e) any other information that may affect annual scheduling.

Buyer shall also inform Seller of any anticipated periods for maintenance to be conducted with respect to the LNG Tankers identified in (a) above.

8.1.3 Seller will then notify Buyer no less than seventy-five (75) Days before the start of such Contract Year of Seller’s proposed schedule of cargoes to be made available in each Month of such Contract Year, exercising reasonable efforts to adopt Buyer’s proposed schedule of receipts requested in accordance with Section 8.1.2 and such schedule shall be on a reasonably even and ratable basis in accordance with Section 5.1.3, subject to any exercise of Major Scheduled Maintenance Quantities by Seller; provided that if Buyer fails to deliver the notice in accordance with Section 8.1.2, Seller may nevertheless propose a schedule according to the terms of this Section 8.1.3. Such notice shall include the following information:

(a) the AACQ for the Contract Year;

(b) the Major Scheduled Maintenance Quantity (if any) for the Contract Year, including identification of the cargo being removed from the schedule;

(c) for each cargo (to avoid doubt, other than any cargo removed by Seller as a result of a Major Scheduled Maintenance Quantity election):

(i) the LNG Tanker (if specified by Buyer);

(ii) the Scheduled Cargo Quantity, which shall be three million seven hundred two thousand eight hundred ninety-nine (3,702,899) MMBtus;

(iii) the proposed Delivery Window;

(iv) the LNG facility at which the relevant cargo is to be loaded; and

(v) the Discharge Terminal specified in the notice sent by Buyer pursuant to Section 8.1.2, subject to such Discharge Terminal complying with Section 26.1; and

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(d) any other information that may affect annual scheduling.

8.2 Determination of Annual Delivery Program

8.2.1 Not later than five (5) Days after receipt of Seller’s proposed schedule provided under Section 8.1.3, Buyer shall notify Seller if Buyer desires to consult with Seller regarding the proposed schedule, and Seller shall, no later than fifteen (15) Days after receipt of Buyer’s notice, meet and consult with Buyer.

8.2.2 If, prior to the date that is fifty-five (55) Days before the start of the coming Contract Year, the Parties have agreed on a schedule of deliveries for such coming Contract Year, then Seller shall issue the delivery schedule agreed by the Parties. If the Parties are unable to agree on a schedule of deliveries for the coming Contract Year, then not later than fifty-five (55) Days before the start of such Contract Year, Seller shall issue the delivery schedule for such Contract Year containing the information set forth in Section 8.1.3, modified to reflect any changes agreed by the Parties pursuant to Section 8.2.1. The schedule promulgated by Seller shall reflect the exercise of reasonable efforts by Seller to assign to Buyer Delivery Windows that are as close as reasonably practicable to the Delivery Windows proposed by Buyer (subject to such Delivery Windows proposed by Buyer being in compliance with the provisions of Section 8.1.2). In assigning Delivery Windows, Seller shall have the right to give priority to the requests of Foundation Customers and all other customers with contractual priority over the requests of other customers including Buyer.

8.2.3 The schedule for deliveries of LNG during the Contract Year established pursuant to this Section 8.2, as amended from time to time in accordance with Section 8.3, is the “Annual Delivery Program” or “ADP”. If Seller fails to issue the schedule provided for in Section 8.1.3 or Section8.2.2, if applicable, then the schedule proposed by Buyer under Section 8.1.2 shall be the ADP for the relevant Contract Year.

8.2.4 Notwithstanding the foregoing provisions of Section 8.1 and Section 8.2, the ADP for the First Contract Year shall be agreed upon by the Parties no later than five (5) days after the Effective Date.

8.3 Changes to Annual Delivery Program

8.3.1 Subject to Section 8.3.4, either Party may request by notice a change in the ADP or Ninety Day Schedule for a Contract Year for any reason. Each Party shall use reasonable efforts to accommodate any such change requested by the other Party; provided, however that neither Party shall be under any obligation to consent thereto if such change results in a change to any Delivery Window or the Scheduled Cargo Quantity.

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8.3.2 Buyer shall have the right at any time to: (a) nominate an alternate LNG Tanker for a cargo subject to such LNG Tanker complying with the requirements of this Agreement and (b) nominate an alternate Discharge Terminal for a cargo subject to such Discharge Terminal complying with Section 26.1. If the gross volumetric capacity of the alternate LNG tanker nominated by Buyer pursuant to the foregoing is not sufficient to load the Scheduled Cargo Quantity of the relevant cargo, then, upon such nomination, the portion of the Scheduled Cargo Quantity that cannot be loaded onto such alternate LNG Tanker shall be considered DQ and the Scheduled Cargo Quantity shall be reduced accordingly.

8.3.3 With respect to any cargo(es) scheduled in the ADP or Ninety Day Schedule, Seller may, at any time, change the LNG facility (and associated Loading Port) at which the relevant cargo is to be loaded to:

(a) the Sabine Pass Facility, Corpus Christi Facility or any other LNG loading facility located in the U.S. Gulf Coast, subject to: (i) providing notice thereof to Buyer no less than ten (10) Days prior to the beginning of the relevant cargo’s Delivery Window; and (ii) in the case of any LNG facility other than the Sabine Pass Facility and the Corpus Christi Facility, confirmation of ship-shore compatibility by Buyer; or

(b) subject to the prior written consent of Buyer (such consent not to be unreasonably withheld or delayed), any LNG loading facility located outside the U.S. Gulf Coast.

8.3.4 Any change to the ADP or Ninety Day Schedule shall not: (a) unless expressly agreed otherwise by both Parties in such amended ADP or Ninety Day Schedule, affect the obligations pursuant to Section 5 of the Party requesting such change; or (b) result in unreasonably unratable deliveries at any time during a Contract Year (when compared to the ADP originally issued for such Contract Year).

8.3.5 Upon a change to the Delivery Window or Scheduled Cargo Quantity for a cargo, the ADP and/or Ninety Day Schedule shall be amended accordingly and an updated ADP and/or Ninety Day Schedule shall promptly be provided in writing by Seller to Buyer.

8.4 Ninety Day Schedule

No later than the twenty-fifth (25^th) Day of each Month, Seller shall issue a forward plan of deliveries for the three (3)-Month period commencing on the first Day of the following Month thereafter (e.g., the Ninety Day Schedule for the three (3)-Month period commencing on May 1^st shall be issued no later than the twenty-fifth (25^th) Day of April) (such plan, as amended from time to time in accordance with

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procedures set forth in this Agreement, the “Ninety Day Schedule”). The Ninety Day Schedule shall set forth by cargo the forecast pattern of deliveries, including the Delivery Window, LNG loading facility, LNG Tanker and Scheduled Cargo Quantity for each cargo. In the absence of agreement between the Parties otherwise, the Ninety Day Schedule will maintain the Scheduled Cargo Quantities and Delivery Windows as identified in the Annual Delivery Program.

9. Contract Sales Price

9.1 Contract Sales Price

9.1.1 The payment (expressed in USD, the “Cargo Payment”) for each cargo made available by Seller to Buyer shall be as follows:

Cargo Payment = ((DSCQ - AQ) x GSA CSP) + (AQ x Alternative CSP) + (EQ x GCMA) - (DQ x Alternative CSP)

where:

Alternative CSP = 1.15 x HH;

GCM = the price (in USD per MMBtu) published by Platts for the relevant date in ‘Platts LNG Daily’ under the heading ‘Platts Daily LNG Markers ($/MMBtu)’, subheading ‘FOB Gulf Coast Marker (GCM)’, reference ‘GCM (Month ‘m’)’, where Month ‘m’ is the Month in which the relevant cargo’s Delivery Window is scheduled to begin;

GCM Pricing Date = each Day within the applicable GCM Pricing Period that GCM is published by the publication agency;

GCM Pricing Period = the Month that is one (1) Month prior to the Month in which the relevant cargo’s Delivery Window is scheduled to begin;

GCMA = the greater of (a) the arithmetic average of the GCM for each GCM Pricing Date and (b) the Alternative CSP; and

GSA CSP = (1.15 x (CP-A - α)) + FLF; where “CP-A”, “α” and “FLF” are each as defined in the GSA, provided that “n” as used in the GSA shall be defined as the relevant Pricing Month.

9.1.2 If more than one (1) cargo is scheduled for delivery in any Month in a given ADP or Ninety Day Schedule, then in respect of each such cargo other than one (1) such cargo, Seller will nominate a Month as the Pricing Month for

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such cargo(es) such that each cargo scheduled for delivery in such ADP or Ninety Day Schedule has a unique Pricing Month.

9.1.3 Alternative Quantity

If a GSA Event occurs, Seller shall have the right to change the price applicable to all or a portion of the Affected Quantity to the Alternative CSP. In such case, Seller shall notify Buyer of the portion of the Affected Quantity to which such alternative price applies (an “Alternative Quantity”), and in relation to the Alternative Quantity only, Seller shall forfeit its right to claim Force Majeure based on the GSA Event.

10. Invoicing and Payment

10.1 Invoices

10.1.1 Invoices for Cargoes. Invoices for each cargo made available by Seller and taken by Buyer, together with relevant supporting documents including a certificate of quantity loaded, shall be prepared and delivered by Seller to Buyer promptly following each Delivery Window and receipt of the final inspection certificate applicable to the loading of such cargo. The invoice amount shall be the Cargo Payment (for the avoidance of doubt, the quantity of MMBtus taken by Buyer for the purposes of calculating the Cargo Payment shall be determined in accordance with Section 13.9). If Buyer fails to take a cargo made available by Seller, the entire Scheduled Cargo Quantity shall be considered DQ and Seller shall prepare and deliver to Buyer an invoice for such cargo promptly following such failure to take.

10.1.2 Invoices for Cargo DoP Payments. Invoices for Cargo DoP Payments owed to Buyer by Seller shall be prepared by Buyer and delivered to Seller promptly following the Delivery Window of each affected cargo and completion of mitigation efforts.

10.1.3 Invoices for Various Sums Due. In the event that any sums are due from one Party to the other Party under Section 7.5.4(b), 7.12.3, 7.12.4, 7.14.2(d), 7.16.1, 10.3.3, 10.4.1, 11.5, 12.3.1(c), or 12.3.2(a) of this Agreement, the Party to whom such sums are owed shall furnish an invoice therefor, describing in reasonable detail the basis for such invoice and providing relevant documents supporting the calculation thereof.

10.1.4 Invoices for Other Sums Due. In the event that any sums are due from one Party to the other Party under this Agreement, other than for a reason addressed in Section 10.1.1 through 10.1.3, the Party to whom such sums are owed shall furnish an invoice therefor, describing in reasonable detail the basis for such invoice and providing relevant documents supporting the calculation thereof.

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10.1.5 Notice. Invoices shall be sent in accordance with Section 25.

10.1.6 Provisional Invoices.

(a) In the event (i) a rate or index used in the calculation of an amount is not available on a temporary or permanent basis; or (ii) any other relevant information necessary to compute an invoice is not available, the invoicing Party may issue a provisional invoice (“Provisional Invoice”) in an amount calculated, in the case of subsection (i) of this Section 10.1.6(a), in accordance with Section 1.3, and, in the case of subsection (ii) of this Section 10.1.6(a), based on the best estimate of the unavailable information by the Party issuing the Provisional Invoice or, in the case of a cargo delivered prior to the end of such cargo’s applicable Pricing Period (as defined in the GSA), based on a Pricing Period calculated to end in the Month of the actual delivery of such cargo. In the event a Provisional Invoice is to be issued because the certificate of quantity loaded is not available because such LNG’s loaded quality has not yet been determined, then Seller shall use the average loaded quality data for the two (2) cargoes loaded at the Corpus Christi Facility (whether delivered to Buyer or another customer) immediately preceding the relevant cargo. A Provisional Invoice shall be deemed to be an invoice issued pursuant to Section 10.1.1 and Section 10.1.2, as applicable, for the purposes of the payment obligations of Seller or Buyer, as applicable, and shall be subject to subsequent adjustment in accordance with Section 10.1.6(b).

(b) If a Provisional Invoice has been issued, the invoicing Party shall issue a final invoice reflecting any credit or debit, as applicable, to the Provisional Invoice as soon as reasonably practicable after the information necessary to compute the payment has been obtained by such Party. Seller and Buyer shall settle such debit or credit amount, as the case may be, when payment of the next invoice is due pursuant to Section 10.2 or, if earlier, upon the termination of this Agreement.

10.2 Payment

All amounts invoiced under this Agreement that are due and payable shall be paid in accordance with this Section 10.2.

10.2.1 Payments for Cargoes. Invoices issued in accordance with Section 10.1.1 for cargoes made available shall become due and payable by Buyer on the Payment Due Date. “Payment Due Date” means in respect of the relevant invoice, the date that is two (2) Business Days prior to the payment due date applicable to the Delivery Month under the GSA. For example, if the GSA payment due date for March 2020 is April 25, 2020, the Payment Due Date

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applicable to a cargo with a March 2020 Delivery Month will be two (2) Business Days prior to April 25, 2020. Seller will notify Buyer of the Payment Due Date in respect of each invoice issued under Section 10.1.1.

10.2.2 Cargo DoP Payments. Invoices issued in accordance with Section 10.1.2 shall become due and payable on the tenth (10^th) Day following receipt by Seller.

10.2.3 Payments for Other Sums Due. An invoice issued pursuant to Section 10.1.3 or 10.1.4 shall be paid by the paying Party thereunder not later than twenty (20) Days after receipt of such invoice.

10.2.4 Payment Method. All invoices shall be settled by payment in USD of the sum due by wire transfer of immediately available funds to an account with the bank designated by the other Party in accordance with Section 10.2.5.

10.2.5 Designated Bank. Each Party shall designate a bank in a location reasonably acceptable to the other Party for payments under this Agreement. A Party shall designate its bank by notice to the other Party initially not later than the Start Date and thereafter not less than thirty (30) Days before any redesignation is to be effective.

10.2.6 Payment Date. If any invoice issued pursuant to Section 10.1 would result in a Party being required to make a payment on a Day that is not a Business Day, then the due date for such invoice shall be the immediately succeeding Business Day; provided, however, that in no event shall any invoice be due less than five (5) Business Days after receipt of the invoice by the Party being required to make a payment.

10.3 Disputed Invoice

10.3.1 Payment Pending Dispute. Absent manifest error, each Party invoiced pursuant to Section 10.1.1, 10.1.2, or 10.1.3 shall pay all disputed and undisputed amounts due under such invoice without netting or offsetting any amounts owed by the Party receiving the invoice, including taxes (except as provided in Section 11.4), exchange charges, or bank transfer charges. In the case of manifest error, the correct amount shall be paid disregarding such error, and necessary correction and consequent adjustment shall be made within five (5) Business Days after agreement or determination of the correct amount.

10.3.2 Timing. Except with respect to Sections 1.3, 10.3.4, and 14, any invoice may be contested by the receiving Party only pursuant to Section 10.5 or if, within a period of thirteen (13) Months after its receipt thereof, that Party serves notice to the other Party questioning the correctness of such invoice.

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Subject to Section 10.5, if no such notice is served, the invoice shall be deemed correct and accepted by both Parties.

10.3.3 Interest. The Party who invoiced and received payment of a sum, subsequently determined not to have been payable under this Agreement to such Party, shall pay interest to the other Party on such amount, at a rate per annum equal to two percent (2%) above LIBOR (as in effect on the Day when such sum was originally paid) on and from the Day when such sum was originally paid until the date of its repayment, provided that, without prejudice to the other terms of this Agreement, if such period lasts longer than ninety (90) Days, the applicable LIBOR rate for each successive term of ninety (90) Days during that period shall be that in effect on the first Day of that ninety (90) Day period. Interest shall accrue from Day to Day and be calculated on the basis of a three hundred sixty (360) Day year.

10.3.4 Measurement or Analyzing Errors. Any errors found in an invoice or credit note which are caused by the inaccuracy of any measuring or analyzing equipment or device shall be corrected in accordance with Exhibit A, as applicable, and shall be settled in the same manner as is set out above in this Section 10.3.

10.4 Delay in Payment

10.4.1 Interest. If either Seller or Buyer fails to make payment of any sum as and when due under this Agreement, it shall pay interest thereon to the other Party at a rate per annum equal to two percent (2%) above LIBOR (as in effect on the Day when such sum was originally due) on and from the Day when payment was due until the date of payment, provided that, without prejudice to the other terms of this Agreement, if such period lasts longer than ninety (90) Days, the applicable LIBOR rate for each successive term of ninety (90) Days during that period shall be that in effect on the first Day of that ninety (90) Day period. Interest shall accrue from Day to Day and be calculated on the basis of a three hundred sixty (360) Day year.

10.4.2 Costs and Expenses. Subject to Section 21.1.12, each Party shall bear its own costs (including attorneys’ or Experts’ fees or costs) in respect of enforcement of such Party’s rights in any Dispute proceeding as a result of the other Party failing to perform or failing timely to perform its obligations under this Agreement including failing timely to make any payment in accordance with this Agreement.

10.5 Audit Rights

Each Party shall have the right to cause an independent auditor, appointed by such Party at such Party’s sole cost and expense, to audit the books, records and accounts of the other Party that are directly relevant to the determination of any amounts

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invoiced, charged, or credited by the other Party within the previous twelve (12) Months or as otherwise required by this Agreement. Such audit shall be conducted at the office where the records are located, during the audited Party’s regular business hours and on reasonable prior notice, and shall be completed within thirty (30) Days after the audited Party’s relevant records have been made available to the auditing Party. The independent auditor shall be a major international accountancy firm, and the Party appointing such auditor shall cause the auditor to execute a confidentiality agreement acceptable to the Party being audited. If the audit discloses an error in any invoiced amount under this Agreement, then the auditing Party shall, within thirty (30) Days following completion of the audit pertaining to the affected invoice or statement, provide notice to the audited Party describing the error and the basis therefor. Promptly thereafter, the Parties shall commence discussions regarding such error in order to expeditiously, and in good faith, achieve resolution thereof, provided that any adjustments arising from such audit shall be made and all credits or charges finalized within forty-five (45) Days of completion of any relevant audit.

10.6 Seller’s Right to Suspend Performance

If either (a) Seller has not received payment in respect of any amounts due under any invoice(s) under this Agreement totaling in excess of USD ten million (US$10,000,000) within two (2) Business Days after the due date thereof or (b) Buyer is in default under any financing agreement and the amount of debt associated with the relevant financing agreement(s) exceeds USD twenty-five million (US$25,000,000), then without prejudice to any other rights and remedies of Seller arising under this Agreement or by Applicable Laws or otherwise, upon giving notice to Buyer:

10.6.1 Seller may suspend delivering any or all subsequent cargoes until: (i) in the case of (a) above, the amounts outstanding under such invoice(s) and interest thereon have been paid in full; or (ii) in the case of (b) above, such default has been cured in its entirety and the underlying cause of such default has been addressed/remedied to Seller’s reasonable satisfaction.

10.6.2 In the event of such suspension, Buyer shall not be relieved of any of its obligations under this Agreement, including its obligation to take any LNG, and the entire Scheduled Cargo Quantity with respect to each cargo scheduled in the Annual Delivery Program or Ninety Day Schedule which is not delivered during the suspension shall be considered DQ.

10.6.3 During the period that such suspension is effective, Seller shall have no obligation to make available any cargoes to Buyer and shall be deemed to have made available such cargo for purposes of Section 9.1.1 and Section 10.1.1.

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10.7 Final Settlement

Within sixty (60) Days after expiration of the Term or the earlier termination of this Agreement, Seller and Buyer shall determine the amount of any final reconciliation payment. After the amount of the final settlement has been determined, Seller shall send a statement to Buyer, or Buyer shall send a statement to Seller, as the case may be, for amounts due under this Section 10.7, and Seller or Buyer, as the case may be, shall pay such final statement no later than twenty (20) Business Days after the date of receipt thereof.

11. Taxes

11.1 Responsibility

Buyer shall indemnify and hold Seller and its direct or indirect owners and Affiliates harmless from any and all Buyer Taxes, and Seller shall indemnify and hold Buyer and its Affiliates harmless from any and all Seller Taxes.

11.2 Seller Taxes

“Seller Taxes” means any taxes imposed from time to time:

(a) solely on account of the corporate existence of Seller or its Affiliates;

(b) in respect of the property, revenue, income, or profits of Seller or its Affiliates (other than taxes required to be deducted or withheld by Buyer from or in respect of any payments (whether in cash or in kind) under this Agreement);

(c) subject to Section 11.5, in the United States of America or any political subdivision thereof, that may be levied or assessed upon the sale, use or purchase of LNG up to and at the Delivery Point;

(d) in the United States of America or any political subdivision thereof, that may be levied or assessed upon the export, loading, storage, processing, transfer, transport, ownership of title, or delivery of LNG, up to and at the Delivery Point; and

(e) payable by Buyer by reason of a failure by Seller to properly deduct, withhold or pay any taxes described in Section 11.4.

11.3 Buyer Taxes

“Buyer Taxes” means any taxes imposed from time to time:

(a) solely on account of the corporate existence of Buyer or its Affiliates;

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(b) in respect of the property, revenue, income, or profits of Buyer or its Affiliates (other than taxes required to be deducted or withheld by Seller from or in respect of payments (whether in cash or in kind) under this Agreement);

(c) in the United States of America (or any political subdivision thereof) or in any jurisdiction in which any of Buyer’s Discharge Terminals are located (or any political subdivision thereof), or any jurisdiction through which any LNG Tanker transits or on which any LNG Tanker calls (or any political subdivision thereof), in each case that may be levied or assessed upon the sale, use, purchase, import, unloading, export, loading, storage, processing, transfer, transport, ownership of title, receipt or delivery of LNG after the Delivery Point; and

(d) payable by Seller by reason of a failure by Buyer to properly deduct, withhold or pay any taxes described in Section 11.4.

11.4 Withholding Taxes

If Seller or Buyer (in either case, the “Payor” for purposes of this Section 11.4), is required to deduct or withhold taxes from or in respect of any payments (whether in cash or in kind) to the other Party under this Agreement, then: (a) the Payor shall make such deductions and withholdings; (b) the Payor shall pay the full amount deducted or withheld to the appropriate Governmental Authority in accordance with Applicable Laws; (c) the Payor shall promptly furnish to the other Party the original or a certified copy of a receipt evidencing such payment; and (d) the sum payable by the Payor to the other Party shall be increased by such additional sums as necessary so that after making all required deductions and withholdings of taxes (including deductions and withholdings of taxes applicable to additional sums payable under this Section 11.4), the other Party receives an amount equal to the sum it would have received had no such deductions or withholdings of taxes been made.

11.5 Transfer Tax

In the event that the United States or any political subdivision thereof, including any state or local subdivision thereof, levies or assesses a value added tax, sales or use tax, or other transfer tax on the transfer of LNG pursuant to this Agreement, Seller shall remit such tax to the appropriate Governmental Authority and Buyer shall reimburse Seller for the amount of such tax. Pursuant to Section 10.1.3, Seller shall furnish Buyer with an invoice of the taxes required to be reimbursed to Seller. Buyer shall pay such invoice in accordance with Section 10.2.3. If Buyer claims an exemption from sales or use tax imposed by the Governmental Authority with respect to the transfer of LNG pursuant to this Agreement, Buyer shall provide documentation to Seller demonstrating its entitlement to such exemption under Applicable Laws. Buyer shall remain liable for sales and use taxes, including penalties and interest, imposed on Seller as a result of Buyer’s failure to qualify for

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an exemption claimed by Buyer. A properly executed resale or exemption certificate shall be deemed to be sufficient documentation demonstrating such exemption, except to the extent Buyer claims an import or export exemption, in which case Buyer shall provide any additional documentation required by Applicable Laws. For the avoidance of doubt, if the aforementioned documentation is provided by Buyer to Seller and Buyer has previously paid to Seller such tax, Seller must promptly refund such tax collected from Buyer, provided that Seller will not be required to refund any tax remitted to a Governmental Authority until Seller has received a refund of such tax from the Governmental Authority. Buyer shall remain liable for sales and use taxes, including penalties and interest, imposed on Seller as a result of Buyer’s failure to qualify for an exemption claimed by Buyer.

11.6 Mitigation

Each Party shall use reasonable efforts to take actions or measures requested by the other Party in order to minimize taxes for which the other Party is liable under this Section 11, including providing applicable sales and use tax resale or exemption certificates, provided that the other Party shall pay such Party’s reasonable costs and expenses in relation thereto.

11.7 Refunds

If a Party has made an indemnification payment to the other Party pursuant to this Section 11 with respect to any amount owed or paid by the indemnified Party and the indemnified Party thereafter receives a refund or credit of any such amount, such indemnified Party shall pay to the indemnifying Party the amount of such refund or credit promptly following the receipt thereof. The indemnified Party shall provide such assistance as the indemnifying Party may reasonably request to obtain such a refund or credit.

12. Quality

12.1 Specification

12.1.1 LNG delivered under this Agreement shall, when converted into a gaseous state, comply with the following specifications (“Specifications”):

Minimum Gross Heat Content (dry)     1000 BTU/SCF

Maximum Gross Heat Content (dry)    1150 BTU/SCF

Minimum methane (C1)    84.0 MOL%

Maximum H₂S    0.25 grains per 100 SCF

Maximum Sulfur    1.35 grains per 100 SCF

Maximum N₂    1.5 MOL%

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Maximum Ethane (C2)    11 MOL%

Maximum Propane (C3)    3.5 MOL%

Maximum Butane (C4) and heavier    2 MOL%

LNG shall contain no water, active bacteria or bacterial agents (including sulfate-reducing bacteria or acid producing bacteria) or other contaminants or extraneous material.

12.1.2 With respect to each cargo to be delivered to Buyer under this Agreement, Seller shall provide Buyer with a report indicating Seller’s best estimate of what the actual loaded quality composition of the LNG to be delivered to Buyer in such cargo is likely to be. Seller shall use reasonable efforts to provide such report as early as possible during the thirty (30) Day period immediately preceding the relevant cargo’s Delivery Window.

12.2 Determining LNG Specifications

LNG shall be tested pursuant to Exhibit A to determine whether such LNG complies with the Specifications.

12.3 Off-Specification LNG

12.3.1 If Seller, acting as a Reasonable and Prudent Operator, determines prior to loading a cargo that the LNG is expected not to comply with the Specifications (“Off-Spec LNG”) upon loading, then:

(a) Seller shall give notice to Buyer of the extent of the expected variance as soon as practicable (but in no case later than the commencement of loading of the cargo);

(b) Buyer shall use reasonable efforts, including coordinating with the Transporter and the operator of the Discharge Terminal, to accept such LNG where the LNG would be acceptable to the Transporter and the operator of the Discharge Terminal, each of them acting in their sole discretion (unless Transporter or such operator is Buyer or an Affiliate of Buyer, in which case Buyer shall cause such Person to use reasonable efforts to accept the LNG), and would not prejudice the safe and reliable operation of any LNG Tanker, the Discharge Terminal, and any downstream facilities being supplied regasified LNG;

(c) if Buyer can accept delivery of such cargo, then Buyer shall notify Seller of Buyer’s estimate of the direct costs to be incurred by Buyer, any Affiliate of Buyer, Transporter, and the operator of the Discharge Terminal in transporting and treating such Off-Spec LNG (or to

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otherwise make such LNG marketable), and, to the extent Seller agrees to such estimate, Buyer shall take delivery of such cargo, and Seller shall reimburse Buyer for all reasonable documented direct costs incurred by Buyer (including costs owed to any Affiliate of Buyer, Transporter, and the operator of the Discharge Terminal in transporting and treating such Off-Spec LNG (or to otherwise make such LNG marketable) prior to and at the Discharge Terminal), provided, however, that Seller’s liability shall not exceed one hundred twenty percent (120%) of the estimate notified by Buyer and agreed by Seller; and

(d) if (1) Buyer determines in good faith that it cannot, using reasonable efforts, receive such cargo, (2) Seller rejects the cost estimate or (3) Buyer anticipates that it might be liable for costs that would not otherwise be reimbursed pursuant to Section 12.3.1(c), then Buyer shall be entitled to reject such cargo by giving Seller notice of rejection within seventy-two (72) hours of Buyer’s receipt of Seller’s notice.

12.3.2 If Off-Spec LNG is delivered to Buyer without Buyer being made aware of the fact that such Off-Spec LNG does not comply with the Specifications, or without Buyer being made aware of the actual extent to which such Off-Spec LNG does not comply with the Specifications, then:

(a) if Buyer is able, using reasonable efforts, to transport and treat the Off-Spec LNG to meet the Specifications (or to otherwise make such LNG marketable), then Seller shall reimburse Buyer for all reasonable documented direct costs incurred by Buyer (including direct costs owed to any Affiliate of Buyer, Transporter, and the operator of the Discharge Terminal in transporting and treating such Off-Spec LNG received at the Discharge Terminal to meet the Specifications (or to otherwise make such LNG marketable)), in an amount not exceeding one hundred percent (100%) of the product of the delivered quantity of such Off-Spec LNG and GCM (calculated in accordance with Section 9.1.1 as if such cargo had been made available in the Delivery Month); provided, however, that Buyer, any Affiliate of Buyer, Transporter, and the operator of the Discharge Terminal shall not be required to incur costs in excess of those reimbursable by Seller; or

(b) if Buyer determines in good faith that it cannot, using reasonable efforts, transport and treat such Off-Spec LNG to meet the Specifications (or to make such LNG marketable) or the cost of transporting and treating Off-Spec LNG is estimated by Buyer, acting reasonably and in good faith, to exceed one hundred percent (100%)

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of the product of the quantity of Off-Spec LNG and GCM (calculated in accordance with Section 9.1.1 as if such cargo had been made available in the Delivery Month), then: (i) Buyer shall be entitled to reject such Off-Spec LNG by giving Seller notice of such rejection as soon as practicable, and in any case within ninety-six (96) hours after (A) Seller notifies Buyer in writing that such LNG is Off-Spec LNG and the actual extent to which such Off-Spec LNG does not comply with the Specifications or (B) Buyer becomes aware that such LNG is Off-Spec LNG, whichever occurs first; (ii) Buyer shall be entitled to dispose of the loaded portion of such Off-Spec LNG (or regasified LNG produced therefrom) in any manner that Buyer, acting in accordance with the standards of a Reasonable and Prudent Operator, deems appropriate; and (iii) Seller shall reimburse Buyer in respect of and indemnify and hold Buyer harmless from all direct loss, damage, costs and expenses incurred by Buyer, any Affiliate of Buyer, or Transporter as a result of the delivery of such Off-Spec LNG, including in connection with the handling, treatment or safe disposal of such Off-Spec LNG or other LNG being held at the Discharge Terminal or being carried onboard the LNG Tanker which was contaminated by it, cleaning or clearing the LNG Tanker and Discharge Terminal, and damage caused to the LNG Tanker and Discharge Terminal.

12.3.3 If Buyer rejects a quantity of LNG in accordance with Section 12.3.1(d) or 12.3.2(b), Seller shall be deemed to have failed to make available the rejected quantity of LNG and Section 5.5.2 shall apply.

13. Measurements and Tests

13.1 LNG Measurement and Tests

LNG delivered to Buyer, and Gas used as fuel by Buyer, pursuant to this Agreement shall be measured and tested in accordance with Exhibit A.

13.2 Parties to Supply Devices

13.2.1 Buyer shall supply, operate and maintain, or cause to be supplied, operated and maintained, suitable gauging devices for the LNG tanks of the LNG Tanker, as well as pressure and temperature measuring devices, in accordance with Section 13.3 and Exhibit A, and any other measurement, gauging or testing devices which are incorporated in the structure of such LNG Tanker or customarily maintained on shipboard.

13.2.2 Seller shall supply, operate and maintain, or cause to be supplied, operated and maintained, devices required for collecting samples and for determining quality and composition of the delivered LNG, in accordance with Section

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13.3 and Exhibit A, and any other measurement, gauging or testing devices which are necessary to perform the measurement and testing required hereunder at the Loading Port.

13.3 Selection of Devices

Each device provided for in this Section 13 shall be selected and verified in accordance with Exhibit A. Any devices that are provided for in this Section 13 not previously used in an existing LNG trade shall be chosen by written agreement of the Parties and shall be such as are, at the time of selection, accurate and reliable in their practical application. The required degree of accuracy of such devices shall be agreed in writing by Buyer and Seller in advance of their use, and such degree of accuracy shall be verified by an independent surveyor who is agreed by Buyer and Seller.

13.4 Tank Gauge Tables of LNG Tanker

Buyer shall furnish to Seller, or cause Seller to be furnished, a certified copy of tank gauge tables as described in Exhibit A for each LNG tank of the LNG Tanker and of tank gauge tables revised as a result of any recalibration of an LNG tank of an LNG Tanker.

13.5 Gauging and Measuring LNG Volumes Loaded

Volumes of LNG delivered under this Agreement will be determined by gauging the LNG in the LNG tanks of the LNG Tanker immediately before and after loading in accordance with the terms of Exhibit A.

13.6 Samples for Quality Analysis

Representative samples of the delivered LNG shall be obtained by Seller as provided in Exhibit A.

13.7 Quality Analysis

The samples referred to in Section 13.6 shall be analyzed, or caused to be analyzed, by Seller in accordance with the terms of Exhibit A, in order to determine the molar fractions of the hydrocarbons and components in the sample.

13.8 Operating Procedures

13.8.1 Prior to carrying out measurements, gauging and analyses hereunder, the Party responsible for such operations shall notify the designated representative(s) of the other Party, allowing such representative(s) a reasonable opportunity to be present for all operations and computations; provided, however, that the absence of such representative(s) after

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notification and reasonable opportunity to attend shall not affect the validity of any operation or computation thereupon performed.

13.8.2 At the request of either Party, any measurements, gauging and/or analyses provided for in Sections 13.5, 13.6 and 13.7 shall be witnessed and verified by an independent surveyor agreed upon in writing by Buyer and Seller. The results of verifications and records of measurement shall be maintained in accordance with the terms of Exhibit A.

13.9 MMBtu Quantity Delivered

The number of MMBtus sold and delivered shall be calculated at the Delivery Point by Seller and witnessed and verified by a mutually appointed independent surveyor agreed upon in writing by the Parties following the procedures set forth in Exhibit A.

13.10 Verification of Accuracy and Correction for Error

13.10.1 Each Party shall test and verify the accuracy of its devices at intervals to be agreed between the Parties. In the case of gauging devices of the LNG Tanker, such tests and verifications shall take place during each scheduled dry-docking, provided that the interval between such dry dockings shall not exceed five (5) years. Indications from any redundant determining devices should be reported to the Parties for verification purposes. Each Party shall have the right to inspect and if a Party reasonably questions the accuracy of any device, to require the testing or verification of the accuracy of such device in accordance with the terms of Exhibit A. At the request of either Party, any testing or verification provided for in this Section 13.10.1 shall be witnessed and verified by an independent surveyor agreed upon in writing by Buyer and Seller. The results of verifications shall be maintained in accordance with the terms of Exhibit A.

13.10.2 Permissible tolerances of the measurement, gauging and testing devices shall be as described in Exhibit A.

13.11 Costs and Expenses

13.11.1 Except as provided in this Section 13.11, all costs and expenses for testing and verifying measurement, gauging or testing devices shall be borne by the Party whose devices are being tested and verified; provided, however, that representatives of the Parties attending such tests and verifications shall do so at the cost and risk of the Party they represent.

13.11.2 In the event that a Party inspects or requests the testing/verification of any of the other Party’s devices on an exceptional basis in each case as provided

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in Section 13.10.1, the Party requesting the testing/verification shall bear all costs thereof.

13.11.3 The costs of the independent surveyor:

(a) requested by a Party in accordance with Section 13.10.1 shall be borne by the requesting Party; and

(b) requested by a Party in accordance with Section 13.8.2 or referred to in Section 13.9 shall be borne equally by Buyer and Seller.

14. Force Majeure

14.1 Force Majeure

Neither Party shall be liable to the other Party for any delay or failure in performance under this Agreement if and to the extent such delay or failure is a result of Force Majeure. To the extent that the Party so affected fails to use commercially reasonable efforts to overcome or mitigate the effects of such events of Force Majeure, it shall not be excused for any delay or failure in performance that would have been avoided by using such commercially reasonable efforts. Subject to the provisions of this Section 14, the term “Force Majeure” shall mean any act, event or circumstance, whether of the kind described herein or otherwise, that is not reasonably within the control of, does not result from the fault or negligence of, and would not have been avoided or overcome by the exercise of reasonable diligence by, the Party claiming Force Majeure or an Affiliate of the Party claiming Force Majeure, such Party and, as applicable, its Affiliate having observed a standard of conduct that is consistent with a Reasonable and Prudent Operator, and that prevents or delays in whole or in part such Party’s performance of one or more of its obligations under this Agreement.

Notwithstanding anything to the contrary contained in this Section 14, any GSA Event shall be deemed to qualify as Force Majeure and, in such case, Seller shall be entitled to claim Force Majeure hereunder, and be relieved of its obligations under this Agreement in respect of a quantity of LNG up to an amount equal to the Affected Quantity.

14.1.1 Force Majeure may include circumstances of the following kind, provided that such circumstances satisfy the definition of Force Majeure set forth above:

(a) acts of God, the government, or a public enemy; strikes, lockout, or other industrial disturbances; flood, lightning, storm, hurricane, tornado, earthquake, or subsidence;

(b) wars, blockades or civil disturbances of any kind, terrorism, acts of piracy, epidemics, Adverse Weather Conditions, fires, explosions,

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arrests and restraints of governments or people, and arrest or detention of an LNG Tanker;

(c) the breakdown or failure of, freezing of, breakage or accident to, or the necessity for making repairs or alterations to any facilities or equipment, including an LNG Tanker;

(d) in respect of Seller: (i) loss of, accidental damage to, or inaccessibility to or inoperability of (x) the Corpus Christi Facility or any Connecting Pipeline related thereto; or (y) any other LNG loading facility or any Connecting Pipeline related thereto, subject to Section 14.2.4; and (ii) any event that would constitute an event of force majeure under (A) any agreement to which Seller is a party that is necessary for Seller to carry out any obligations hereunder or (B) without limiting the foregoing, any agreement between Seller and the owner(s) or operator(s) of any Connecting Pipeline for Gas transportation services, provided however, that an event of force majeure affecting a party to any such agreement shall constitute Force Majeure under this Agreement only to the extent such event meets the definition of Force Majeure in this Section 14.1;

(e) in respect of Buyer, events affecting the ability of any LNG Tanker to receive and transport LNG, subject to Section 14.2.3; and

(f) the modification, withdrawal, denial, or expiration of, or failure to obtain, any Approval.

14.1.2 Nothing in this Section 14.1 shall be construed to require a Party to observe a higher standard of conduct than that required of a Reasonable and Prudent Operator as a condition to claiming the existence of Force Majeure.

14.2 Limitations on Force Majeure

14.2.1 Indemnity and Payment Obligations. Notwithstanding Section 14.1, no Force Majeure shall relieve, suspend, or otherwise excuse either Party from performing any obligation to indemnify, reimburse, hold harmless or otherwise pay the other Party under this Agreement.

14.2.2 Events Not Force Majeure. The following events shall not constitute Force Majeure:

(a) a Party’s inability to finance its obligations under this Agreement or the unavailability of funds to pay amounts when due in the currency of payment;

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(b) the unavailability of, or any event affecting, any facilities at or associated with any transit port or facilities, unloading port or Discharge Terminal;

(c) the ability of Seller or Buyer to obtain better economic terms for LNG or Gas from an alternative supplier or buyer, as applicable;

(d) changes in either Party’s market factors, default of payment obligations or other commercial, financial or economic conditions, including failure or loss of any of Buyer’s or Seller’s Gas or LNG markets;

(e) breakdown or failure of plant or equipment caused by normal wear and tear or by a failure to properly maintain such plant or equipment;

(f) the non-availability or lack of economically obtainable Gas reserves;

(g) in the case of Buyer, any event arising from an action or omission of Transporter, to the extent that, had Buyer taken such action or experienced such event, such event would not constitute Force Majeure pursuant to the provisions of this Section 14; and

(h) the loss of interruptible or secondary firm transportation service on a Connecting Pipeline or any pipeline upstream of a Connecting Pipeline unless the cause of such loss was an event that would satisfy the definition of Force Majeure hereunder and primary in-the-path transportation service on such pipeline was also interrupted as a result of such event.

14.2.3 Force Majeure relief in respect of Buyer for an event described in Section 14.1.1(e) affecting a specific LNG Tanker shall only be available with respect to cargoes that are scheduled to be transported on such LNG Tanker in the applicable Ninety Day Schedule or ADP for such Contract Year, or (to the extent that the ADP for the following Contract Year has been issued by Seller) in the ADP for the following Contract Year; provided, however, that Buyer shall not be entitled to claim Force Majeure relief for an event affecting the LNG Tanker nominated for such cargo if such LNG Tanker was affected by, or could reasonably have been expected to be affected by, such Force Majeure event at the time it was nominated by Buyer pursuant to Section 8.1.2 or Section 8.3, as applicable, for the relevant cargo.

14.2.4 Force Majeure relief in respect of Seller for an event described in Section 14.1.1(d)(i)(y) affecting an LNG loading facility or Connecting Pipeline other than the Corpus Christi Facility and any Connecting Pipeline related thereto shall only be available with respect to cargoes that are scheduled to be loaded at such LNG loading facility in the applicable Ninety Day

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Schedule or ADP for such Contract Year, or (to the extent that the ADP for the following Contract Year has been issued by Seller) in the ADP for the following Contract Year.

14.3 Notification

A Force Majeure event shall take effect at the moment such an event or circumstance occurs. Upon the occurrence of a Force Majeure event that prevents, interferes with or delays the performance by Seller or Buyer, in whole or in part, of any of its obligations under this Agreement, the Party affected shall give notice thereof to the other Party describing such event and stating the obligations the performance of which are affected (either in the original or in supplemental notices) and stating, as applicable:

14.3.1 the estimated period during which performance may be prevented, interfered with or delayed, including, to the extent known or ascertainable, the estimated extent of such reduction in performance;

14.3.2 the particulars of the program to be implemented to resume normal performance under this Agreement; and

14.3.3 the anticipated portion of the AACQ for a Contract Year that will not be made available or taken, as the case may be, by reason of Force Majeure.

Such notices shall thereafter be updated at least monthly during the period of such claimed Force Majeure specifying the actions being taken to remedy the circumstances causing such Force Majeure.

14.4 Measures

Prior to resumption of normal performance, the Parties shall continue to perform their obligations under this Agreement to the extent not excused by such event of Force Majeure.

14.5 No Extension of Term

The Term shall not be extended as a result of or by the duration of an event of Force Majeure.

14.6 Settlement of Industrial Disturbances

Settlement of strikes, lockouts, or other industrial disturbances shall be entirely within the discretion of the Party experiencing such situations, and nothing in this Agreement shall require such Party to settle industrial disputes by yielding to demands made on it when it considers such action inadvisable.

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14.7 Foundation Customer Priority

Notwithstanding any other provision in this Section 14, in respect of any cargo(es) scheduled to be loaded hereunder at the Corpus Christi Facility (or alternate source, as applicable), during any event of Force Majeure affecting Seller, (i) Seller shall have the right to apportion the remaining capacity at the Corpus Christi Facility (or alternate source, as applicable) according to the Foundation Customer Priority and (ii) Buyer shall be treated on a non-discriminatory basis as compared to other similarly situated customers of Seller and/or its Affiliates purchasing LNG at the Corpus Christi Facility. “Foundation Customer Priority” means that Foundation Customers and all other customers with contractual priority will receive priority over other customers including Buyer for receiving LNG from the remaining available LNG production capacity, if any, at the Corpus Christi Facility (or alternate source, as applicable) without regard to which LNG production train(s) is affected by the underlying event, and without regard to which LNG production train(s) maintains available LNG production capacity.

15. Liabilities and Indemnification

15.1 General

Subject to Section 15.2, and without prejudice to any indemnity provided under this Agreement, Seller shall be liable to Buyer, and Buyer shall be liable to Seller, for any loss which has been suffered as a result of the breach by the Party liable of any one or more of its obligations under this Agreement, to the extent that the Party liable should reasonably have foreseen the loss.

15.2 Limitations on Liability

15.2.1 Incidental and Consequential Losses. Neither Party shall be liable to the other Party hereunder as a result of any act or omission in the course of or in connection with the performance of this Agreement, for or in respect of:

(a) any indirect, incidental, consequential or exemplary losses;

(b) any loss of income or profits;

(c) except as expressly provided in this Agreement, any failure of performance or delay in performance to the extent relieved by the application of Force Majeure in accordance with Section 14; or

(d) except as expressly provided in this Agreement, any losses arising from any claim, demand or action made or brought against the other Party by a Third Party.

15.2.2 Exclusive Remedies. A Party’s sole liability, and the other Party’s exclusive remedy, arising under or in connection with Sections 5.4, 5.5, 7.12.3, 7.12.4,

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7.14.2(d) and 12.3 and this Section 15 shall be as set forth in each such provision, respectively.

15.2.3 Liquidated Damages. The Parties agree that it would be impracticable to determine accurately the extent of the loss, damage and expenditure that either Party would have in the circumstances described in Sections 5.4, 5.5, 7.12.3 and 7.12.4. Accordingly, the Parties have estimated and agreed in advance that the sole liability, and exclusive remedy for such circumstances shall be as provided in those Sections, and neither Party shall have additional liability as a result of any such circumstances. Each amount described in or determined by the provisions of Sections 5.4, 5.5, 7.12.3 and 7.12.4 is intended to represent a genuine pre-estimate by the Parties as to the loss or damage likely to be suffered by the Party receiving the payment or benefit in each such circumstance. Each Party waives any right to claim or assert, in any arbitration or expert determination pursuant to Section 21 in any action with respect to this Agreement, that any of the exclusive remedies set forth in Sections 5.4, 5.5, 7.12.3 and 7.12.4 do not represent a genuine pre-estimate by the Parties as to the loss or damage likely to be suffered by the Party receiving the payment or benefit in each such circumstance or otherwise are not valid and enforceable damages.

15.2.4 Express Remedies. The Parties agree that Section 15.2.1 shall not impair a Party’s obligation to pay the amounts specified in, or the validity of or limitations imposed by, Sections 5.4, 5.5, 7.12.3, 7.12.4, 7.14.2(d), and 12.3. Neither Party shall have a right to make a claim for actual damages (whether direct or indirect) or other non-specified damages under any circumstances for which an express remedy or measure of damages is provided in this Agreement.

15.2.5 Remedies in Contract. Except with respect to claims for injunctive relief under Section 19 and Section 21.1.11, a Party’s sole remedy against the other Party for nonperformance or breach of this Agreement or for any other claim of whatsoever nature arising out of or in relation to this Agreement shall be in contract and no Party shall be liable to another Party (or its Affiliates and contractors and their respective members, directors, officers, employees and agents) in respect of any damages or losses suffered or claims which arise out of, under or in any alleged breach of statutory duty or tortious act or omission or otherwise.

15.2.6 Seller Aggregate Liability for Certain Events.

(a) Notwithstanding any provision herein to the contrary, the maximum Seller Aggregate Liability as of any given date in respect of any occurrence or series of occurrences shall not exceed the Seller Liability Cap.

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(b) “Seller Aggregate Liability” shall mean, as of any date of determination, any and all liability of Seller to Buyer under this Agreement, excluding (i) any Seller liabilities under this Agreement for which Seller has already made payment to Buyer as of such date, (ii) any liability caused by the gross negligence or willful misconduct of Seller or an Affiliate of Seller and (iii) any amounts related to an indemnity obligation of Seller.

(c) The “Seller Liability Cap” shall be an amount (in USD) equal to USD one hundred ninety-five million (US$195,000,000).

15.2.7 EXCEPT FOR WARRANTIES OF TITLE AND NO LIENS OR ENCUMBRANCES, AND SUBJECT TO THE PROVISIONS OF THIS AGREEMENT CONCERNING THE QUALITY OF LNG TO BE DELIVERED UNDER THIS AGREEMENT, SELLER EXPRESSLY NEGATES ANY WARRANTY WITH RESPECT TO LNG DELIVERED UNDER THIS AGREEMENT, WRITTEN OR ORAL, EXPRESS OR IMPLIED, INCLUDING ANY WARRANTY WITH RESPECT TO CONFORMITY TO SAMPLES, MERCHANTABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE.

15.3 Third Party Liability

With respect to Third Party liabilities:

(a) If any Third Party shall notify either Party (the “Indemnified Party”) with respect to any matter (a “Third Party Claim”) that may give rise to a claim for indemnification against the other Party (the “Indemnifying Party”) under this Section 15 or elsewhere in this Agreement, then the Indemnified Party shall promptly notify the Indemnifying Party thereof in writing; provided, however, that no delay on the part of the Indemnified Party in notifying the Indemnifying Party shall relieve the Indemnifying Party from any obligation hereunder unless (and then solely to the extent) the Indemnifying Party thereby is materially prejudiced.

(b) The Indemnifying Party will have the right to defend against the Third Party Claim with counsel of its choice reasonably satisfactory to the Indemnified Party so long as (i) the Indemnifying Party notifies the Indemnified Party in writing within fifteen (15) Days after the Indemnified Party has given notice of the Third Party Claim that the Indemnifying Party will indemnify the Indemnified Party from and against any damages the Indemnified Party may suffer resulting from, arising out of, relating to, in the nature of, or caused by the Third Party Claim; (ii) the Indemnifying Party provides the Indemnified

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Party with evidence reasonably acceptable to the Indemnified Party that the Indemnifying Party will have the financial resources to defend against the Third Party Claim and fulfill its indemnification obligations hereunder; (iii) the Third Party Claim involves only money damages and does not seek an injunction or other equitable relief; (iv) settlement of, or an adverse judgment with respect to, the Third Party Claim is not in the good faith judgment of the Indemnified Party, likely to establish a precedential custom or practice materially adverse to the continuing business interests of the Indemnified Party; and (v) the Indemnifying Party conducts the defense of the Third Party Claim actively and diligently.

(c) So long as the Indemnifying Party is conducting the defense of the Third Party Claim in accordance with Section 15.3(b): (i) the Indemnified Party may retain separate co-counsel at its sole cost and expense and participate in the defense of the Third Party Claim; (ii) the Indemnified Party will not consent to the entry of any judgment or enter into any settlement with respect to the Third Party Claim without the prior written consent of the Indemnifying Party (which consent shall not be unreasonably withheld); and (iii) the Indemnifying Party will not consent to the entry of any judgment or enter into any settlement with respect to the Third Party Claim without the prior written consent of the Indemnified Party (which consent shall not be unreasonably withheld).

(d) In the event any of the conditions in Section 15.3(b) is or becomes unsatisfied, or a conflict arises, with regard to the Third Party Claim, between the Indemnified Party and the Indemnifying Party in respect of such Third Party Claim the Indemnified Party may defend against the Third Party Claim in any manner it reasonably may deem appropriate.

(e) If either Party gives notice to the other Party of a Third Party Claim pursuant to the provisions of Section 15.3(a) and the notified Party does not give notice that it will indemnify the notifying Party in the manner set out in Section 15.3(b), the notifying Party shall nevertheless send copies of all pleadings and other documents filed in any such Third Party lawsuit to the notified Party and such notified Party may have the right to participate in the defense of the Third Party Claim in any manner permitted by Applicable Law.

15.4 Seller’s Insurance

15.4.1 Seller shall obtain and maintain or cause to be obtained and maintained:

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(a) insurance for the Corpus Christi Facility to the extent required by Applicable Law, and

(b) additional insurance, as is reasonably necessary and available on reasonable commercial terms, against such other risks and at such levels as a Reasonable and Prudent Operator of a liquefaction terminal would obtain.

15.4.2 Seller shall obtain or cause to be obtained the insurance required by Section 15.4.1 from a reputable insurer (or insurers) reasonably believed to have adequate financial reserves. Seller shall exercise its best efforts, or shall cause the applicable insured Person to use its best efforts, to collect any amount due under such insurance policies.

15.5 Buyer’s Insurance

Buyer shall ensure that insurances are procured and maintained for each LNG Tanker in accordance with the following provisions. In all cases, such insurance shall establish insurance coverages consistent with insurances to the standards which a ship owner operating reputable LNG vessels, as a Reasonable and Prudent Operator, should observe in insuring LNG vessels of similar type, size, age and trade as such LNG Tanker. In this regard:

(a) Hull and Machinery Insurance shall be placed and maintained with reputable marine underwriters; and

(b) Protection & Indemnity Insurance (“P&I Insurance”) shall be placed and maintained with full P&I indemnity cover in the ordinary course from a P&I Club, and such LNG Tanker shall be entered for insurance with a P&I Club, including pollution liability standard for LNG vessel and Certificate of Financial Responsibility.

16. Safety

16.1 General

The Parties recognize the importance of securing and maintaining safety in all matters contemplated in this Agreement, including the construction and operation of their respective facilities and the LNG Tankers and transportation of LNG. It is their respective intentions to secure and maintain high standards of safety in accordance with the generally accepted standards prevailing in the LNG and LNG transportation industries from time to time.

16.2 Third Parties

Both Parties shall endeavor to ensure that their respective employees, agents, operators, Transporter, contractors and suppliers shall have due regard to safety and

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abide by the relevant regulations while they are performing work and services in connection with the performance of this Agreement, including such work and services performed within and around the area of the Corpus Christi Facility (or alternate source, as applicable) and on board the LNG Tankers.

17. Representations, Warranties and Undertakings

17.1 Representations and Warranties of Buyer

As of the Effective Date and until the expiration or termination of this Agreement, Buyer represents, undertakes and warrants that:

17.1.1 Buyer is and shall remain duly formed and in good standing under the laws of the jurisdiction of its organization;

17.1.2 Buyer has the requisite power, authority and legal right to execute and deliver, and to perform its obligations under, this Agreement;

17.1.3 Buyer has not incurred any liability to any financial advisor, broker or finder for any financial advisory, brokerage, finder’s or similar fee or commission in connection with the transactions contemplated by this Agreement for which Seller or any of its Affiliates could be liable; and

17.1.4 neither the execution, delivery, nor performance of this Agreement violates or will violate, results or will result in a breach of or constitutes or will constitute a default under any provision of Buyer’s organizational documents, any law, judgment, order, decree, rule, or regulation of any court, administrative agency, or other instrumentality of any Governmental Authority or of any other material agreement or instrument to which Buyer is a party.

17.2 Representations and Warranties of Seller

As of the Effective Date and until the expiration or termination of this Agreement, Seller represents, undertakes and warrants that:

17.2.1 Seller is and shall remain duly formed and in good standing under the laws of the jurisdiction of its organization;

17.2.2 Seller has the requisite power, authority and legal right to execute and deliver, and to perform its obligations under this Agreement;

17.2.3 Seller has not incurred any liability to any financial advisor, broker or finder for any financial advisory, brokerage, finder’s or similar fee or commission in connection with the transactions contemplated by this Agreement for which Buyer or any of its Affiliates could be liable; and

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17.2.4 neither the execution, delivery, nor performance of this Agreement, violates or will violate, results or will result in a breach of, or constitutes or will constitute a default under, any provision of Seller’s organizational documents, any law, judgment, order, decree, rule, or regulation of any court, administrative agency, or other instrumentality of any Governmental Authority or of any other material agreement or instrument to which Seller is a party.

17.3 Business Practices

Each Party represents and warrants to the other, as of the Effective Date, that it has not taken any actions that would, if such actions were undertaken after the Effective Date, conflict with such Party’s obligations under Section 26.3.

18. Exchange of Information

The Parties shall maintain close communication and mutually provide and shall use reasonable efforts to exchange available information directly relevant to the fulfillment of the terms and conditions of this Agreement.

19. Confidentiality

19.1 Duty of Confidentiality

The (i) terms of this Agreement and (ii) any information disclosed by either Party to the other Party in connection with this Agreement which is not:

(a) already known to the recipient from sources other than the other Party;

(b) already in the public domain (other than as a result of a breach of the terms of this Section 19.1); or

(c) independently developed by the recipient;

shall be “Confidential Information” and shall, unless otherwise agreed in writing by the disclosing Party, be kept confidential and shall not be used by the receiving Party other than for a purpose connected with this Agreement or, except as provided below, disclosed to Third Parties by the receiving Party.

19.2 Permitted Disclosures

19.2.1 The Confidential Information, which either Party receives from the other, may be disclosed by such Party:

(a) to any Person who is such Party’s legal counsel, other professional consultant or adviser, Transporter, insurer, accountant or construction

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contractor; providedthat such disclosure is solely to assist the purpose for which such Person was so engaged;

(b) if required and to the extent required by the rules of any recognized stock exchange or agency established in connection therewith upon which the securities of such Party or a company falling within Section 19.2.1(e) are quoted;

(c) if required and to the extent required by the U.S. Department of Energy;

(d) without limiting Section 19.2.1(c), if required and to the extent required by any Applicable Laws, or such Party becomes legally required (by oral questions, interrogatories, request for information or documents, orders issued by any Governmental Authority or any other process) to disclose such information, or to the extent necessary to enforce Section 21.1 or 21.2 or any arbitration award or binding decision of an Expert (including by filing Confidential Information in proceedings before a court or other competent judicial authority) or to enforce other rights of a party to the Dispute; provided that such Party shall, to the extent practicable, give prior notice to the other Party of the requirement and the terms thereof and shall cooperate with the other Party to minimize the disclosure of the information, seek a protective order or other appropriate remedy, and if such protective order or other remedy is not obtained, then such Party will furnish only that portion of such information that it is legally required to furnish;

(e) to any of its Affiliates or shareholders (or any company involved in the provision of advice to any such Affiliate or shareholder for the purposes of this Agreement) and any employee of that Party or of a company to which disclosure is permitted pursuant to this Section 19.2.1(e);

(f) to any bona fide intended assignees of a Party’s interests under this Agreement;

(g) to any Third Party as reasonably necessary for the performance of a Party’s obligations under this Agreement;

(h) to any arbitrator appointed in accordance with Section 21.1.4, or Expert appointed pursuant to Section 21.2.1, or to any other party to an arbitration or Expert proceeding arising under or in connection with this Agreement, or to any witnesses appearing in an arbitration under Section 21.1 or in an Expert proceeding under Section 21.2; or

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(i) to any Person reasonably required to see such Confidential Information, including the Lenders, in connection with any bona fide financing or offering or sale of securities by Seller or Buyer or any Affiliate of Seller or Buyer or any Affiliate of any of the shareholders of Seller or Buyer, to comply with the disclosure or other requirements of Applicable Law or of financial institutions or other participants (including rating agencies) in such financing, offering or sale.

19.2.2 The Party making the disclosure shall ensure that any Person listed in Section 19.2.1(a), (e), (f), (g), (h) or (i) to which it makes the disclosure (excluding any legal counsel, arbitrator or Expert already bound by confidentiality obligations) undertakes to hold such Confidential Information subject to confidentiality obligations equivalent to those set out in Section 19.1. In the case of a disclosure to an employee made in accordance with Section 19.2.1(e), the undertaking shall be given by the company on its own behalf and in respect of all its employees.

19.2.3 Seller and its Affiliates may disclose Confidential Information to their long-term customers related to scheduling, operations and other relevant technical information to comply with Seller’s performance of Section 8, only to the extent necessary to ensure the effective implementation thereof.

19.2.4 Seller and its Affiliates may disclose Confidential Information to EOG (or any successor entity as seller under the GSA) to comply with the requirements of and/or to facilitate Seller’s performance under the GSA.

19.2.5 No press release concerning the execution of this Agreement or resolution of any Disputes shall be issued unless agreed by the Parties.

19.3 Duration of Confidentiality

The foregoing obligations with regard to the Confidential Information shall remain in effect for three (3) years after this Agreement is terminated or expires.

20. Default and Termination

20.1 Termination Events

The following circumstances (each, a “Termination Event”) shall give rise to the right for either or both of Seller and Buyer (as the case may be) to terminate this Agreement:

20.1.1 in respect of either Party, if a Bankruptcy Event has occurred with respect to the other Party;

20.1.2 in respect of either Party, if the other Party fails to pay or cause to be paid any amount or amounts in the aggregate due that are in excess of USD twenty

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million (US$20,000,000), for a period of five (5) Business Days or more following the due date of the relevant invoice;

20.1.3 in respect of either Party, violation of Section 17.3 or Section 26.3.1(ii) by the other Party;

20.1.4 in respect of Seller, if Buyer fails to comply with any provision of Section 22;

20.1.5 in respect of Seller, if Buyer fails to execute any Direct Agreement with Lenders within sixty (60) Days after Seller’s request thereof, provided that such Direct Agreement complies with the requirements in Section 22.4.2;

20.1.6 in respect of Buyer, if (a) Seller has declared Force Majeure one or more times and the interruptions resulting from such Force Majeure total twenty-four (24) Months during any consecutive thirty-six (36) Month period, and (b) such Force Majeure has resulted in Seller being prevented from making available fifty percent (50%) or more of the annualized ACQ during such periods of Force Majeure;

20.1.7 in respect of Seller, if (a) Buyer has declared Force Majeure one or more times and the interruptions resulting from such Force Majeure total twenty-four (24) Months during any consecutive thirty-six (36) Month period, and (b) such Force Majeure has resulted in Buyer being prevented from taking fifty percent (50%) or more of the annualized ACQ during such periods of Force Majeure;

20.1.8 in respect of Seller, violation of Section 26.1 by Buyer;

20.1.9 in respect of Seller, violation of Section 26.2 by Buyer;

20.1.10 in respect of Buyer, if Seller fails to make available (as such obligation for any cargo is set forth in Section 5.5.1) fifty percent (50%) of the cargoes scheduled in any given twelve (12) Month period;

20.1.11 in respect of Seller, if Buyer fails to take (as such obligation for any cargo is set forth in Section 5.4.1) fifty percent (50%) of the cargoes scheduled in any given twelve (12) Month period;

20.1.12 in respect of Seller, if the GSA terminates for any reason other than where the GSA terminates as the result of an “Event of Default” (as such term is defined in the GSA) occurring in respect of the buyer under the GSA; and

20.1.13 in respect of Seller: (a) if Buyer is in default under any financing agreement, the amount of debt associated with the relevant financing agreement(s) exceeds USD twenty-five million (US$25,000,000), and such default has not been cured in its entirety within five (5) Business Days of its occurrence;

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or (b) if Buyer is in default under any financing agreement and the amount of debt associated with the relevant financing agreement(s) exceeds USD fifty million (US$50,000,000).

20.2 Termination

20.2.1 Notice of Termination. Upon the occurrence of any Termination Event, subject to Section 20.2.5, the Party which has the right under Section 20.1 to terminate this Agreement (“Terminating Party”) may give notice thereof to the other Party, specifying in reasonable detail the nature of such Termination Event (except that any termination notice with respect to a Termination Event identified in Section 20.1.10 or 20.1.11 shall only be valid if notice thereof is provided within ninety (90) Days after such Termination Event first arose).

20.2.2 Timing. Except with respect to the Termination Events described in Section 20.2.3, at any time after the expiry of a period of five (5) Business Days after the Terminating Party gave notice of a Termination Event pursuant to Section 20.2.1, unless the circumstances constituting the Termination Event have been fully remedied or have ceased to apply, the Terminating Party may terminate this Agreement with immediate effect by giving notice of such termination to the other Party.

20.2.3 Certain Events. Upon the occurrence of a Termination Event described in Sections 20.1.1, 20.1.3, 20.1.4, 20.1.5, 20.1.6, 20.1.7, 20.1.8, 20.1.9, 20.1.10, 20.1.11, 20.1.12 and 20.1.13 the Terminating Party’s notice pursuant to Section 20.2.1 shall terminate this Agreement immediately.

20.2.4 Rights Accrued Prior to Termination. Termination of this Agreement shall be without prejudice to:

(a) the rights and liabilities of the Parties accrued prior to or as a result of such termination; and

(b) claims for breaches of Section 19 that occur during the three (3) year period after termination of this Agreement.

20.2.5 Limits to Termination. Neither Seller nor Buyer, respectively, may terminate this Agreement if the Termination Event occurs solely because of a breach by the non-terminating Party arising from events for which that non-terminating Party would otherwise be entitled to terminate this Agreement, provided that this shall not apply in respect of the Termination Event described in Section 20.1.12.

20.2.6 Termination Related to GSA. Buyer hereby waives any right it may have to seek monetary damages arising solely as a result of the Termination Event

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set forth in Section 20.1.12. Nothing in this Section 20.2.6 shall act as a waiver of any right Buyer may have to seek monetary damages in respect of (a) any rights accrued prior to Termination as provided in Section 20.2.4, or (b) any other Termination Event, whether or not the circumstances giving rise to such other Termination Event would also have entitled Seller to terminate the Agreement pursuant to Section 20.1.12.

20.3 Survival

The following provisions shall survive expiration or termination of this Agreement: Sections 1, 10, 11, 13.8.2, 15, 19 (to the extent provided therein), and 21 to 26, in addition to this Section 20.3.

21. Dispute Resolution and Governing Law

21.1 Dispute Resolution

21.1.1 Arbitration. Any Dispute (other than a Dispute submitted to an Expert under Section 21.2.1) shall be exclusively and definitively resolved through final and binding arbitration, it being the intention of the Parties that this is a broad form arbitration agreement designed to encompass all possible claims and disputes under this Agreement.

21.1.2 Rules. The arbitration shall be conducted in accordance with the International Arbitration Rules (the “Rules”) of the American Arbitration Association (“AAA”) (as then in effect).

21.1.3 Number of Arbitrators. The arbitral tribunal shall consist of three (3) arbitrators, who shall endeavor to complete the final hearing in the arbitration within six (6) Months after the appointment of the last arbitrator.

21.1.4 Method of Appointment of the Arbitrators. If there are only two (2) parties to the Dispute, then each party to the Dispute shall appoint one (1) arbitrator within thirty (30) Days of the filing of the arbitration, and the two arbitrators so appointed shall select the presiding arbitrator within thirty (30) Days after the latter of the two arbitrators has been appointed by the parties to the Dispute. If a party to the Dispute fails to appoint its party-appointed arbitrator or if the two party-appointed arbitrators cannot reach an agreement on the presiding arbitrator within the applicable time period, then the AAA shall serve as the appointing authority and shall appoint the remainder of the three arbitrators not yet appointed. If the arbitration is to be conducted by three arbitrators and there are more than two parties to the Dispute, then within thirty (30) Days of the filing of the arbitration, all claimants shall jointly appoint one arbitrator and all respondents shall jointly appoint one arbitrator, and the two arbitrators so appointed shall select the presiding arbitrator within thirty (30) Days after the latter of the two arbitrators has

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been appointed by the parties to the Dispute. For the purposes of appointing arbitrators under this Section 21, (a) Buyer and all persons whose interest in this Agreement derives from Buyer shall be considered as one party; and (b) Seller and all persons whose interest in this Agreement derives from Seller shall be considered as one party. If either all claimants or all respondents fail to make a joint appointment of an arbitrator, or if the party-appointed arbitrators cannot reach an agreement on the presiding arbitrator within the applicable time period, then the AAA shall serve as the appointing authority and shall appoint the remainder of the three (3) arbitrators not yet appointed.

21.1.5 Consolidation. If the Parties initiate multiple arbitration proceedings under this Agreement, the subject matters of which are related by common questions of law or fact and which could result in conflicting awards or obligations, then either Party may request prior to the appointment of the arbitrators for such multiple or subsequent Disputes that all such proceedings be consolidated into a single arbitral proceeding. Such request shall be directed to the AAA, which shall consolidate appropriate proceedings into a single proceeding unless consolidation would result in undue delay for the arbitration of the Disputes.

21.1.6 Place of Arbitration. Unless otherwise agreed by all parties to the Dispute, the place of arbitration shall be New York, New York.

21.1.7 Language. The arbitration proceedings shall be conducted in the English language, and the arbitrators shall be fluent in the English language.

21.1.8 Entry of Judgment. The award of the arbitral tribunal shall be final and binding. Judgment on the award of the arbitral tribunal may be entered and enforced by any court of competent jurisdiction. The Parties agree that service of process for any action to enforce an award may be accomplished according to the procedures of Section 25, as well as any other procedure authorized by law.

21.1.9 Notice. All notices required for any arbitration proceeding shall be deemed properly given if given in accordance with Section 25.

21.1.10 Qualifications and Conduct of the Arbitrators. All arbitrators shall be and remain at all times wholly impartial, and, once appointed, no arbitrator shall have any ex parte communications with any of the parties to the Dispute concerning the arbitration or the underlying Dispute other than communications directly concerning the selection of the presiding arbitrator, where applicable.

21.1.11 Interim Measures. Any party to the Dispute may apply to a court in Harris County, Texas for interim measures (a) prior to the constitution of the arbitral

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tribunal (and thereafter as necessary to enforce the arbitral tribunal’s rulings); or (b) in the absence of the jurisdiction of the arbitral tribunal to rule on interim measures in a given jurisdiction. The Parties agree that seeking and obtaining such interim measures shall not waive the right to arbitration. The arbitrators (or in an emergency the presiding arbitrator acting alone in the event one or more of the other arbitrators is unable to be involved in a timely fashion) may grant interim measures including injunctions, attachments and conservation orders in appropriate circumstances, which measures may be immediately enforced by court order. Hearings on requests for interim measures may be held in person, by telephone, by video conference or by other means that permit the parties to the Dispute to present evidence and arguments.

21.1.12 Costs and Attorneys’ Fees. The arbitral tribunal is authorized to award costs of the arbitration in its award, including: (a) the fees and expenses of the arbitrators; (b) the costs of assistance required by the tribunal, including its Experts; (c) the fees and expenses of the administrator; (d) the reasonable costs for legal representation of a successful Party; and (e) any such costs incurred in connection with an application for interim or emergency relief and to allocate those costs between the parties to the Dispute. The costs of the arbitration proceedings, including attorneys’ fees, shall be borne in the manner determined by the arbitral tribunal.

21.1.13 Interest. The award shall include pre-award and post-award interest, as determined by the arbitral award, from the date of any default or other breach of this Agreement until the arbitral award is paid in full. Interest shall accrue at a rate per annum equal to two percent (2%) above LIBOR (as in effect on the Day such award was issued) on and from the Day when such award was issued until the date of its repayment, provided that, without prejudice to the other terms of this Agreement, if such period lasts longer than ninety (90) Days, the applicable LIBOR rate for each successive term of ninety (90) Days during that period shall be that in effect on the first Day of that ninety (90) Day period. Interest shall accrue from Day to Day and be calculated on the basis of a three hundred sixty (360) Day year.

21.1.14 Currency of Award. The arbitral award shall be made and payable in USD, free of any tax or other deduction.

21.1.15 Waiver of Challenge to Decision or Award. To the extent permitted by law, the Parties hereby waive any right to appeal from or challenge any arbitral decision or award, or to oppose enforcement of any such decision or award before a court or any governmental authority, except with respect to the limited grounds for modification or non-enforcement provided by any applicable arbitration statute or treaty.

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21.1.16 Confidentiality. Any arbitration or Expert determination relating to a Dispute (including an arbitral award, a settlement resulting from an arbitral award, documents exchanged or produced during an arbitration or Expert proceeding, and memorials, briefs or other documents prepared for the arbitration or Expert proceeding) shall be Confidential Information subject to the confidentiality provisions of Section 19; provided, however, that breach of such confidentiality provisions shall not void any settlement, determination or award.

21.2 Expert Determination

21.2.1 General. In the event of any disagreement between the Parties regarding a measurement under Exhibit A or any other Dispute which the Parties agree to submit to an Expert (in either case, a “Measurement Dispute”), the Parties hereby agree that such Measurement Dispute shall be resolved by an Expert selected as provided in this Section 21.2.1. The Expert is not an arbitrator of the Measurement Dispute and shall not be deemed to be acting in an arbitral capacity. The Party desiring an expert determination shall give the other Party to the Measurement Dispute notice of the request for such determination. If the Parties to the Measurement Dispute are unable to agree upon an Expert within ten (10) Days after receipt of the notice of request for an expert determination, then, upon the request of any of the Parties to the Measurement Dispute, the International Centre for Expertise of the International Chamber of Commerce (“ICC”) shall appoint such Expert and shall administer such expert determination through the ICC’s Rules for Expertise. The Expert shall be and remain at all times wholly impartial, and, once appointed, the Expert shall have no ex parte communications with any of the Parties to the Measurement Dispute concerning the expert determination or the underlying Measurement Dispute. The Parties to the Measurement Dispute shall cooperate fully in the expeditious conduct of such expert determination and provide the Expert with access to all facilities, books, records, documents, information and personnel necessary to make a fully informed decision in an expeditious manner. Before issuing a final decision, the Expert shall issue a draft report and allow the Parties to the Measurement Dispute to comment on it. The Expert shall endeavor to resolve the Measurement Dispute within thirty (30) Days (but no later than sixty (60) Days) after his appointment, taking into account the circumstances requiring an expeditious resolution of the matter in dispute.

21.2.2 Final and Binding. The Expert’s decision shall be final and binding on the Parties to the Measurement Dispute unless challenged in an arbitration pursuant to Section 21.1 within thirty (30) Days of the date the Expert’s decision. If challenged, (a) the decision shall remain binding and be implemented unless and until finally replaced by an award of the arbitrators; (b) the decision shall be entitled to a rebuttable presumption of correctness;

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and (c) the Expert shall not be appointed in the arbitration as an arbitrator or as advisor to either Party without the written consent of both Parties.

21.2.3 Arbitration of Expert Determination. In the event that a Party requests expert determination for a Measurement Dispute which raises issues that require determination of other matters in addition to correct measurement under Exhibit A, then either Party may elect to refer the entire Measurement Dispute for arbitration under Section 21.1.1. In such case, the arbitrators shall be competent to make any measurement determination that is part of a Dispute. An expert determination not referred to arbitration shall proceed and shall not be stayed during the pendency of an arbitration.

21.3 Governing Law

This Agreement shall be governed by and construed in accordance with the laws of the State of New York (United States of America) without regard to principles of conflict of laws that would specify the use of other laws.

21.4 Immunity

21.4.1 Each Party, as to itself and its assets, hereby irrevocably, unconditionally, knowingly and intentionally waives any right of immunity (sovereign or otherwise) and agrees not to claim, or assert any immunity with respect to the matters covered by this Agreement in any arbitration, Expert proceeding, or other action with respect to this Agreement, whether arising by statute or otherwise, that it may have or may subsequently acquire, including rights under the doctrines of sovereign immunity and act of state, immunity from legal process (including service of process or notice, pre-judgment or pre-award attachment, attachment in aid of execution, or otherwise), immunity from jurisdiction or judgment of any court, arbitrator, Expert or tribunal (including any objection or claim on the basis of inconvenient forum), and immunity from enforcement or execution of any award or judgment or any other remedy.

21.4.2 Each Party irrevocably, unconditionally, knowingly and intentionally:

(a) agrees that the execution, delivery and performance by it of this Agreement constitute private and commercial acts rather than public or governmental acts;

(b) consents in respect of the enforcement of any judgment against it in any such proceedings in any jurisdiction and to the giving of any relief or the issue of any process in connection with such proceedings (including the making, enforcement or execution of any such judgment or any order arising out of any such judgment against or in

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respect of any property whatsoever irrespective of its use or intended use).

22. Assignments

22.1 Merger, Consolidation

This Agreement shall be binding upon and inure to the benefit of any successor to each of Seller and Buyer by merger, or consolidation.

22.2 Assignment by Buyer

22.2.1 Prior Written Consent. Buyer may novate or assign this Agreement in its entirety to another Person, for the remainder of the Term, upon the prior written consent of Seller (which consent shall not be unreasonably withheld or delayed), provided that such transferee assumes all of the obligations of Buyer under this Agreement commencing as of the date of the novation or assignment by execution of a copy of this Agreement in its own name (countersigned by Seller) or by execution of a binding assignment and assumption agreement which is enforceable by Seller.

22.2.2 Further Obligations. Upon a novation or assignment in whole by Buyer in accordance with Section 22.2.1, the assignor shall be released from all further obligations, duties and liabilities under this Agreement, other than any obligations, duties and liabilities arising prior to the date of effectiveness of such novation or assignment.

22.3 Assignments by Seller

22.3.1 Prior Written Consent. Seller may novate or assign this Agreement in its entirety to another Person, for the remainder of the Term, upon the prior written consent of Buyer (which consent shall not be unreasonably withheld or delayed), provided that the transferee assumes all of the obligations of Seller under this Agreement commencing as of the date of the novation or assignment by execution of a copy of this Agreement in its own name (countersigned by Buyer) or by execution of a binding assignment and assumption agreement which is enforceable by Buyer.

22.3.2 Without Prior Consent. Seller may novate or assign this Agreement in its entirety to an Affiliate of Seller, for the remainder of the Term, without Buyer’s prior consent, provided that:

(a) such Affiliate assignee has an ownership interest in and/or operates the Corpus Christi Facility (including Corpus Christi Liquefaction, LLC or Corpus Christi Liquefaction Stage III, LLC), the Sabine Pass

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Facility (including Sabine Pass Liquefaction, LLC) and/or any other natural gas liquefaction facility; and

(b) such Affiliate assignee assumes all of the obligations of Seller under this Agreement commencing as of the date of the novation or assignment, either by execution of a copy of this Agreement in its own name and (if elected by such assignee) modified to replace all references to “Corpus Christi Facility” and similar terms with references to the Affiliate assignee, relevant LNG facility and, as applicable, other relevant terms (countersigned by Buyer) or by execution of a binding assignment and assumption agreement which is enforceable by Buyer.

22.3.3 Pursuant to Direct Agreement. Seller may novate or assign this Agreement in its entirety, for the remainder of the Term, to the extent that Buyer has so consented in the Direct Agreement.

22.3.4 Further Obligations. Upon a novation or assignment by Seller in accordance with this Section 22.3, the assignor shall be released from all further obligations, duties and liabilities under this Agreement, other than any obligations, duties and liabilities arising prior to the date of effectiveness of such novation or assignment.

22.4 Financing by Seller or its Affiliates

22.4.1 Lender Financing. Seller and its Affiliates shall each have the right to obtain financing from Lenders. In connection with any financing or refinancing of Seller’s activities or any LNG production facility owned, operated or being developed by Seller or any of its Affiliates (including the Corpus Christi Facility and Sabine Pass Facility), Buyer, shall, if so requested by Seller, deliver to the relevant Lenders or the agent acting on behalf of any such Lenders (“Lenders’ Agent”) opinions of counsel, certified copies of their respective corporate charter and by-laws, resolutions, incumbency certificates, financial statements, and such other items as available and upon reasonable request by Lenders or Lenders’ Agent. Buyer shall not be required to provide any documents or information which would cause it to be in breach of Applicable Laws, including the rules of any recognized stock exchange on which Buyer’s stock is quoted.

22.4.2 Assignment as Security. Buyer further acknowledges and agrees that Seller may assign, transfer, or otherwise encumber, all or any of its rights, benefits and obligations under this Agreement to such Lenders or Lenders’ Agent as security for the obligations of Seller or its Affiliates to the respective Lenders. Accordingly, upon Seller’s request pursuant to a notice hereunder, Buyer shall enter into one or more direct agreements (each, a “Direct Agreement”) that:

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(a) provide for the assignment and transfer of the assigning Person’s rights and obligations under this Agreement to a nominee of Lender following a default by the assigning Person under its lending arrangement; and

(b) are in a form and contain such terms and conditions as are required by the Lenders or Lenders’ Agent.

23. Contract Language

This Agreement, together with the Exhibits hereto, shall be made and originals executed in the English language. In case of any difference in meaning between the English language original version and any translation thereof, the English language original version shall be applicable.

24. Miscellaneous

24.1 Disclaimer of Agency

This Agreement does not appoint either Party as the agent, partner or legal representative of the other for any purposes whatsoever, and neither Party shall have any express or implied right or authority to assume or to create any obligation or responsibility on behalf of or in the name of the other Party.

24.2 Entire Agreement

This Agreement, together with the Exhibits hereto, constitutes the entire agreement between the Parties and includes all promises and representations, express or implied, and supersedes all other prior agreements and representations, written or oral, between the Parties relating to the subject matter. Anything that is not contained or expressly incorporated by reference in this instrument, is not part of this Agreement.

24.3 Third Party Beneficiaries

The Parties do not intend any term of this Agreement to be for the benefit of, or enforceable by, any Third Party except as expressly provided in Section 7.7. The Parties may rescind or vary this Agreement, in whole or in part, without the consent of any Third Party, including those Third Parties referred to under Section 7.7, even if as a result such Third Party’s rights to enforce a term of this Agreement will be varied or extinguished.

24.4 Amendments and Waiver

This Agreement may not be supplemented, amended, modified or changed except by an instrument in writing signed by Seller and Buyer and expressed to be a supplement, amendment, modification or change to this Agreement. A Party shall

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not be deemed to have waived any right or remedy under this Agreement by reason of such Party’s failure to enforce such right or remedy.

24.5 Exclusion

The United Nations Convention on Contracts for the International Sale of Goods (and the Convention on the Limitation Period in the International Sale of Goods) shall not apply to this Agreement and the respective rights and obligations of the Parties hereunder.

24.6 Further Assurances

Each Party hereby agrees to take all such action as may be necessary to effectuate fully the purposes of this Agreement, including causing this Agreement or any document contemplated herein to be duly registered, notarized, attested, consularized and stamped in any applicable jurisdiction.

24.7 Severability

If and for so long as any provision of this Agreement shall be deemed to be judged invalid for any reason whatsoever, such invalidity shall not affect the validity or operation of any other provision of this Agreement except only so far as shall be necessary to give effect to the construction of such invalidity, and any such invalid provision shall be deemed severed from this Agreement without affecting the validity of the balance of this Agreement.

24.8 Multiple SPAs

24.8.1 The Parties expressly agree that all rights and obligations (including in respect of all claims, demands, legal proceedings and actions; all losses, liabilities, damages, costs, judgments, settlements and expenses (whether or not resulting from claims by third parties), including interest and penalties with respect thereto and reasonable attorneys’ and accountants’ fees and expenses; and all mitigation measures) of Corpus Christi Liquefaction, LLC (or its successor or permitted assignee pursuant to the CMILLP Base SPA), and Cheniere Marketing International, LLP (or its successor or permitted assignee pursuant to the CMILLP Base SPA), under the CMILLP Base SPA, whether in contract or at law, are wholly separate and in isolation of, and shall not merge in any way with, any rights and obligations (including in respect of all Claims, all Losses, and all mitigation measures) of the Parties under this Agreement. The Parties expressly waive any right to combine any such rights or obligations under the CMILLP Base SPA with such rights and obligations under this Agreement. Default by a Party under this Agreement shall not excuse default under the CMILLP Base SPA by any party thereto, and default under the CMILLP Base SPA by a party thereto shall not excuse a Party’s default under this Agreement. No Party shall have

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any obligation to take any action or inaction under this Agreement to mitigate the losses or liabilities that may arise in respect of the CMILLP Base SPA. Without limiting the foregoing, in no way shall the Seller Liability Cap under this Agreement be merged with the corresponding seller liability cap under the CMILLP Base SPA, and the Parties’ respective rights and obligations in respect of the Seller Liability Cap shall not vary based on performance or nonperformance of the CMILLP Base SPA.

24.8.2 Without prejudice to Section 21.1.5, if the Parties initiate multiple arbitration proceedings under this Agreement and the CMILLP Base SPA, the subject matters of which are related by common questions of law or fact and which could result in conflicting awards or obligations, then either Party may request prior to the appointment of the arbitrators for such multiple or subsequent Disputes that all such proceedings be consolidated into a single arbitral proceeding. Such request shall be directed to the AAA, which shall consolidate appropriate proceedings into a single proceeding unless consolidation would result in undue delay for the arbitration of the Disputes.

24.8.3 Each Party shall ensure that all invoices and notices sent by or on behalf of such Party pursuant to this Agreement identify such invoice or notice as being in connection with this Agreement.

24.8.4 Each Party shall issue invoices and make payments in accordance with this Agreement separate from invoices and payments under the CMILLP Base SPA. If either Party receives payment from the other Party and such payment does not identify itself as being in respect of the CMILLP Base SPA or this Agreement, then the Party receiving such payment shall promptly request confirmation of whether to apply the payment to the CMILLP Base SPA or this Agreement. If confirmation has not been received by close of business on the third (3rd) Business Day after the request is deemed to be received pursuant to Section 25.2, the Party receiving such payment shall have the right to apply such payment received to amounts owed to the receiving Party under the CMILLP Base SPA or this Agreement, with first priority to overdue amounts (with priority within this group to be based on how many days the amount has been overdue, starting with the longest number of days) and then to other amounts due but unpaid (with priority within this group to be based on how many days remain until the applicable due date, starting with the shortest number of days).

24.8.5 Each Party shall maintain separate financial and other records in connection with the CMILLP Base SPA and this Agreement in a manner that enables the Parties to identify whether costs, expenses, and other auditable amounts and information are in respect of the CMILLP Base SPA or this Agreement and to comply with all audit obligations under the CMILLP Base SPA and this Agreement.

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24.8.6 Without limiting the foregoing, the Parties agree to conduct their businesses in a manner that effectuates the foregoing terms of this Section 24.8, and that any course of dealing that is inconsistent with the foregoing terms of this Section 24.8 shall not change the Parties’ respective rights and obligations under this Section 24.8.

24.9 Safe Harbor Provisions

Without limiting any other protections available to the Parties under the Bankruptcy Code or any other United States of America federal or state, or any other insolvency law, the Parties acknowledge and agree that:

24.9.1 This Agreement and all transactions contemplated hereby shall constitute a “swap agreement” and a “forward contract” (as each such term is defined in the Bankruptcy Code).

24.9.2 Seller and Buyer each constitute a “swap participant” and a “forward contract merchant” within the meaning of the Bankruptcy Code and are entitled to all of the protections in the Bankruptcy Code afforded to such entities that are party to a “swap agreement” or a “forward contract”, respectively, including those protections set forth in sections 362, 546, 548, 556, 560, 561 and 562 of the Bankruptcy Code. In furtherance of these acknowledgments and agreements, the Parties further acknowledge and agree that Seller is a Person whose business consists in whole or in part of, and Buyer is a Person whose business consists in whole or in part of, entering into “forward contracts” (as such term is defined in the Bankruptcy Code) as or with merchants in natural gas (whether in liquefied or gaseous state).

24.9.3 Each Party’s right to cause the liquidation, termination or acceleration of this Agreement, or any transaction contemplated hereby, because of a condition of the kind specified in section 365(e)(1) of the Bankruptcy Code or to offset or net out termination values, payment amounts or other transfer obligations, and to exercise any other remedies upon the occurrence of any such termination, liquidation or acceleration under this Agreement, constitutes a “contractual right” with respect to the other Party within the meaning of sections 556, 560 and 561 of the Bankruptcy Code.

24.9.4 Any transfer of cash, securities or other property provided as performance assurance, credit support or collateral with respect to this Agreement, or any transaction contemplated hereby, shall constitute (i) a “transfer” made “by or to (or for the benefit of)” a “forward contract merchant” “under” or “in connection with” this Agreement and each such transaction and/or (ii) a “transfer” made “by or to (or for the benefit of)” a “swap participant” “under” or “in connection with” this Agreement and each such transaction, in each case within the meaning of the Bankruptcy Code.

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All payments, transfers or deliveries for, under or in connection with this Agreement, or any transaction contemplated hereby, shall be a “settlement payment” and “transfer” “under” or “in connection with” each such transaction, in each case within the meaning of the Bankruptcy Code.

25. Notices

25.1 Form of Notice

25.1.1 Except as expressly set forth herein, any notice, invoice or other communication from one of the Parties to the other Party (or, where contemplated in this Agreement, from or to the Transporter or the master of the LNG Tanker), which is required or permitted to be made by the provisions of this Agreement shall be:

(a) made in the English language;

(b) made in writing;

(c) (i) delivered by hand or sent by courier to the address of the other Party which is shown below or to such other address as the other Party shall by notice require or; (ii) be sent by facsimile to the facsimile number of the other Party which is shown below or to such other facsimile number as the other Party shall by notice require or; (iii) with respect to any notice, invoice or other communication to be sent pursuant to Sections 3.1, 7, 8, 10, 12 or 14 (or others as may be agreed by the Parties), be sent by electronic mail to the e-mail address of the other Party which is shown below or to such other e-mail address as the other Party shall by notice require; and

(d) marked for the attention of the Person(s) there referred to or to such other Person(s) as the other Party shall by notice require.

25.1.2 The addresses of the Parties for service of notices are as follows:

Seller: Corpus Christi Liquefaction, LLC

700 Milam Street

Suite 1900

Houston, TX 77002

Telephone: (713) 375-5121

Fax: (713) 375-6121

E-mail: Customer.Coordination@Cheniere.com

Attention: Commercial Operations

Buyer: Cheniere Marketing International LLP

Berkeley Square House, Fifth Floor, Berkeley Square

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London W1J 6BY, United Kingdom

Telephone:    +44 20 3214 2700

Fax:        +44 20 3214 2705

E-mail:     lngoperations@cheniere.com

Attention: Commercial Operations

25.2 Effective Time of Notice

25.2.1 Any notice, invoice or other communication made by one Party to the other Party in accordance with the foregoing provisions of this Section 25 shall be deemed to be received by the other Party if delivered by hand or by courier, on the Day on which it is received at that Party’s address or, if sent by facsimile or e-mail, on the next Day on which the office of the receiving Party is normally open for business following the Day on which it is received in a legible form at the address to which it is properly addressed. The foregoing shall not apply to notices or communications sent by facsimile or e-mail under Sections 7.9.2, 7.9.3, and 7.10, which shall be deemed effective at the time transmitted to the facsimile number or e-mail address shown above or such other number or e-mail address previously notified by the receiving Party.

25.2.2 Without limiting the meaning of the word “received” for the purpose of the preceding paragraph, a notice which is delivered by hand or by courier shall be deemed to have been received at a Party’s address if it is placed in any receptacle normally used for the delivery of post to the address of that Party.

25.2.3 Any notice given by facsimile or e-mail shall be subsequently confirmed by letter, unless otherwise agreed, but without prejudice to the validity of the original notice.

26. Business Practices

26.1 Trade Law Compliance.

26.1.1 Buyer acknowledges and agrees that it will resell or transfer LNG purchased hereunder for delivery only: (a) with respect to all LNG loaded at the Corpus Christi Facility (i) (A) to countries identified in Ordering Paragraph B of DOE/FE Order No. 3164, issued October 16, 2012 in FE Docket No. 12-99-LNG and Ordering Paragraph B of DOE/FE Order No. 4277, issued November 9, 2018, in FE Docket No. 18-78-LNG or (B) to countries identified in Ordering Paragraph F of DOE/FE Order No. 3638, issued May 12, 2015 in FE Docket No. 12-97-LNG, and/or (ii) to purchasers that have agreed in writing to limit their direct or indirect resale or transfer of such LNG to such countries; and (b) with respect to all LNG loaded at the Sabine Pass Facility (i) to countries identified in Ordering Paragraph B of DOE/

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FE Order No. 3384 issued January 22, 2014 in FE Docket No. 13-121-LNG, to countries identified in Ordering Paragraph B of DOE/FE Order No. 3595 issued February 12, 2015 in FE Docket No. 14-92-LNG, to countries identified in Ordering Paragraph F of DOE/FE Order No. 3669 issued June 26, 2015 in FE Docket Nos. 13-30-LNG, 13-42-LNG, and 13-121-LNG, or to countries identified in Ordering Paragraph F of DOE/FE Order No. 3792 issued March 11, 2016 in FE Docket No. 15-63-LNG, and/or (ii) to purchasers that have agreed in writing to limit their direct or indirect resale or transfer of such LNG to such countries. Buyer further commits to cause a report to be provided to Seller (and any other Seller Affiliate as may be identified from time to time by Seller) that identifies the country of destination, upon delivery, into which the exported LNG was actually delivered, and to include in any resale contract for such LNG the necessary conditions to ensure that Seller (and any other Seller Affiliate as may be identified from time to time by Seller) is made aware of all such actual destination countries. Each Party agrees to comply with all U.S. Department of Energy export authorizations authorizing the export of LNG from the Corpus Christi Facility and Sabine Pass Facility, as applicable. If any export authorization requires conditions to be included in this Agreement then, within fifteen (15) Days following the issuance of the export authorization (or the amendment or other modification to an existing export authorization) imposing such condition, the Parties shall discuss the appropriate changes to be made to this Agreement to comply with such export authorization and shall amend this Agreement accordingly.

26.1.2 Without prejudice to Section 26.1.1, with respect to all LNG purchased hereunder that is loaded at an LNG facility other than the Corpus Christi Facility or the Sabine Pass Facility: (a) Buyer acknowledges and agrees that it will resell or transfer such LNG for delivery only to countries authorized pursuant to the applicable export authorization (whether issued by the U.S. Department of Energy or otherwise), and/or to purchasers that have agreed in writing to limit their direct or indirect resale or transfer of such LNG to such countries; (b) Buyer further commits to cause a report to be provided to Seller that identifies the country of destination, upon delivery, into which the exported LNG was actually delivered, and to include in any resale contract for such LNG the necessary conditions to ensure Seller is made aware of all such actual destination countries; and (c) each Party agrees to comply with the export authorization(s) applicable to the export of LNG from such LNG facility.

26.1.3 Buyer represents and warrants that the final delivery of LNG received pursuant to the terms of this Agreement are permitted and lawful under United States of America laws and policies, including the rules, regulations, orders, policies, and other determinations of the U.S. Department of Energy, the Office of Foreign Assets Control of the United States Department of the

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Treasury and the Federal Energy Regulatory Commission, and Buyer shall not take any action which would cause any export authorization(s) referred to in Section 26.1.2 or Section 26.1.2 to be withdrawn, revoked, suspended or not renewed. Buyer shall promptly provide to Seller all information required by Seller and its Affiliates, to comply with such export authorization(s) and shall provide the delivery destination reports (as described in Section 26.1.1 and Section 26.1.2) for all LNG sold hereunder, to Seller (and any other Seller Affiliate as may be identified from time to time by Seller), not later than the fifteenth (15th) Day of the Month following the Month in which any relevant LNG is delivered to the country of destination. In addition to the information required pursuant to Section 26.1, such delivery destination reports shall contain any other information required by the applicable export authorization(s).

26.2 Use of LNG

At all times during the Term, Buyer shall, with respect to all LNG delivered by Seller to Buyer pursuant to this Agreement: (a) utilize such LNG as a refined product or chemical feedstock; (b) use or consume such LNG to produce power for sale to customers; (c) market such LNG to distributors or wholesalers for resale to their own customers; or (d) resell such LNG to other Persons provided that the transfer by Buyer to a Transporter of gas that boils off from a cargo in transit from the Delivery Point shall be considered to be a sale.

26.3 Prohibited Practices

26.3.1 Each Party agrees that in connection with this Agreement and the activities contemplated herein, it will take no action, or omit to take any action, which would (i) violate any Applicable Law applicable to that Party, or (ii) cause the other Party to be in violation of any Applicable Law applicable to such other Party, including the U.S. Foreign Corrupt Practices Act, the OECD convention on anti-bribery, the U.K. Bribery Act of 2010, E.U. and E.U. member country anti-bribery and corruption laws, and corruption or any similar statute, regulation, order or convention binding on such other Party, as each may be amended from time to time, and including any implementing regulations promulgated pursuant thereto.

26.3.2 Without limiting Section 26.3.1, each Party agrees on behalf of itself, its directors, officers, employees, agents, contractors, and Affiliates, not to pay any fees, commissions or rebates to any employee, officer or agent of the other Party or its Affiliates or shareholders nor provide or cause to be provided to any of them any gifts or entertainment of significant cost or value in connection with this Agreement or in order to influence or induce any actions or inactions in connection with the commercial activities of the Parties hereunder.

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26.4 Records; Audit

Each Party shall keep all records necessary to confirm compliance with Sections 26.1, 26.2, 26.3.1(ii), and 26.3.2 for a period of five (5) years following the year for which such records apply. If either Party asserts that the other Party is not in compliance with Sections 26.1, 26.2, 26.3.1(ii), or 26.3.2, the Party asserting noncompliance shall send a notice to the other Party indicating the type of noncompliance asserted. After giving such notice, the Party asserting noncompliance may cause an independent auditor to audit the records of the other Party in respect of the asserted noncompliance. The costs of any independent auditor under this Section 26.4 shall be paid (i) by the Party being audited, if such Party is determined not to be in compliance with Sections 26.1, 26.2, 26.3.1(ii) or 26.3.2, as applicable, and (ii) by the Party requesting the audit, if the Party being audited is determined to be in compliance with Sections 26.1, 26.2, 26.3.1(ii), or 26.3.2, as applicable.

26.5 Indemnity

Each Party agrees to indemnify and hold the other Party harmless from any Losses arising out of the indemnifying Party’s breach of any or all of Section 26.1, Section 26.3, or Section 26.4 or the breach of the representation and warranty in Section 17.3.

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IN WITNESS WHEREOF, the Parties hereto have executed this Agreement as of the date first above written.

SELLER:	BUYER:
CORPUS CHRISTI LIQUEFACTION, LLC	CHENIERE MARKETING
	INTERNATIONAL LLP
	By : Cheniere Marketing, LLC, its managing member
/s/ Michael J. Wortley	/s/ Anatol Feygin
Name: Michael J. Wortley	Name: Anatol Feygin
Title: President and Chief Financial Officer	Title: Executive Vice President and Chief Commercial Officer

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Exhibit A

Measurement

1.Parties to Supply Devices

a)    General. Unless otherwise agreed, Buyer and Seller shall supply equipment and conform to procedures that are in accordance with the latest version of the standards referred to in this document.

b)Buyer Devices. Buyer or Buyer’s agent shall supply, operate and maintain, or cause to be supplied, operated and maintained, suitable gauging devices for the liquid level in LNG tanks of the LNG Tankers, pressure and temperature measuring devices, and any other measurement or testing devices which are incorporated in the structure of LNG vessels or customarily maintained on board ship.

c)Seller Devices. Seller shall supply, operate and maintain, or cause to be supplied, operated and maintained, devices required for collecting samples and for determining quality and composition of the LNG and any other measurement or testing devices which are necessary to perform the measurement and testing required hereunder at the Corpus Christi Facility (or alternate source, as applicable).

d)Dispute. Any Dispute arising under this Exhibit A shall be submitted to an Expert under Section 21.2 of this Agreement.

2.Selection of Devices

All devices provided for in this Exhibit A shall be approved by Seller, acting as a Reasonable and Prudent Operator. The required degree of accuracy (which shall in any case be within the permissible tolerances defined herein and in the applicable standards referenced herein) of such devices selected shall be mutually agreed upon by Buyer and Seller. In advance of the use of any device, the Party providing such device shall cause tests to be carried out to verify that such device has the required degree of accuracy.

3.Verification of Accuracy and Correction for Error

a)Accuracy. Accuracy of devices used shall be tested and verified at the request of either Party, including the request by a Party to verify accuracy of its own devices. Each Party shall have the right to inspect at any time the measurement devices installed by the other Party, provided that the other Party is notified in advance. Testing shall be performed only when both Parties are represented, or have received adequate advance notice thereof, using methods recommended by the manufacturer or any other method agreed to by Seller and Buyer. At the request of any Party hereto, any test shall be witnessed and verified by an independent surveyor mutually agreed upon by Buyer and Seller. Permissible tolerances shall be as defined herein or as defined in the applicable standards referenced herein.

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b)Inaccuracy. Inaccuracy of a device exceeding the permissible tolerances shall require correction of previous recordings, and computations made on the basis of those recordings, to zero error with respect to any period which is definitely known or agreed upon by the Parties as well as adjustment of the device. All invoices issued during such period shall be amended accordingly to reflect such correction, and an adjustment in payment shall be made between Buyer and Seller. If the period of error is neither known nor agreed upon, and there is no evidence as to the duration of such period of error, corrections shall be made and invoices amended for each delivery of LNG made during the last half of the period since the date of the most recent calibration of the inaccurate device. However, the provisions of this Paragraph 3 shall not be applied to require the modification of any invoice that has become final pursuant to Section 10.3.2 of this Agreement.

c)Costs and Expenses of Test Verification. All costs and expenses for testing and verifying Seller’s measurement devices shall be borne by Seller, and all costs and expenses for testing and verifying Buyer’s measurement devices shall be borne by Buyer. The fees and charges of independent surveyors for measurements and calculations shall be borne by the Parties in accordance with Section 13.11.3 of this Agreement.

4.Tank Gauge Tables of LNG Tankers

a)Initial Calibration. Buyer shall arrange or caused to be arranged, for each tank of each LNG Tanker, a calibration of volume against tank level. Buyer shall provide Seller or its designee, or cause Seller or its designee to be provided, with a certified copy of tank gauge tables for each tank of each LNG Tanker verified by a competent impartial authority or authorities mutually agreed upon by the Parties. Such tables shall include correction tables for list, trim, tank contraction and any other items requiring such tables for accuracy of gauging.

Tank gauge tables prepared pursuant to the above shall indicate volumes in cubic meters expressed to the nearest thousandth (1/1000), with LNG tank depths expressed in meters to the nearest hundredth (1/100).

b)Presence of Representatives. Seller and Buyer shall each have the right to have representatives present at the time each LNG tank on each LNG Tanker is volumetrically calibrated.

c)Recalibration. If the LNG tanks of any LNG Tanker suffer distortion of such nature as to create a reasonable doubt regarding the validity of the tank gauge tables described herein (or any subsequent calibration provided for herein), Buyer or Buyer’s agent shall recalibrate the damaged tanks, and the vessel shall not be employed as an LNG Tanker hereunder until appropriate corrections are made. If mutually agreed between Buyer and Seller representatives, recalibration of damaged tanks can be deferred until the next time when such damaged tanks are warmed for any reason, and any corrections to the prior tank gauge tables will be made from the time the distortion occurred. If the time of the distortion cannot be ascertained, the Parties shall mutually agree on the time period for retrospective adjustments.

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5.Units of Measurement and Calibration

The Parties shall co-operate in the design, selection and acquisition of devices to be used for measurements and tests in order that all measurements and tests may be conducted in the SI system of units, except for the quantity delivered which is expressed in MMBtu, the Gross Heating Value (volume based) which is expressed in Btu/SCF and the pressure which is expressed in millibar and temperature in Celsius. In the event that it becomes necessary to make measurements and tests using a new system of units of measurements, the Parties shall establish agreed upon conversion tables.

6.Accuracy of Measurement

All measuring equipment must be maintained, calibrated and tested in accordance with the manufacturer’s recommendations. In the absence of a manufacturer’s recommendation, the minimum frequency of calibration shall be five (5) years, unless otherwise mutually agreed between the Parties. Documentation of all tests and calibrations will be made available by the Party performing the same to the other Party. Acceptable accuracy and performance tolerances shall be:

a)Liquid Level Gauging Devices.

Each LNG tank of the LNG Tanker shall be equipped with primary and secondary liquid level gauging devices as per Paragraph 7(b) of this Exhibit A.

The measurement accuracy of the primary gauging devices shall be plus or minus seven point five (± 7.5) millimeters and the secondary liquid level gauging devices shall be plus or minus ten (± 10) millimeters.

The liquid level in each LNG tank shall be logged or printed.

b)Temperature Gauging Devices.

The temperature of the LNG and of the vapor space in each LNG tank shall be measured by means of a number of properly located temperature measuring devices sufficient to permit the determination of average temperature.

The measurement accuracy of the temperature gauging devices shall be as follows:

(i)in the temperature range of minus one hundred sixty five to minus one hundred forty degree Celsius (-165C to -140°C), the accuracy shall be plus or minus zero point two degree Celsius (± 0.2 °C);

(ii)in the temperature range of minus one hundred forty to plus forty degree Celsius (-140C to +40 °C), the accuracy shall be plus or minus one point five degree Celsius (± 1.5 °C).

The temperature in each LNG tank shall be logged or printed.

c)Pressure Gauging Devices.

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Each LNG tank of the LNG Tanker shall have one (1) absolute pressure gauging device.

The measurement accuracy of the pressure gauging device shall be plus or minus one percent (± 1%) of the measuring range.

The pressure in each LNG tank shall be logged or printed.

d)List and Trim Gauging Devices.

A list gauging device and a trim gauging device shall be installed. These shall be interfaced with the custody transfer system.

The measurement accuracy of the list and the trim gauging devices shall be better than plus or minus zero point zero five (±0.05) degrees for list and plus or minus zero point one (± 0.1) meters for trim.

7.Gauging and Measuring LNG Volumes Delivered

a)Gauge Tables. Upon Seller’s representative and the independent surveyor, if present, arriving on board the LNG Tanker prior to the commencement of or during loading, Buyer or Buyer’s representative shall make available to them a certified copy of tank gauge tables for each tank of the LNG Tanker.

b)Gauges. Volumes of LNG delivered pursuant to this Agreement shall be determined by gauging the LNG in the tanks of the LNG Tankers before and after loading. Each LNG Tanker’s tank shall be equipped with a minimum of two (2) independent sets of level gauges, each set utilizing preferably a different measurement principle. Comparison of the two (2) systems, designated as Primary and Secondary Measurement Systems, shall be performed from time to time to ensure compliance with the acceptable performance tolerances stated herein.

c)Gauging Process. Gauging the liquid level of each tank of the LNG Tankers and measuring of liquid temperature, vapor temperature and vapor pressure in each LNG tank, trim and list of the LNG Tankers, and atmospheric pressure shall be performed, or caused to be performed, by Buyer before and after loading. Seller’s representative shall have the right to be present while all measurements are performed and shall verify the accuracy and acceptability of all such measurements. The first gauging and measurements shall be made immediately before the commencement of loading. The second gauging and measurements shall take place immediately after the completion of loading.

d)Records. Copies of gauging and measurement records shall be furnished to Seller immediately upon completion of loading.

e)Gauging Liquid Level of LNG. The level of the LNG in each LNG tank of the LNG Tanker shall be gauged by means of the primary gauging device installed in the LNG Tanker for that purpose. The level of the LNG in each tank shall be logged or printed.

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Measurement of the liquid level in each LNG tank of the LNG Tanker shall be made to the nearest millimeter by using the primary liquid level gauging devices. Should the primary devices fail, the secondary device shall be used.

Five (5) readings shall be made following manufacturer’s recommendations on reading interval. The arithmetic average of the readings rounded to the nearest millimeter using one (1) decimal place shall be deemed the liquid level.

f)Determination of Temperature. The temperature of the LNG and of the vapor space in each LNG tank shall be measured by means of a sufficient number of properly located temperature measuring devices to permit the determination of average temperature. Temperatures shall be measured at the same time as the liquid level measurements and shall be logged or printed.

In order to determine the temperature of liquid and vapor respectively in the LNG Tanker one (1) reading shall be taken at each temperature gauging device in each LNG tank. An arithmetic average of such readings rounded to the nearest zero point one degree Celsius (0.1 °C) using two (2) decimal places with respect to vapor and liquid in all LNG tanks shall be deemed the final temperature of the vapor and liquid respectively.

Buyer shall cause each cargo tank in the LNG Tanker to be provided with a minimum of five (5) temperature measuring devices. One such measuring device shall be located in the vapor space at the top of each cargo tank, one near the bottom of each cargo tank and the remainder distributed at appropriate intervals from the top to the bottom of the cargo tank. These devices shall be used to determine the average temperatures of the liquid cargo and the vapor in the cargo tank.

The average temperature of the vapor in an LNG Tanker shall be determined immediately before loading by means of the temperature measuring devices specified above at the same time as when the liquid level is measured. The temperature measuring devices shall be fully surrounded by the vapor. This determination shall be made by taking the temperature readings of the temperature measuring devices in question to the nearest zero point zero one degrees Celsius (0.01°C), and if more than one of the devices are fully surrounded by the vapor, by averaging those readings, and rounding to one (1) decimal place.

The average temperature of the liquid in an LNG Tanker shall be determined immediately after loading by means of the temperature measuring devices specified above.

g)Determination of Pressure. The pressure of the vapor in each LNG tank shall be determined by means of pressure measuring devices installed in each LNG tank of the LNG Tankers. The atmospheric pressure shall be determined by readings from the standard barometer installed in the LNG Tankers. Pressures shall be measured at the same time as the liquid level measurements, and shall be logged or printed.

Buyer shall cause the LNG Tanker to be provided with pressure measuring equipment capable of determining the absolute pressure of the vapor in each cargo tank with an accuracy equal to or better than plus or minus one percent (± 1%) of the measuring range.

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The pressure of the vapor in an LNG Tanker shall be determined immediately before loading at the same time as when the liquid level is measured.

Such determination shall be made by taking the pressure readings of the pressure measuring devices to the nearest millibar, then averaging these readings and rounding to a whole millibar.

h)Determination of Density. The LNG density shall be calculated using the revised Klosek-McKinley method. Should any improved data, method of calculation or direct measurement device become available which is acceptable to both Buyer and Seller, such improved data, method or device shall then be used.

8.Samples for Quality Analysis

a)General. Representative liquid samples shall be collected from an appropriate point located as close as practical to the loading line starting one (1) hour after full loading rate is reached and ending one (1) hour before ramping down from the full loading rate.

Sampling conducted by Seller will conform with the procedure specified in (i), (ii) or (iii) as follows:

i) Online chromatograph: A sample shall be taken and analyzed at least once every twenty (20) minutes by an on-line chromatograph during the sampling period referenced in the opening paragraph of section 8(a) of this Exhibit A. These intermittent samples will be passed through a vaporizer, and samples of the vaporized liquid will be analyzed. The arithmetically averaged analysis, representative of the delivered LNG cargo shall be used for all appropriate calculations. Samples taken when biphasic or where overheated LNG is suspected to be in the main transfer line will be disregarded.

In instances where the on-line chromatograph system being utilized were to fail during loading operations manual samples (composite or spot) collected shall be analyzed.

ii) Composite sample: One (1) representative sample of the loading shall be collected by continuous sampling of the delivered LNG. If applicable the sample analysis shall be applied to the appropriate calculations associated with the delivered LNG cargo.

iii) Spot samples: One (1) spot sample shall be collected from the vaporizer at each point in time corresponding to approximately 25%, 50% and 75% of loading is completed. If applicable the analysis of spot samples shall be averaged and applied to the appropriate calculations associated with the delivered LNG cargo.

b)Manual Samples. It is recognized that for every loading manual samples should be retained for use by Buyer and Seller.

i) Where sampling analysis is conducted using spot samples per section 8(a)iii of this Exhibit A, two (2) sets of samples shall be collected from the vaporizer at each point

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in time corresponding to approximately twenty-five percent (25%), fifty percent (50%) and seventy-five percent (75%) of loading is completed and retained.

ii) Where sampling analysis is conducted using a composite sample per section 8(a)ii of this Exhibit A, two (2) samples shall be collected from the collection devices at the end of loading and retained.

The samples collected shall be properly labeled and sealed by the independent surveyor in attendance. Seller shall retain all samples for a period of thirty (30) days, unless the analysis is disputed prior to the end of such thirty (30) day period. If the analysis is in dispute, the samples will be retained until the dispute is resolved.

Notwithstanding the above, it is recognized from time to time that Buyer may require one (1) of the retained samples to accompany the LNG cargo delivery, provided sufficient notice.

Where Buyer receives a set of samples, Buyer shall return the set of sample cylinders provided or an identical set within sixty (60) days. If the set of sample cylinders provided are not returned or replaced to Seller’s satisfaction within the sixty (60) day period, Seller will procure replacement cylinders and Buyer will be invoiced for the cost of replacement cylinders inclusive of preparation cost.

Sampling and analysis methods and procedures that differ from the above may be employed with the mutual agreement of the Parties.

9.Quality Analysis

a)Certification and Deviation. Chromatograph calibration gasses shall be provided and their composition certified by an independent third party. From time to time, deviation checks shall be performed to verify the accuracy of the gas composition mole percentages and resulting calculated physical properties. Analyses of a sample of test gas of known composition resulting when procedures that are in accordance with the above mentioned standards have been applied will be considered as acceptable if the resulting calculated gross heating value is within plus or minus zero point three percent (± 0. 3%) of the known gross heating value of the test gas sample. If the deviation exceeds the tolerance stated, the gross real heating value, relative density and compressibility previously calculated will be corrected immediately. Previous analyses will be corrected to the point where the error occurred, if this can be positively identified to the satisfaction of both Parties. Otherwise it shall be assumed that the drift has been linear since the last recalibration and correction shall be based on this assumption.

b)GPA Standard 2261. All samples shall be analyzed by Seller to determine the molar fraction of the hydrocarbon and other components in the sample by gas chromatography using a mutually agreed method in accordance with GPA Standard 2261 - Method of Analysis for Gas and Similar Gaseous Mixtures by Gas Chromatography, current as of January 1^st, 1990 and as periodically updated or as otherwise mutually agreed by the Parties. If better standards for analysis are subsequently adopted by GPA or other recognized competent impartial authority, upon mutual agreement of Buyer and Seller, they shall be substituted for the standard then in use, but such

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substitution shall not take place retroactively. A calibration of the chromatograph or other analytical instrument used shall be performed by Seller immediately prior to the analysis of the sample of LNG delivered. Seller shall give advance notice to Buyer of the time Seller intends to conduct a calibration thereof, and Buyer shall have the right to have a representative present at each such calibration; provided, however, Seller will not be obligated to defer or reschedule any calibration in order to permit the representative of Buyer to be present.

c)GPA Standard 2377. Seller shall determine the presence of Hydrogen Sulfide (H2S) by use of GPA Standard 2377 - Test of Hydrogen Sulfide and Carbon Dioxide in Gas Using Length of Stain Tubes. Total sulfur will be determined as the summation of sulfur compounds (i.e. mercaptans) following ASTM D1988-06 (Standard Test Method for Mercaptans in Natural Gas using Length-of-Stain Detector Tubes). If the presence of Hydrogen Sulfide or sulfur compounds is detected, an additional test shall be performed to confirm the respective concentration(s) following either: (i) ASTM D6228 (Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection), (ii) ASTM D5504 (Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence), (iii) ASTM D6667 (Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence), or (iv) any other testing method mutually agreed by the Parties.

10.Operating Procedures

a)Notice. Prior to conducting operations for measurement, gauging, sampling and analysis provided in this Exhibit A, the Party responsible for such operations shall notify the appropriate representatives of the other Party, allowing such representatives reasonable opportunity to be present for all operations and computations; provided that the absence of the other Party’s representative after notification and opportunity to attend shall not prevent any operations and computations from being performed.

b)Independent Surveyor. At the request of either Party any measurement, gauging, sampling and analysis shall be witnessed and verified by an independent surveyor mutually agreed upon by Buyer and Seller. The results of such surveyor’s verifications shall be made available promptly to each Party.

c)Preservation of Records. All records of measurement and the computed results shall be preserved by the Party responsible for taking the same, or causing the same to be taken, and made available to the other Party for a period of not less than three (3) years after such measurement and computation.

11.Quantities Delivered

a)Calculation of MMBtu Quantities. Seller shall calculate, or cause to be calculated and Buyer shall verify, the quantity of MMBtu delivered. Either Party may, at its own expense, require the measurements and calculations and/or their verification by an independent surveyor, mutually agreed upon by the Parties. Consent to an independent surveyor proposed by a Party shall not be unreasonably withheld by the other Party.

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b)Determination of Gross Heating Value. All component values shall be in accordance with the latest revision of GPA Standard 2145 SI (2009) - Physical Constants for Hydrocarbons & Other Compounds of Interest to the Natural Gas Industry and the latest revision of the reference standards therein. Standard reference conditions for Hi component should be 15°C & 101.325 kPa.

c)Determination of Volume of LNG Loaded.

(i)The LNG volume in the tanks of the LNG Tanker before and after loading (valves have to be closed) shall be determined by gauging on the basis of the tank gauge tables provided for in Paragraph 6. During the period when measurement is occurring, no LNG cargo, ballast, boil-off gas, fuel oil or other cargo transfer activity will be carried out on the LNG Tanker. Measurements shall first be made immediately before loading commences. Accordingly, after connection of the loading arms, but prior to their cool-down, and immediately before opening the manifold ESD valves of the LNG Tanker, the initial gauging shall be conducted upon the confirmation of stoppage of all spray pumps and compressors and shut-off of the gas master valve to the LNG Tanker’s boilers or any other gas consuming unit. The gas master valve to the LNG Tanker’s boilers or any other gas consuming unit shall remain closed until after the second gauging, unless a regulatory change requires the consumption of gas during the vessel loading operations and/or upon mutual agreement between all parties upon which event the procedure for the measurement of gas consumed during loading shall be calculated in accordance with Paragraph 12.4 of this Exhibit A. A second gauging shall be made immediately after loading is completed. Accordingly, the second gauging shall be conducted upon the confirmation of shut-off of the manifold ESD valves, with transfer pumps off and allowing sufficient time for the liquid level to stabilize. Measurements prior to loading and after loading will be carried out based on the condition of the LNG Tanker’s lines upon arrival at berth. Since significant volumes of LNG may remain in the LNG Tanker’s manifold and crossover, gauging will be performed with these lines in the same condition prior to loading and after loading. If the LNG Tanker’s manifold and crossover lines are empty (warm) when measurement is taken before loading commences, they will be emptied prior to measurement following the completion of loading. If the crossover lines are liquid filled (cold) when measurement is taken before loading commences, they will remain full (cold) until measurement is taken following the completion of loading. The volume of LNG remaining in the tanks immediately before loading of the LNG Tanker shall be subtracted from the volume immediately after loading and the resulting volume shall be taken as the volume of the LNG delivered from the terminal to the LNG Tanker.

The volume of LNG stated in cubic meters to the nearest zero point zero zero one (0.001) cubic meter, shall be determined by using the tank gauge tables and by applying the volume corrections set forth therein.

(ii)Gas returned to the terminal and gas consumed by the LNG Tanker during loading shall be taken into account to determine the volume loaded for Buyer’s account in accordance with the formula in Paragraph 12.4 of this Exhibit A - MMBtu Calculation of the Quantity of LNG Loaded.

(iii)If failure of the primary gauging and measuring devices of an LNG Tanker should make it impossible to determine the LNG volume, the volume of LNG loaded shall be determined by gauging the liquid level using the secondary gauging and measurement devices. If an LNG Tanker is not so equipped, the volume of LNG loaded shall be determined by gauging the liquid level in Seller’s

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onshore LNG storage tanks immediately before and after loading the LNG Tanker, in line with the terminal procedures, and such volume shall have subtracted from it an estimated LNG volume, agreed upon by the Parties, for boil-off from such tanks during the loading of such LNG Tanker. Seller shall provide Buyer, or cause Buyer to be provided with, a certified copy of tank gauge tables for each onshore LNG tank which is to be used for this purpose, such tables to be verified by a competent impartial authority.

12.Calculations

The calculation procedures contained in this Paragraph 12 are generally in accordance with the Institute of Petroleum Measurement Manual, Part XII, the Static Measurement of Refrigerated Hydrocarbon Liquids, Section 1, IP 251/76.

d =density of LNG loaded at the prevailing composition and temperature Tl in kg/m3, rounded to two (2) decimal places, calculated according to the method specified in Paragraph 12.1 of this Exhibit A.

Hi=gross heating value (mass based) of component “i” in MJ/kg, in accordance with Paragraph 12.6(a) of this Exhibit A.

Hm=gross heating value (mass based) of the LNG loaded in MJ/kg, calculated in accordance with the method specified in Paragraph 12.3 of this Exhibit A, rounded to four (4) decimal places.

Hv=gross heating value (volume based) of the LNG loaded in Btu/SCF, calculated in accordance with the method specified in Paragraph 12.5 of this Exhibit A.

K1= volume correction in m3/kmol, at temperature Tl, obtained by linear interpolation from Paragraph 12.6(c) of this Exhibit A, rounded to six (6) decimal places.

K2=volume correction in m3/kmol, at temperature Tl obtained by linear interpolation from Paragraph 12.6(d) of this Exhibit A, rounded to six (6) decimal places.

Mi=molecular mass of component “i” in kg/kmol, in accordance with Paragraph 12.6(a) of this Exhibit A.

P =average absolute pressure of vapor in an LNG Tanker immediately before loading, in millibars, rounded to a whole millibar.

Q=number of MMBtu contained in the LNG delivered, rounded to the nearest ten (10) MMBtu.

Tl =average temperature of the liquid cargo in the LNG Tanker immediately after loading, in degrees Celsius, rounded to one (1) decimal place.

Tv = average temperature of the vapor in an LNG Tanker immediately before loading, in degrees Celsius, rounded to one (1) decimal place.

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V=the volume of the liquid cargo loaded, in cubic meters, rounded to three (3) decimal places.

Vh=the volume of the liquid cargo in an LNG Tanker immediately before loading, in cubic meters, rounded to three (3) decimal places.

Vb=the volume of the liquid cargo in an LNG Tanker immediately after loading, in cubic meters, rounded to three (3) decimal places.

Vi=molar volume of component “i” at temperature Tl, in m3/kmol, obtained by linear interpolation from Paragraph 12.6(b) of this Exhibit A, rounded to six (6) decimal places.

Xi=molar fraction of component “i” of the LNG samples taken from the loading line, rounded to four (4) decimal places, determined by gas chromatographic analysis.

Xm=the value of Xi for methane.

Xn=the value of Xi for nitrogen.

12.1 Density Calculation Formula

The density of the LNG loaded which is used in the MMBtu calculation in 12.4 of this Exhibit A shall be calculated from the following formula derived from the revised Klosek-McKinley method:

In the application of the above formula, no intermediate rounding shall be made if the accuracy of “d” is thereby affected.

12.2Calculation of Volume Delivered

The volume, in cubic meters, of each LNG cargo loaded shall be calculated by using the following formula:

12.3 Calculation of Gross Heating Value (Mass Based)

The gross heating value (mass based), in MJ/kg, of each LNG cargo loaded shall be calculated by using the following formula:

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12.4MMBtu Calculation of the Quantity of LNG Loaded

The number of MMBtu contained in the LNG loaded shall be calculated using the following formula:

The derivation of the conversion factor 1/1055.12 in the formula in this Paragraph for the conversion of MJ into MMBtu is obtained from GPA-2145:1994 and IP-251:1976 as follows:

(a)q(T,P) means the gross heating value (measured at temperature T and pressure P), contained in a given quantity of gas;

(b)q(60°F, 14.696 psia) in MJ = 1/1.00006 x q(15°C, 1013.25 millibar) in MJ;

(c)1 MMBtu corresponds to 1055.06 MJ;

(d)q(60°F, 14.696 psia) in MMBtu = 1/1055.06 x q(60°F, 14.696 psia) in MJ; and

(e)Combining (b) and (d) above yields:

q(60°F, 14.696 psia) in MMBtu = 1/1055.12 x q(15°C, 1013.25 millibar) in MJ.

Hence the number of MJ derived shall be divided by 1055.12 to obtain the number of MMBtu for invoicing purposes.

QBOG =the quantity of boil off gas in MJ consumed by the LNG tanker during loading, calculated as follows:

QBOG = (V2 x 55.575)

where:

V2 =the quantity of natural gas consumed by the LNG tanker during loading (as calculated pursuant to the below formula), stated in kg and rounded to the nearest kg; and

55.575 = the heating value of the vapor (assumed to be 100% of methane) stated in MJ/kg at standard reference conditions (15˚C, 1.01325 bar) for both combustion & metering references (tables below).

Quantity of Natural Gas Consumed by LNG Tanker (V2)

The quantity of natural gas consumed by the LNG tanker during loading shall be computed by taking the initial and the final reading of Natural Gas Consumption Meter on board the tanker (i.e. final reading of Natural Gas Consumption Meter after completion of loading

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minus initial reading of Natural Gas Consumption Meter before the start of loading) and is calculated by using the following formula:

V2=Vf - Vi

where:

V2 =the quantity of natural gas consumed by the LNG tanker during loading, stated in kg;

Vf =the reading of Natural Gas Consumption Meter on board the tanker after the completion of loading, stated in kg; and

Vi =the reading of Natural Gas Consumption Meter on board the tanker before the start of loading, stated in kg.

12.5Calculation of Gross Heating Value (Volume Based)

The calculation of the Gross Heating Value (volume based) in Btu/SCF shall be derived from the same compositional analysis as is used for the purposes of calculating the Gross Heating Value (mass based) Hm and the following formula shall apply:

The derivation of the conversion factor 1.13285 for the conversion of MJ/kmol into Btu/SCF is obtained as follows:

(a)molar gross heating value = ∑ (Xi x Mi x Hi) MJ/kmol;

(b)1 kmol = 2.20462 lbmol;

(c)1 lbmol = 379.482 SCF;

(d)hence 1 kmol = 836.614 SCF; and

(e)Hv = 1,000,000/ (1055.12 x 836.614) x ∑ (Xi x Mi x Hi) Btu/SCF

A-13

12.6Data

(a)Valuesof Hi and Mi

Component	Hi (in MJ/kg)	Mi (in kg/kmol)
Methane	55.575	16.0425
Ethane	51.951	30.0690
Propane	50.369	44.0956
Iso-Butane	49.388	58.1222
N-Butane	49.546	58.1222
Iso-Pentane	48.950	72.1488
N-Pentane	49.045	72.1488
N-Hexane	48.715	86.1754
Nitrogen	0	28.0134
Carbon Dioxide	0	44.0095
Oxygen	0	31.9988

Source: GPA Publication 2145 Sl-2009: “Table of Physical Properties for Hydrocarbons and Other Compounds of Interest to the Natural Gas Industry”.

(b)Values of Vi (cubic meter/kmol)

Temperature	-150°C	-154°C	-158°C	-160°C	-162°C	-166°C	-170°C
Methane	0.039579	0.038983	0.038419	0.038148	0.037884	0.037375	0.036890
Ethane	0.048805	0.048455	0.048111	0.047942	0.047774	0.047442	0.047116
Propane	0.063417	0.063045	0.062678	0.062497	0.062316	0.061957	0.061602
Iso-Butane	0.079374	0.078962	0.078554	0.078352	0.078151	0.077751	0.077356
N-Butane	0.077847	0.077456	0.077068	0.076876	0.076684	0.076303	0.075926
Iso-Pentane	0.092817	0.092377	0.091939	0.091721	0.091504	0.091071	0.090641
N-Pentane	0.092643	0.092217	0.091794	0.091583	0.091373	0.090953	0.090535
N-Hexane	0.106020	0.105570	0.105122	0.104899	0.104677	0.104236	0.103800
Nitrogen	0.055877	0.051921	0.048488	0.046995	0.045702	0.043543	0.041779
Carbon Diox	0.027950	0.027650	0.027300	0.027200	0.027000	0.026700	0.026400
Oxygen	0.03367	0.03275	0.03191	0.03151	0.03115	0.03045	0.02980

Source: National Bureau of Standards Interagency Report 77-867, Institute of Petroleum IP251/76 for Oxygen.

Note:For intermediate values of temperature and molecular mass a linear interpolation shall be applied

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(c)Values of Volume Correction Factor, K1 (cubic meter/kmol)

Molecular Mass of Mixture	-150°C	-154°C	-158°C	-160°C	-162°C	-166°C	-170°C
16.0	-0.000012	-0.000010	-0.000009	-0.000009	-0.000008	-0.000007	-0.000007
16.5	0.000135	0.000118	0.000106	0.000100	0.000094	0.000086	0.000078
17.0	0.000282	0.000245	0.000221	0.000209	0.000197	0.000179	0.000163
17.2	0.000337	0.000293	0.000261	0.000248	0.000235	0.000214	0.000195
17.4	0.000392	0.000342	0.000301	0.000287	0.000274	0.000250	0.000228
17.6	0.000447	0.000390	0.000342	0.000327	0.000312	0.000286	0.000260
17.8	0.000502	0.000438	0.000382	0.000366	0.000351	0.000321	0.000293
18.0	0.000557	0.000486	0.000422	0.000405	0.000389	0.000357	0.000325
18.2	0.000597	0.000526	0.000460	0.000441	0.000423	0.000385	0.000349
18.4	0.000637	0.000566	0.000499	0.000477	0.000456	0.000412	0.000373
18.6	0.000677	0.000605	0.000537	0.000513	0.000489	0.000440	0.000397
18.8	0.000717	0.000645	0.000575	0.000548	0.000523	0.000467	0.000421
19.0	0.000757	0.000685	0.000613	0.000584	0.000556	0.000494	0.000445
19.2	0.000800	0.000724	0.000649	0.000619	0.000589	0.000526	0.000474
19.4	0.000844	0.000763	0.000685	0.000653	0.000622	0.000558	0.000503
19.6	0.000888	0.000803	0.000721	0.000688	0.000655	0.000590	0.000532
19.8	0.000932	0.000842	0.000757	0.000722	0.000688	0.000622	0.000561
20.0	0.000976	0.000881	0.000793	0.000757	0.000721	0.000654	0.000590
25.0	0.001782	0.001619	0.001475	0.001407	0.001339	0.001220	0.001116
30.0	0.002238	0.002043	0.001867	0.001790	0.001714	0.001567	0.001435

Source: National Bureau of Standards Interagency Report 77-867.

Note 1:Molecular mass of mixture equals ∑ (Xi x Mi).

Note 2:For intermediate values of temperature and molecular mass a linear interpolation shall be applied.

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(d)Values of Volume Correction Factor, K2 (cubic meter/kmol)

Molecular Mass of Mixture	-150°C	-154°C	-158°C	-160°C	-162°C	-166°C	-170°C
16.0	-0.000039	-0.000031	-0.000024	-0.000021	-0.000017	-0.000012	-0.000009
16.5	0.000315	0.000269	0.000196	0.000178	0.000162	0.000131	0.000101
17.0	0.000669	0.000568	0.000416	0.000377	0.000341	0.000274	0.000210
17.2	0.000745	0.000630	0.000478	0.000436	0.000397	0.000318	0.000246
17.4	0.000821	0.000692	0.000540	0.000495	0.000452	0.000362	0.000282
17.6	0.000897	0.000754	0.000602	0.000554	0.000508	0.000406	0.000318
17.8	0.000973	0.000816	0.000664	0.000613	0.000564	0.000449	0.000354
18.0	0.001049	0.000878	0.000726	0.000672	0.000620	0.000493	0.000390
18.2	0.001116	0.000939	0.000772	0.000714	0.000658	0.000530	0.000425
18.4	0.001184	0.001000	0.000819	0.000756	0.000696	0.000567	0.000460
18.6	0.001252	0.001061	0.000865	0.000799	0.000735	0.000605	0.000496
18.8	0.001320	0.001121	0.000912	0.000841	0.000773	0.000642	0.000531
19.0	0.001388	0.001182	0.000958	0.000883	0.000811	0.000679	0.000566
19.2	0.001434	0.001222	0.000998	0.000920	0.000844	0.000708	0.000594
19.4	0.001480	0.001262	0.001038	0.000956	0.000876	0.000737	0.000623
19.6	0.001526	0.001302	0.001078	0.000992	0.000908	0.000765	0.000652
19.8	0.001573	0.001342	0.001118	0.001029	0.000941	0.000794	0.000681
20.0	0.001619	0.001382	0.001158	0.001065	0.000973	0.000823	0.000709
25.0	0.002734	0.002374	0.002014	0.001893	0.001777	0.001562	0.001383
30.0	0.003723	0.003230	0.002806	0.002631	0.002459	0.002172	0.001934

Source: National Bureau of Standards Interagency Report 77-867.

Note 1:Molecular mass of mixture equals ∑ (Xi x Mi).

Note 2:For intermediate values of temperature and molecular mass a linear interpolation shall be applied.

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Exhibit B

FORM OF PORT LIABILITY AGREEMENT

THIS PORT LIABILITY AGREEMENT (this “Agreement”) is effective as of _______, 20__, and is made by and between [INSERT NAME(S) OF TERMINAL ENTITY, a TYPE OF ENTITY AND JURISDICTION OF ORGANIZATION] (“Terminal”), and [INSERT NAME(S) OF VESSEL OWNER(S), a TYPE OF ENTITY AND JURISDICTION OF ORGANIZATION] ([collectively] “Vessel Owner”).

RECITALS

WHEREAS, Vessel Owner, using the vessel set forth below under its name and signature (“Vessel”), proposes to receive certain quantities of liquefied natural gas (“LNG”) from Terminal at the marine terminal and LNG liquefaction and storage facilities located on [•] (as more fully defined below, the “Marine Terminal”); and

WHEREAS, Vessel Owner and Terminal (collectively, the “Parties” and individually a “Party”) have agreed to allocate the risk of and responsibility for loss and damage resulting from an Incident (as defined below) at the Marine Terminal in the following manner;

NOW THEREFORE, for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree as follows:

1. The following terms shall have the following meanings when used herein:

“Affiliate” means, with respect to any Person, any other Person which, directly or indirectly, controls, is controlled by, or is under common control with, such Person. For purposes of this definition, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”) means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities or otherwise.

“Incident” means any occurrence or series of occurrences having the same origin arising out of or relating to the Vessel’s use of the Marine Terminal in which there is any one or more of the following: (i) loss of or damage to the Marine Terminal or the Vessel; (ii) injury to the employees and agents comprising Terminal Interests or Vessel Interests; (iii) loss or damage, other than to the Marine Terminal or the Vessel, caused or contributed to by the Vessel, including but not limited to, injury to third parties or damage to the property of third parties; or (iv) an obstruction or danger affecting or interfering with the normal operation of the Marine Terminal or the Port.

“Terminal Interests” means (i) Terminal, (ii) all Affiliates of Terminal, (iii) all Persons (other than the Vessel Interests and Persons providing fire boats, tugs and escort vessels to Vessel at the Port) employed or providing services at the Marine Terminal in connection with the loading, storage, or liquefaction of LNG at the Marine Terminal, and (iv) the employees and agents of all Persons referred to in this paragraph.

B-1

“Marine Terminal” means Terminal’s marine terminal and LNG liquefaction and storage facilities located at the Port, including all berths, buoys, gear, craft, equipment, plant, facilities and property of any kind (whether afloat or ashore) located thereat or adjacent thereto and in the ownership, possession or control of the Terminal Interests.

“Person” means any individual, firm, corporation, trust, partnership, association, joint venture (incorporated or unincorporated), or other business entity.

“Port” means the port at or near [INSERT LOCATION], including its anchorage, turning basin and approaches into the Marine Terminal associated therewith.

“Vessel Interests” means (i) Vessel Owner, (ii) all Affiliates of Vessel Owner, (iii) all Persons (other than the Terminal Interests) participating, employed, or providing services in connection with the ownership or operation (including all operations related to navigation and berthing/unberthing) of the Vessel, and (iv) the employees and agents of all Persons referred to in this paragraph.

2. In all circumstances, the Master of the Vessel shall remain solely responsible on behalf of the Vessel Interests for the proper navigation and safety of the Vessel and her cargo.

3. Any liability arising from an Incident shall, as between the Vessel Interests and the Terminal Interests, be borne (i) by the Vessel Interests alone, if the Vessel Interests are wholly or partially at fault and the Terminal Interests are not at fault, (ii) by the Terminal Interests alone, if the Terminal Interests are wholly or partially at fault and the Vessel Interests are not at fault, (iii) by the Vessel Interests and the Terminal Interests, in proportion to the degree of their respective fault, if both are at fault and the degree of such fault can be established or (iv) by the Vessel Interests and the Terminal Interests equally if neither of them appears to be at fault or it is not possible to establish the degree of their respective fault. In this regard, any acts or omissions of Persons providing fire boats, tugs and escort vessels to Vessel at the Port shall be deemed to be the responsibility of the Vessel Interests.

4.

(i) Terminal shall be solely responsible for claims brought by any employee and/or member of the family or dependent of any employee of Terminal arising out of or consequent upon the personal injury, loss or damage to property of, or death of such employee, family member or dependent, and Terminal shall indemnify and hold any Vessel Owner harmless in the event any such employee, or any family member or dependent thereof, or the executor, administrator, or personal representative of any of the foregoing, shall bring such a claim against any Vessel Owner.

(ii) The Vessel Owners shall be solely responsible for claims brought by any employee and/or member of the family or dependent of any employee of any Vessel Owner arising out of or consequent upon the personal injury, loss or damage to property of, or death of such employee, family member or dependent, and each Vessel Owner shall indemnify and hold Terminal harmless in the event any such employee, or any

B-2

family member or dependent thereof, or the executor, administrator or personal representative of any of the foregoing, shall bring such claim against Terminal.

(iii) Terminal and the Vessel Owners shall consult together to the extent practicable before either makes any payment which would fall due to be indemnified by the other under the terms of Sections 4(i) or 4(ii). The indemnities contained in Sections 4(i) and 4(ii) are separate and distinct from, and independent of, the obligations undertaken and the responsibilities and exceptions from and the limitations of liability provided in Sections 2, 3, 5 and 6 of this Agreement.

(iv) The cross indemnities provided in this Section 4 are intended to be binding regardless of fault or negligence on the part of the party in whose favor they are being given.

5.

(i) Subject to Section 5(ii) below, the total aggregate liability of the Vessel Interests to the Terminal Interests, however arising, in respect of any one Incident, shall not exceed one hundred fifty million dollars (US$150,000,000) or such higher coverage amount as the Vessel’s Protection and Indemnity Association then provides as a matter of normal practice for LNG vessels. Payment of an aggregate sum of one hundred fifty million dollars (US$150,000,000) or such higher amount (as applicable) to any one or more of the Terminal Interests in respect of any one Incident shall be a complete defense to any claim, suit or demand relating to such Incident made by the Terminal Interests against the Vessel Interests. The liability of the Vessel Interests hereunder shall be joint and several.

(ii) Vessel Interests shall provide to the Terminal Interests, upon request, sufficient written evidence that the Vessel’s Protection and Indemnity Association has agreed to cover the Vessel Interests as a member of the Association against the liabilities and responsibilities provided for in this Agreement in accordance with its Rules. Such evidence may include a true and correct copy of the Vessel’s certificate of entry with the Protection and Indemnity Association reflecting the agreement referenced in the immediately foregoing sentence.

(iii) Vessel Interests hereby expressly, voluntarily and intentionally waive in favor of the Terminal Interests all rights of subrogation of claims by Vessel Interests’ insurers against the Terminal Interests to the extent such claims have been waived in this Agreement by the Vessel Interests. Vessel Interests hereby agree to give the Terminal Interests prior written notice of any cancellation of the Vessel’s entry in its Protection and Indemnity Association.

6. As to matters subject to this Agreement and regardless of fault or negligence on the part of any Party, with respect to an Incident:

(i) except to the extent expressly preserved in this Agreement, Terminal Interests hereby expressly, voluntarily and intentionally waive any right or claims they might

B-3

otherwise have against the Vessel Interests under applicable laws or under any port liability agreement or similar port conditions of use previously signed by the Master for the Port; and

(ii) except to the extent expressly preserved in this Agreement, Vessel Interests hereby expressly, voluntarily and intentionally waive any rights to limit their liability to Terminal Interests under the United States Limitation of Vessel Owners Liability Act or any other similar law or convention, as applicable, in respect of any Incident. Such waiver shall include any right to petition a court, arbitral tribunal or other entity for limitation of liability, any right to claim limitation of liability as a defense in an action, and any other similar right under relevant law. The foregoing waivers shall apply to all Persons claiming through the Terminal Interests or through the Vessel Interests.

7. The substantive law of New York, without regard to any conflicts of law principles that could require the application of any other law, shall govern the interpretation of this Agreement and any dispute, controversy, or claim arising out of, relating to, or in any way connected with this Agreement, including, without limitation, the existence, validity, performance, or breach hereof.

IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their duly authorized representatives effective as of the date first set forth above.

[INSERT SIGNATURE OF TERMINAL ENTITY]	[INSERT SIGNATURES OF EACH OF VESSEL INTERESTS]
By:	By:
By:	By:
Title:	Title:
	As owner of the Name of Vessel Registration No. State of Registry

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EX-21.1

Exhibit 21.1

Subsidiaries of the Registrant as of December 31, 2019

Entity Name	Jurisdiction of Incorporation
Cheniere Corpus Christi Pipeline, L.P.	Delaware
Corpus Christi Liquefaction, LLC	Delaware
Corpus Christi Pipeline GP, LLC	Delaware

EX-31.1

Exhibit 31.1

CERTIFICATION BY PRESIDENT AND CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Michael J. Wortley, certify that:

1. I have reviewed this annual report on Form 10-K of Cheniere Corpus Christi Holdings, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 24, 2020

/s/ Michael J. Wortley

Michael J. Wortley

President and Chief Financial Officer of

Cheniere Corpus Christi Holdings, LLC

EX-32.1

Exhibit 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

In connection with the annual report of Cheniere Corpus Christi Holdings, LLC (the “Company”) on Form 10-K for the year ended December 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Wortley, President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 24, 2020

/s/ Michael J. Wortley

Michael J. Wortley

President and Chief Financial Officer of

Cheniere Corpus Christi Holdings, LLC

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Inventory

12 Months Ended

Dec. 31, 2019

Inventory Disclosure [Abstract]

Inventory

INVENTORY

As of December 31, 2019 and 2018, inventory consisted of the following (in thousands):

	December 31,
	2019		2018
Natural gas	$	6,870	$	1,326
LNG	6,103		—
Materials and other	56,206		24,872
Total inventory	$	69,179	$	26,198

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Accrued Liabilities

12 Months Ended

Dec. 31, 2019

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

As of December 31, 2019 and 2018, accrued liabilities consisted of the following (in thousands): 

	December 31,
	2019		2018
Interest costs and related debt fees	$	7,950	$	994
Accrued natural gas purchases	132,148		91,910
Liquefaction Project costs	192,215		46,964
Other	37,667		22,337
Total accrued liabilities	$	369,980	$	162,205

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2019, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contracts

CCL has a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 3 of the Liquefaction Project. The EPC contract price for Train 3 of the Liquefaction Project is approximately $2.4 billion, reflecting amounts incurred under change orders through December 31, 2019. As of December 31, 2019, we have incurred $2.0 billion under this contract. CCL has the right to terminate each of the EPC contracts for its convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.

Obligations under SPAs

CCL has third-party SPAs which obligate CCL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project. CCL has also entered into SPAs with Cheniere Marketing, as further described in Note 12—Related Party Transactions.

Obligations under 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 8 years, some of which commence upon the satisfaction of certain events or states of affairs. As of December 31, 2019, CCL had secured up to approximately 2,999 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the certain events or states of affairs are satisfied.

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, 2019, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in thousands): 

Years Ending December 31,	Payments Due (1)
2020	$	1,255,512
2021	1,047,335
2022	711,428
2023	591,844
2024	483,856
Thereafter	2,072,188
Total	$	6,162,163

(1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2019. 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. 

State Tax Sharing Agreement

CCL and CCP have a state tax sharing agreement with Cheniere.  See Note 12—Related Party Transactions for information regarding this agreement.

Other Commitments

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.

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. In the opinion of management, as of December 31, 2019, 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.

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Customer Concentration (Tables)

12 Months Ended

Dec. 31, 2019

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

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

	Percentage of Total Revenues from External Customers			Percentage of Accounts Receivable from External Customers
	Year Ended December 31,			December 31,
	2019	2018	2017	2019	2018
Customer A	57%	—%	—%	38%	—%
Customer B	23%	—%	—%	39%	—%

Schedule of Revenue from External Customers by Country

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in thousands). 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,
	2019		2018		2017
Spain	$	451,199	$	—	$	—
Indonesia	154,584		—		—
United States	73,287		—		—
Total	$	679,070	$	—	$	—

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Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Debt Instruments

As of December 31, 2019 and 2018, our debt consisted of the following (in thousands): 

	December 31,
	2019			2018
Long-term debt
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	$	1,250,000		$	1,250,000
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500,000			1,500,000
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500,000			1,500,000
4.80% Senior Secured Notes due 2039 (“4.80% CCH Senior Notes”)	727,000			—
3.925% Senior Secured Notes due 2039 (“3.925% CCH Senior Notes”)	475,000			—
3.700% Senior Secured Notes due 2029 (“2029 CCH Senior Notes”)	1,500,000			—
CCH Credit Facility	3,282,655			5,155,737
Unamortized debt issuance costs	(141,175		)	(160,185		)
Total long-term debt, net	10,093,480			9,245,552
Current debt
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	—			168,000
Total debt, net	$	10,093,480		$	9,413,552

Schedule of Maturities of Long-term Debt [Table Text Block]

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, 2019 (in thousands): 

Years Ending December 31,	Principal Payments
2020	$	—
2021	134,973
2022	118,507
2023	132,859
2024	4,146,316
Thereafter	5,702,000
Total	$	10,234,655

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2019 (in thousands):

	CCH Credit Facility		CCH Working Capital Facility
Original facility size	$	8,403,714	$	350,000
Incremental commitments	1,565,961		850,000
Less:
Outstanding balance	3,282,655		—
Commitments terminated	6,687,020		—
Letters of credit issued	—		470,784
Available commitment	$	—	$	729,216
Interest rate on available balance	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75%
Weighted average interest rate of outstanding balance	3.55%		n/a
Maturity date	June 30, 2024		June 29, 2023

Schedule of Interest Expense

Total interest expense consisted of the following (in thousands):

	Year Ended December 31,
	2019			2018			2017
Total interest cost	$	538,677		$	451,135		$	360,932
Capitalized interest, including amounts capitalized as an Allowance for Funds Used During Construction	(260,642		)	(451,135		)	(360,932		)
Total interest expense, net	$	278,035		$	—		$	—

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	December 31, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	5,750,000	$	6,329,200	$	4,250,000	$	4,228,750
4.80% CCH Senior Notes (2)	727,000		830,203		—		—
3.925% CCH Senior Notes (2)	475,000		495,291		—		—
Credit facilities (3)	3,282,655		3,282,655		5,323,737		5,323,737

(1) Includes 144A CCH Senior Notes. 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)

Includes CCH Credit Facility and CCH Working Capital Facility. 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.

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative assets		$ 73,809	$ 15,627
Derivative assets—related party		2,623	2,132
Non-current derivative assets		61,217	19,032
Non-current derivative assets—related party		1,933	3,381
Derivative liabilities		(46,486)	(13,576)
Non-current derivative liabilities		(134,667)	(8,595)
Derivative asset (liability), net
Total Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		0	18,474
Total derivative liabilities		(88,227)	(405)
Derivative asset (liability), net		(88,227)	18,069
Total Interest Rate Derivatives [Member] | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets		0	10,556
Total Interest Rate Derivatives [Member] | Non-current derivative assets
Derivatives, Fair Value [Line Items]
Non-current derivative assets		0	7,918
Total Interest Rate Derivatives [Member] | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities		(39,566)	(7)
Total Interest Rate Derivatives [Member] | Non-current derivative liabilities
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		(48,661)	(398)
Interest Rate Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		0	18,474
Total derivative liabilities		(80,645)	(405)
Derivative asset (liability), net		(80,645)	18,069
Interest Rate Derivatives [Member] | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets		0	10,556
Interest Rate Derivatives [Member] | Non-current derivative assets
Derivatives, Fair Value [Line Items]
Non-current derivative assets		0	7,918
Interest Rate Derivatives [Member] | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities		31,984	(7)
Interest Rate Derivatives [Member] | Non-current derivative liabilities
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		48,661	(398)
Interest Rate Forward Start Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets		0	0
Total derivative liabilities		(7,582)	0
Derivative asset (liability), net		(7,582)	0
Interest Rate Forward Start Derivatives [Member] | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets		0	0
Interest Rate Forward Start Derivatives [Member] | Non-current derivative assets
Derivatives, Fair Value [Line Items]
Non-current derivative assets		0	0
Interest Rate Forward Start Derivatives [Member] | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities		7,582	0
Interest Rate Forward Start Derivatives [Member] | Non-current derivative liabilities
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities		0	0
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	[1]	139,582	21,698
Total derivative liabilities	[1]	(92,926)	(21,766)
Derivative asset (liability), net	[1]	46,656	(68)
Derivative, collateral posted by us		4,500	4,500
Liquefaction Supply Derivatives [Member] | Derivative assets
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	73,809	5,071
Liquefaction Supply Derivatives [Member] | Derivative assets—related party
Derivatives, Fair Value [Line Items]
Derivative assets—related party	[1]	2,623	2,132
Liquefaction Supply Derivatives [Member] | Non-current derivative assets
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[1]	61,217	11,114
Liquefaction Supply Derivatives [Member] | Non-current derivative assets—related party
Derivatives, Fair Value [Line Items]
Non-current derivative assets—related party	[1]	1,933	3,381
Liquefaction Supply Derivatives [Member] | Derivative liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(6,920)	(13,569)
Liquefaction Supply Derivatives [Member] | Non-current derivative liabilities
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[1]	$ (86,006)	$ (8,197)

[1] Does not include collateral posted with counterparties by us of $4.5 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of both December 31, 2019 and 2018.

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Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 7,950	$ 994
Accrued natural gas purchases	132,148	91,910
Liquefaction Project costs	192,215	46,964
Other	37,667	22,337
Total accrued liabilities	$ 369,980	$ 162,205

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Customer Concentration - Schedule of Revenue from External Customers by Country (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Revenues from External Customers	$ 612,457	$ 386,559	$ 300,073	$ 106,081	$ 0	$ 0	$ 0	$ 0	$ 1,405,170	$ 0	$ 0
Geographic Concentration Risk [Member]
Concentration Risk [Line Items]
Revenues from External Customers									679,070	0	0
Geographic Concentration Risk [Member] | Spain
Concentration Risk [Line Items]
Revenues from External Customers									451,199	0	0
Geographic Concentration Risk [Member] | Indonesia
Concentration Risk [Line Items]
Revenues from External Customers									154,584	0	0
Geographic Concentration Risk [Member] | United States
Concentration Risk [Line Items]
Revenues from External Customers									$ 73,287	$ 0	$ 0

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Summarized Quarterly Financial Data (unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 612,457	$ 386,559	$ 300,073	$ 106,081	$ 0	$ 0	$ 0	$ 0	$ 1,405,170	$ 0	$ 0
Income (loss) from operations	234,561	(90,951)	(43,388)	(25,402)	(15,193)	2,345	(5,941)	(3,090)	74,820	(21,879)	(19,161)
Net income (loss)	$ 158,298	$ (272,410)	$ (188,907)	$ (71,277)	$ (91,113)	$ 24,388	$ 7,319	$ 65,692	$ (374,296)	$ 6,286	$ (48,652)

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Related Party Transactions - Equity Contribution Agreements (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Capital contributions	$ 710,737,000	$ 324,517,000	$ 402,119,000
Cheniere [Member] | Equity Contributions Agreement [Member]
Related Party Transaction [Line Items]
Capital contributions	557,900,000
Cheniere [Member] | Previous Equity Contributions Agreement [Member]
Related Party Transaction [Line Items]
Capital contributions	2,000,000,000.0
Cheniere [Member] | Early Works Equity Contribution Agreement [Member]
Related Party Transaction [Line Items]
Capital contributions	250,000,000.0
Maximum [Member] | Cheniere [Member] | Equity Contributions Agreement [Member]
Related Party Transaction [Line Items]
Capital contributions	1,100,000,000
Cheniere Revolving Credit Facility [Member]
Related Party Transaction [Line Items]
Letters of credit issued	585,000,000.0
CCH Credit Facility [Member]
Related Party Transaction [Line Items]
Letters of credit issued	0
CCH Credit Facility [Member] | Cheniere [Member] | Equity Contributions Agreement [Member]
Related Party Transaction [Line Items]
Related Party Agreement, Additional Contribution Requirement, Debt Instrument, Commitments Reduction Threshold	$ 0

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Related Party Transactions - LNG Sale and Purchase Agreements (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) tbtu	Dec. 31, 2018 USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate | $	$ 57,211	$ 21,060
Cheniere Marketing EOG SPA [Member] | Maximum [Member]
Related Party Transaction [Line Items]
SPA, Term of Agreement	7 years
CCL [Member] | Cheniere Marketing SPA and Cheniere Marketing Base SPA [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
Accounts receivable—affiliate | $	$ 57,200	$ 21,100
CCL [Member] | Cheniere Marketing Base SPA [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
SPA, Term of Agreement	20 years
CCL [Member] | Cheniere Marketing Base SPA [Member] | Cheniere Marketing [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Volumes	150
CCL [Member] | Cheniere Marketing SPA [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
SPA, Term of Agreement	23 years
Contract Volumes	15
CCL [Member] | Cheniere Marketing EOG SPA [Member] | Cheniere Marketing [Member]
Related Party Transaction [Line Items]
Contract Volumes	0.85

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Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 0	$ 0
Restricted cash	79,741	289,141
Accounts and other receivables	57,712	24,989
Accounts receivable—affiliate	57,211	21,060
Advances to affiliate	115,476	94,397
Inventory	69,179	26,198
Derivative assets	73,809	15,627
Derivative assets—related party	2,623	2,132
Other current assets	14,852	15,217
Other current assets—affiliate	5	633
Total current assets	470,608	489,394
Property, plant and equipment, net	12,507,419	11,138,825
Debt issuance and deferred financing costs, net	14,705	38,012
Non-current derivative assets	61,217	19,032
Non-current derivative assets—related party	1,933	3,381
Investments in subsidiaries	0	0
Other non-current assets, net	55,630	31,709
Total assets	13,111,512	11,720,353
Current liabilities
Accounts payable	7,290	16,202
Accrued liabilities	369,980	162,205
Accrued liabilities—related party	2,531	0
Current debt	0	168,000
Due to affiliates	26,900	25,086
Derivative liabilities	46,486	13,576
Other current liabilities	364	0
Other current liabilities—affiliate	519	0
Total current liabilities	454,070	385,069
Long-term debt, net	10,093,480	9,245,552
Non-current derivative liabilities	134,667	8,595
Other non-current liabilities	10,433	0
Other non-current liabilities—affiliate	1,284	0
Member’s equity	2,417,578	2,081,137	$ 1,667,276	$ 1,313,809
Total liabilities and member’s equity	13,111,512	11,720,353
Parent Issuer [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	68,787	282,248
Accounts and other receivables	0	0
Accounts receivable—affiliate	0	0
Advances to affiliate	0	0
Inventory	0	0
Derivative assets	0	10,556
Derivative assets—related party	0	0
Other current assets	249	178
Other current assets—affiliate	0	0
Total current assets	69,036	292,982
Property, plant and equipment, net	1,330,748	1,094,671
Debt issuance and deferred financing costs, net	14,705	38,012
Non-current derivative assets	0	7,917
Non-current derivative assets—related party	0	0
Investments in subsidiaries	11,224,400	10,194,296
Other non-current assets, net	0	1
Total assets	12,638,889	11,627,879
Current liabilities
Accounts payable	32	71
Accrued liabilities	9,488	1,242
Accrued liabilities—related party	0
Current debt		168,000
Due to affiliates	337	0
Derivative liabilities	39,566	6
Other current liabilities	0
Other current liabilities—affiliate	0
Total current liabilities	49,423	169,319
Long-term debt, net	10,093,480	9,245,552
Non-current derivative liabilities	48,661	398
Other non-current liabilities	0
Other non-current liabilities—affiliate	0
Member’s equity	2,447,325	2,212,610
Total liabilities and member’s equity	12,638,889	11,627,879
Guarantors [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	10,954	6,893
Accounts and other receivables	57,712	24,989
Accounts receivable—affiliate	57,211	21,060
Advances to affiliate	115,476	94,397
Inventory	69,179	26,198
Derivative assets	73,809	5,071
Derivative assets—related party	2,623	2,132
Other current assets	14,603	15,039
Other current assets—affiliate	5	634
Total current assets	401,572	196,413
Property, plant and equipment, net	11,176,671	10,044,154
Debt issuance and deferred financing costs, net	0	0
Non-current derivative assets	61,217	11,115
Non-current derivative assets—related party	1,933	3,381
Investments in subsidiaries	0	0
Other non-current assets, net	55,630	31,708
Total assets	11,697,023	10,286,771
Current liabilities
Accounts payable	7,258	16,131
Accrued liabilities	360,492	160,963
Accrued liabilities—related party	2,531
Current debt		0
Due to affiliates	26,563	25,086
Derivative liabilities	6,920	13,570
Other current liabilities	364
Other current liabilities—affiliate	519
Total current liabilities	404,647	215,750
Long-term debt, net	0	0
Non-current derivative liabilities	86,006	8,197
Other non-current liabilities	10,433
Other non-current liabilities—affiliate	1,284
Member’s equity	11,194,653	10,062,824
Total liabilities and member’s equity	11,697,023	10,286,771
Eliminations [Member]
Current assets
Cash and cash equivalents	0	0
Restricted cash	0	0
Accounts and other receivables	0	0
Accounts receivable—affiliate	0	0
Advances to affiliate	0	0
Inventory	0	0
Derivative assets	0	0
Derivative assets—related party	0	0
Other current assets	0	0
Other current assets—affiliate	0	(1)
Total current assets	0	(1)
Property, plant and equipment, net	0	0
Debt issuance and deferred financing costs, net	0	0
Non-current derivative assets	0	0
Non-current derivative assets—related party	0	0
Investments in subsidiaries	(11,224,400)	(10,194,296)
Other non-current assets, net	0	0
Total assets	(11,224,400)	(10,194,297)
Current liabilities
Accounts payable	0	0
Accrued liabilities	0	0
Accrued liabilities—related party	0
Current debt		0
Due to affiliates	0	0
Derivative liabilities	0	0
Other current liabilities	0
Other current liabilities—affiliate	0
Total current liabilities	0	0
Long-term debt, net	0	0
Non-current derivative liabilities	0	0
Other non-current liabilities—affiliate	0
Member’s equity	(11,224,400)	(10,194,297)
Total liabilities and member’s equity	$ (11,224,400)	$ (10,194,297)

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 12,507,419	$ 11,138,825
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(232,451)	(7,416)
Property, plant and equipment, net	12,495,845	11,126,433
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	10,027,111	618,547
LNG site and related costs [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	275,959	44,725
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,425,226	10,470,577
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19,083	15,534
Accumulated depreciation	(7,509)	(3,142)
Property, plant and equipment, net	$ 11,574	$ 12,392

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Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 79,741	$ 289,141
Liquefaction Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 79,741	$ 289,141

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Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues
Revenues	$ 612,457	$ 386,559	$ 300,073	$ 106,081	$ 0	$ 0	$ 0	$ 0	$ 1,405,170	$ 0	$ 0
Revenues from contracts with customers									1,404,943	0	0
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)									691,301	172	91
Cost of sales—affiliate									3,015	0	0
Cost of sales—related party									85,429	0	0
Operating and maintenance expense (recovery)									242,027	(96)	3,024
Operating and maintenance expense—affiliate									59,319	4,283	2,401
Development expense									596	177	516
Development expense—affiliate									61	0	8
General and administrative expense									6,106	5,263	5,551
General and administrative expense—affiliate									11,352	2,201	1,173
Depreciation and amortization expense									230,780	9,859	892
Impairment expense and loss on disposal of assets									364	20	5,505
Total operating costs and expenses									1,330,350	21,879	19,161
Income (loss) from operations	234,561	(90,951)	(43,388)	(25,402)	(15,193)	2,345	(5,941)	(3,090)	74,820	(21,879)	(19,161)
Other income (expense)
Interest expense, net of capitalized interest									(278,035)	0	0
Loss on modification or extinguishment of debt									(41,296)	(15,332)	(32,480)
Derivative gain (loss), net									(133,427)	43,105	3,249
Other income (expense)									3,642	392	(260)
Total other income (expense)									(449,116)	28,165	(29,491)
Net income (loss)	$ 158,298	$ (272,410)	$ (188,907)	$ (71,277)	$ (91,113)	$ 24,388	$ 7,319	$ 65,692	(374,296)	6,286	(48,652)
LNG [Member]
Revenues
Revenues									679,070	0	0
Revenues from contracts with customers									678,843	0	0
LNG—affiliate [Member]
Revenues
Revenues from contracts with customers									$ 726,100	$ 0	$ 0

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Organization and Nature of Operations

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Operations

ORGANIZATION AND NATURE OF OPERATIONSCCH is a Houston-based Delaware limited liability company formed in September 2014 by Cheniere to hold its limited partner interest in CCP and its equity interests in CCL and CCP GP. We are operating and constructing a natural gas liquefaction and export facility (the “Liquefaction Facilities”) and operating a 23-mile natural gas supply pipeline that interconnects the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Liquefaction Facilities, the “Liquefaction Project”) near Corpus Christi, Texas, through our subsidiaries CCL and CCP, respectively. We are currently operating two Trains and are constructing one additional Train for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain three LNG storage tanks and two marine berths.

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Debt - Credit Facilities Table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Outstanding balance, current	$ 0	$ 168,000
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	8,403,714
Incremental commitments	1,565,961
Outstanding balance	3,282,655	$ 5,155,737
Commitments terminated	6,687,020
Letters of credit issued	0
Available commitment	$ 0
Debt Instrument, Description of Variable Rate Basis	LIBOR or the base rate
Weighted average interest rate of outstanding balance	3.55%
Maturity Date	Jun. 30, 2024
CCH Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	$ 350,000
Incremental commitments	850,000
Outstanding balance, current	0
Commitments terminated	0
Letters of credit issued	470,784
Available commitment	$ 729,216
Debt Instrument, Description of Variable Rate Basis	LIBOR or the base rate
Maturity Date	Jun. 29, 2023
CCH Working Capital Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.25%
CCH Working Capital Facility [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.25%
CCH Working Capital Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
CCH Working Capital Facility [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value		$ 10,093,480	$ 9,413,552
Senior notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[1]	5,750,000	4,250,000
Senior notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	[1]	6,329,200	4,228,750
4.8% CCH Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[2]	727,000	0
4.8% CCH Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	[2]	830,203	0
3.925% CCH Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[2]	475,000	0
3.925% CCH Senior Notes [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	[2]	495,291	0
Credit facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt, Carrying Value	[3]	3,282,655	5,323,737
Credit facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[3]	$ 3,282,655	$ 5,323,737

[1] ncludes 144A CCH Senior Notes. 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] he 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] ncludes CCH Credit Facility and CCH Working Capital Facility. 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.

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 726,100	$ 0	$ 0
Cost of sales—affiliate	3,015	0	0
Cost of sales—related party	85,429	0	0
Operating and maintenance expense—affiliate	59,319	4,283	2,401
Development expense—affiliate	61	0	8
General and administrative expense—affiliate	11,352	2,201	1,173
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	719,069	0	0
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	7,031	0	0
Cost of sales—affiliate	3,015	0	0
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—related party	85,429	0	0
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	58,576	3,412	2,075
Development expense—affiliate	61	0	8
General and administrative expense—affiliate	11,352	2,201	1,173
Land Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	743	874	326
Other Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	$ 0	$ (3)	$ 0

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Summarized Quarterly Financial Data (unaudited)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (unaudited)

Summarized Quarterly Financial Data—(in thousands)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2019:
Revenues	$	106,081		$	300,073		$	386,559		$	612,457
Income (loss) from operations	(25,402		)	(43,388		)	(90,951		)	234,561
Net income (loss)	(71,277		)	(188,907		)	(272,410		)	158,298
Year ended December 31, 2018:
Revenues	$	—		$	—		$	—		$	—
Income (loss) from operations	(3,090		)	(5,941		)	2,345			(15,193		)
Net income (loss)	65,692			7,319			24,388			(91,113		)

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Inventory (Tables)

12 Months Ended

Dec. 31, 2019

Inventory Disclosure [Abstract]

Schedule of Inventory

As of December 31, 2019 and 2018, inventory consisted of the following (in thousands):

	December 31,
	2019		2018
Natural gas	$	6,870	$	1,326
LNG	6,103		—
Materials and other	56,206		24,872
Total inventory	$	69,179	$	26,198

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 0	$ 0
Restricted cash	79,741	289,141
Accounts and other receivables	57,712	24,989
Accounts receivable—affiliate	57,211	21,060
Advances to affiliate	115,476	94,397
Inventory	69,179	26,198
Derivative assets	73,809	15,627
Derivative assets—related party	2,623	2,132
Other current assets	14,852	15,217
Other current assets—affiliate	5	633
Total current assets	470,608	489,394
Property, plant and equipment, net	12,507,419	11,138,825
Debt issuance and deferred financing costs, net	14,705	38,012
Non-current derivative assets	61,217	19,032
Non-current derivative assets—related party	1,933	3,381
Other non-current assets, net	55,630	31,709
Total assets	13,111,512	11,720,353
Current liabilities
Accounts payable	7,290	16,202
Accrued liabilities	369,980	162,205
Accrued liabilities—related party	2,531	0
Current debt	0	168,000
Due to affiliates	26,900	25,086
Derivative liabilities	46,486	13,576
Other current liabilities	364	0
Other current liabilities—affiliate	519	0
Total current liabilities	454,070	385,069
Long-term debt, net	10,093,480	9,245,552
Non-current derivative liabilities	134,667	8,595
Other non-current liabilities	10,433	0
Other non-current liabilities—affiliate	1,284	0
Commitments and contingencies (see Note 13)
Member’s equity	2,417,578	2,081,137
Total liabilities and member’s equity	$ 13,111,512	$ 11,720,353

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Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 0	$ 0
Restricted cash	79,741	289,141
Total cash, cash equivalents and restricted cash	$ 79,741	$ 289,141	$ 226,559	$ 270,540

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Property, Plant and Equipment - Schedule of Useful Lives (Details)	12 Months Ended
	Dec. 31, 2019
LNG terminal costs [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
LNG terminal costs [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Water pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years
Natural gas pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
Liquefaction processing equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Liquefaction processing equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	15 years
Other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years

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Accounts and Other Receivables (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Receivables [Abstract]
Trade receivable	$ 44,403	$ 51
Other accounts receivable	13,309	24,938
Total accounts and other receivables	$ 57,712	$ 24,989

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Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Dec. 31, 2019	Dec. 31, 2018
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 34.6	$ 34.9
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 33.6	$ 33.9
Weighted Average Recognition Timing	[1]	11 years	12 years
LNG—affiliate [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 1.0	$ 1.0
Weighted Average Recognition Timing	[1]	13 years	14 years

[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.

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Debt - Senior Notes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Nov. 06, 2019	Oct. 17, 2019	Sep. 27, 2019
Debt Instrument [Line Items]
Loss on modification or extinguishment of debt	$ (41,296)	$ (15,332)	$ (32,480)
Corpus Christi Holdings Senior Notes [Member]
Debt Instrument [Line Items]
Loss on modification or extinguishment of debt	$ 38,700
Debt Instrument, Redemption Period, Minimum Number of Months Prior to Maturity Date, Redemption Price Equals Make Whole Price	6 months
Debt Instrument, Redemption Period, Maximum Number of Months Prior to Maturity Date, Redemption Price Equals Principal Amount	6 months
Debt Instrument, Redemption Price, Percentage	100.00%
4.8% CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount						$ 727,000
Debt Instrument, Interest Rate, Stated Percentage	4.80%
4.8% CCH Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Term	15 years
3.925% CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 475,000
Debt Instrument, Interest Rate, Stated Percentage	3.925%
3.925% CCH Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Term	15 years
2029 Corpus Christi Holdings Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 1,500,000
Debt Instrument, Interest Rate, Stated Percentage	3.70%

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Debt - Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Total interest cost	$ 538,677	$ 451,135	$ 360,932
Capitalized interest, including amounts capitalized as an Allowance for Funds Used During Construction	(260,642)	(451,135)	(360,932)
Total interest expense, net	$ 278,035	$ 0	$ 0

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Supplemental Guarantor Information

12 Months Ended

Dec. 31, 2019

Supplemental Guarantor Information [Abstract]

Supplemental Guarantor Information

SUPPLEMENTAL GUARANTOR INFORMATION

Our CCH Senior Notes are jointly and severally guaranteed by our subsidiaries, CCL, CCP and CCP GP (each a “Guarantor” and collectively, the “Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) the designation of the Guarantor as an “unrestricted subsidiary” in accordance with the indentures governing each of 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. See Note 10—Debt for additional information regarding the CCH Senior Notes.

The following is condensed consolidating financial information for CCH (“Parent Issuer”) and the Guarantors. We did not have any non-guarantor subsidiaries as of December 31, 2019.

Condensed Consolidating Balance Sheet
December 31, 2019
(in thousands)
	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	68,787		10,954		—			79,741
Accounts and other receivables	—		57,712		—			57,712
Accounts receivable—affiliate	—		57,211		—			57,211
Advances to affiliate	—		115,476		—			115,476
Inventory	—		69,179		—			69,179
Derivative assets	—		73,809		—			73,809
Derivative assets—related party	—		2,623		—			2,623
Other current assets	249		14,603		—			14,852
Other current assets—affiliate	—		5		—			5
Total current assets	69,036		401,572		—			470,608
Property, plant and equipment, net	1,330,748		11,176,671		—			12,507,419
Debt issuance and deferred financing costs, net	14,705		—		—			14,705
Non-current derivative assets	—		61,217		—			61,217
Non-current derivative assets—related party	—		1,933		—			1,933
Investments in subsidiaries	11,224,400		—		(11,224,400		)	—
Other non-current assets, net	—		55,630		—			55,630
Total assets	$	12,638,889	$	11,697,023	$	(11,224,400	)	$	13,111,512
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	32	$	7,258	$	—		$	7,290
Accrued liabilities	9,488		360,492		—			369,980
Accrued liabilities—related party	—		2,531		—			2,531
Due to affiliates	337		26,563		—			26,900
Derivative liabilities	39,566		6,920		—			46,486
Other current liabilities	—		364		—			364
Other current liabilities—affiliate	—		519		—			519
Total current liabilities	49,423		404,647		—			454,070
Long-term debt, net	10,093,480		—		—			10,093,480
Non-current derivative liabilities	48,661		86,006		—			134,667
Other non-current liabilities	—		10,433		—			10,433
Other non-current liabilities—affiliate	—		1,284		—			1,284
Member’s equity	2,447,325		11,194,653		(11,224,400		)	2,417,578
Total liabilities and member’s equity	$	12,638,889	$	11,697,023	$	(11,224,400	)	$	13,111,512

Condensed Consolidating Balance Sheet
December 31, 2018
(in thousands)
	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	282,248		6,893		—			289,141
Accounts and other receivables	—		24,989		—			24,989
Accounts receivable—affiliate	—		21,060		—			21,060
Advances to affiliate	—		94,397		—			94,397
Inventory	—		26,198		—			26,198
Derivative assets	10,556		5,071		—			15,627
Derivative assets—related party	—		2,132		—			2,132
Other current assets	178		15,039		—			15,217
Other current assets—affiliate	—		634		(1		)	633
Total current assets	292,982		196,413		(1		)	489,394
Property, plant and equipment, net	1,094,671		10,044,154		—			11,138,825
Debt issuance and deferred financing costs, net	38,012		—		—			38,012
Non-current derivative assets	7,917		11,115		—			19,032
Non-current derivative assets—related party	—		3,381		—			3,381
Investments in subsidiaries	10,194,296		—		(10,194,296		)	—
Other non-current assets, net	1		31,708		—			31,709
Total assets	$	11,627,879	$	10,286,771	$	(10,194,297	)	$	11,720,353
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	71	$	16,131	$	—		$	16,202
Accrued liabilities	1,242		160,963		—			162,205
Current debt	168,000		—		—			168,000
Due to affiliates	—		25,086		—			25,086
Derivative liabilities	6		13,570		—			13,576
Total current liabilities	169,319		215,750		—			385,069
Long-term debt, net	9,245,552		—		—			9,245,552
Non-current derivative liabilities	398		8,197		—			8,595
Member’s equity	2,212,610		10,062,824		(10,194,297		)	2,081,137
Total liabilities and member’s equity	$	11,627,879	$	10,286,771	$	(10,194,297	)	$	11,720,353

Condensed Consolidating Statement of Operations
Year Ended December 31, 2019
(in thousands)
	Parent Issuer			Guarantors		Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	679,070	$	—		$	679,070
LNG revenues—affiliate	—			726,100		—			726,100
Total revenues	—			1,405,170		—			1,405,170
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			691,301		—			691,301
Cost of sales—affiliate	—			3,015		—			3,015
Cost of sales—related party	—			85,429		—			85,429
Operating and maintenance expense	—			242,027		—			242,027
Operating and maintenance expense—affiliate	—			59,319		—			59,319
Development expense	—			596		—			596
Development expense—affiliate	—			61		—			61
General and administrative expense	2,082			4,024		—			6,106
General and administrative expense—affiliate	—			11,352		—			11,352
Depreciation and amortization expense	24,297			206,483		—			230,780
Impairment expense and loss on disposal of assets	—			364		—			364
Total operating costs and expenses	26,379			1,303,971		—			1,330,350
Income (loss) from operations	(26,379		)	101,199		—			74,820
Other income (expense)
Interest expense, net of capitalized interest	(278,035		)	—		—			(278,035		)
Loss on modification or extinguishment of debt	(41,296		)	—		—			(41,296		)
Derivative loss, net	(133,427		)	—		—			(133,427		)
Other income	3,387			528		(273		)	3,642
Total other income (expense)	(449,371		)	528		(273		)	(449,116		)
Net income (loss)	$	(475,750	)	$	101,727	$	(273	)	$	(374,296	)

Condensed Consolidating Statement of Operations
Year Ended December 31, 2018
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Revenues	$	—		$	—		$	—		$	—
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			172			—			172
Operating and maintenance recovery	—			(96		)	—			(96		)
Operating and maintenance expense—affiliate	—			4,283			—			4,283
Development expense	—			177			—			177
General and administrative expense	1,513			3,750			—			5,263
General and administrative expense—affiliate	—			2,201			—			2,201
Depreciation and amortization expense	239			9,620			—			9,859
Impairment expense and gain on disposal of assets	—			20			—			20
Total operating costs and expenses	1,752			20,127			—			21,879
Loss from operations	(1,752		)	(20,127		)	—			(21,879		)
Other income (expense)
Loss on modification or extinguishment of debt	(15,332		)	—			—			(15,332		)
Derivative gain, net	43,105			—			—			43,105
Other income	352			7,952			(7,912		)	392
Total other income	28,125			7,952			(7,912		)	28,165
Net income (loss)	$	26,373		$	(12,175	)	$	(7,912	)	$	6,286

Condensed Consolidating Statement of Operations
Year Ended December 31, 2017
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Revenues	$	—		$	—		$	—		$	—
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			91			—			91
Operating and maintenance expense	—			3,024			—			3,024
Operating and maintenance expense—affiliate	—			2,401			—			2,401
Development expense	—			516			—			516
Development expense—affiliate	—			8			—			8
General and administrative expense	1,360			4,191			—			5,551
General and administrative expense—affiliate	—			1,173			—			1,173
Depreciation and amortization expense	13			879			—			892
Impairment expense and gain on disposal of assets	—			5,505			—			5,505
Total operating costs and expenses	1,373			17,788			—			19,161
Loss from operations	(1,373		)	(17,788		)	—			(19,161		)
Other income (expense)
Loss on modification or extinguishment of debt	(32,480		)	—			—			(32,480		)
Derivative gain, net	3,249			—			—			3,249
Other income (expense)	(265		)	15,580			(15,575		)	(260		)
Total other income (expense)	(29,496		)	15,580			(15,575		)	(29,491		)
Net loss	$	(30,869	)	$	(2,208	)	$	(15,575	)	$	(48,652	)

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2019
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(237,471	)	$	250,856		$	(46,758	)	$	(33,373	)
Cash flows from investing activities
Property, plant and equipment, net	(242,322		)	(1,274,840		)	—			(1,517,162		)
Investments in subsidiaries	(2,711,350		)	—			2,711,350			—
Distributions received from affiliates	1,634,489			—			(1,634,489		)	—
Other	—			(2,058		)	—			(2,058		)
Net cash used in investing activities	(1,319,183		)	(1,276,898		)	1,076,861			(1,519,220		)
Cash flows from financing activities
Proceeds from issuances of debt	4,203,550			—			—			4,203,550
Repayments of debt	(3,543,757		)	—			—			(3,543,757		)
Debt issuance and deferred financing costs	(16,210		)	—			—			(16,210		)
Debt extinguishment cost	(11,127		)	—			—			(11,127		)
Capital contributions	710,737			2,711,350			(2,711,350		)	710,737
Distributions	—			(1,681,247		)	1,681,247			—
Net cash provided by financing activities	1,343,193			1,030,103			(1,030,103		)	1,343,193
Net increase (decrease) in cash, cash equivalents and restricted cash	(213,461		)	4,061			—			(209,400		)
Cash, cash equivalents and restricted cash—beginning of period	282,248			6,893			—			289,141
Cash, cash equivalents and restricted cash—end of period	$	68,787		$	10,954		$	—		$	79,741

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2019
	Parent Issuer		Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—
Restricted cash	68,787		10,954		—		79,741
Total cash, cash equivalents and restricted cash	$	68,787	$	10,954	$	—	$	79,741

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2018
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows used in operating activities	$	(6,854	)	$	(51,913	)	$	(1,395	)	$	(60,162	)
Cash flows from investing activities
Property, plant and equipment, net	(555,946		)	(2,406,990		)	—			(2,962,936		)
Investments in subsidiaries	(2,532,266		)	—			2,532,266			—
Distributions received from affiliates	67,744			—			(67,744		)	—
Other	—			2,669			—			2,669
Net cash used in investing activities	(3,020,468		)	(2,404,321		)	2,464,522			(2,960,267		)
Cash flows from financing activities
Proceeds from issuances of debt	3,114,800			—			—			3,114,800
Repayments of debt	(301,455		)	—			—			(301,455		)
Debt issuance and deferred financing costs	(45,743		)	—			—			(45,743		)
Debt extinguishment cost	(9,108		)	—			—			(9,108		)
Capital contributions	324,517			2,532,266			(2,532,266		)	324,517
Distributions	—			(69,139		)	69,139			—
Net cash provided by financing activities	3,083,011			2,463,127			(2,463,127		)	3,083,011
Net increase in cash, cash equivalents and restricted cash	55,689			6,893			—			62,582
Cash, cash equivalents and restricted cash—beginning of period	226,559			—			—			226,559
Cash, cash equivalents and restricted cash—end of period	$	282,248		$	6,893		$	—		$	289,141

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2018
	Parent Issuer		Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—
Restricted cash	282,248		6,893		—		289,141
Total cash, cash equivalents and restricted cash	$	282,248	$	6,893	$	—	$	289,141

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows used in operating activities	$	(52,633	)	$	(11,683	)	$	—		$	(64,316	)
Cash flows from investing activities
Property, plant and equipment, net	(253,612		)	(1,733,642		)	—			(1,987,254		)
Investments in subsidiaries	(1,720,280		)	—			1,720,280			—
Other	—			25,045			—			25,045
Net cash used in investing activities	(1,973,892		)	(1,708,597		)	1,720,280			(1,962,209		)
Cash flows from financing activities
Proceeds from issuances of debt	3,040,000			—			—			3,040,000
Repayments of debt	(1,436,050		)	—			—			(1,436,050		)
Debt issuance and deferred financing costs	(23,496		)	—			—			(23,496		)
Debt extinguishment cost	(29		)	—			—			(29		)
Capital contributions	402,119			1,720,437			(1,720,437		)	402,119
Distributions	—			(157		)	157			—
Net cash provided by financing activities	1,982,544			1,720,280			(1,720,280		)	1,982,544
Net decrease in cash, cash equivalents and restricted cash	(43,981		)	—			—			(43,981		)
Cash, cash equivalents and restricted cash—beginning of period	270,540			—			—			270,540
Cash, cash equivalents and restricted cash—end of period	$	226,559		$	—		$	—		$	226,559

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Accounts and Other Receivables (Tables)

12 Months Ended

Dec. 31, 2019

Receivables [Abstract]

Schedule of Accounts and Other Receivables

As of December 31, 2019 and 2018, accounts and other receivables consisted of the following (in thousands):

	December 31,
	2019		2018
Trade receivable	$	44,403	$	51
Other accounts receivable	13,309		24,938
Total accounts and other receivables	$	57,712	$	24,989

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Related Party Transactions

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018			2017
LNG revenues—affiliate
Cheniere Marketing Agreements	$	719,069	$	—		$	—
Contracts for Sale and Purchase of Natural Gas and LNG	7,031		—			—
Total LNG revenues—affiliate	726,100		—			—
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	3,015		—			—
Cost of sales—related party
Natural Gas Supply Agreement	85,429		—			—
Operating and maintenance expense—affiliate
Services Agreements	58,576		3,412			2,075
Land Agreements	743		874			326
Other Agreements	—		(3		)	—
Total operating and maintenance expense—affiliate	59,319		4,283			2,401
Development expense—affiliate
Services Agreements	61		—			8
General and administrative expense—affiliate
Services Agreements	11,352		2,201			1,173

We had $26.9 million and $25.1 million due to affiliates as of December 31, 2019 and 2018, respectively, under agreements with affiliates, as described below.

Cheniere Marketing Agreements

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 an approximate term of 23 years with Cheniere Marketing which allows them to purchase volumes of approximately 15 TBtu per annum of LNG and (2) an SPA for 0.85 mtpa of LNG with a term of up to seven years associated with the integrated production marketing gas supply agreement between CCL and EOG Resources, Inc. As of December 31, 2019 and 2018, CCL had $57.2 million and $21.1 million of accounts receivable—affiliate, respectively, under these agreements.

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. 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 has entered into a natural gas supply contract to obtain feed gas for the operation of the Liquefaction Project through March 2022 with a related party in the ordinary course of business. CCL recorded $85.4 million in cost of sales—related party under this contract during the year ended December 31, 2019. Of this amount, $2.5 million and zero was included in accrued liabilities—related party as of December 31, 2019 and 2018, respectively. CCL did not have any deliveries during the year ended December 31, 2018 under this contract. CCL also has recorded derivative assets—related party of $2.6 million and $2.1 million and non-current derivative assets—related party of $1.9 million and $3.4 million as of December 31, 2019 and 2018, respectively, related to this contract.

Agreements with Midship Pipeline

CCL has entered into a transportation precedent agreement and a negotiated rate agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) to secure firm pipeline transportation capacity for a period of 10 years following commencement of the approximately 200-mile natural gas pipeline project which Midship Pipeline is constructing. In May 2018, CCL issued a letter of credit to Midship Pipeline for drawings up to an aggregate maximum amount of $16.2 million. Midship Pipeline had not made any drawings on this letter of credit as of December 31, 2019.

Natural Gas Transportation Agreement

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 that allows them to sell and purchase natural gas with each other. CCL did not have any transactions under this agreement during the year ended December 31, 2019.

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 five 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.

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 for which Cheniere could have demanded payment from CCL under this agreement; therefore, Cheniere has not demanded any such payments from CCL. 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 for which Cheniere could have demanded payment from CCP under this agreement; therefore, Cheniere has not demanded any such payments from CCP. 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, 2019, we have received $557.9 million in contributions under the Equity Contribution Agreement and Cheniere has posted $585.0 million of 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.

Early Works Equity Contribution Agreement

In conjunction with the amendment and restatement of the Equity Contribution Agreement, we terminated the early works equity contribution agreement with Cheniere entered into in December 2017. Prior to termination in May 2018, we had received $250.0 million in contributions from Cheniere under the early works equity contribution agreement.

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Accounts and Other Receivables

12 Months Ended

Dec. 31, 2019

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2019 and 2018, accounts and other receivables consisted of the following (in thousands):

	December 31,
	2019		2018
Trade receivable	$	44,403	$	51
Other accounts receivable	13,309		24,938
Total accounts and other receivables	$	57,712	$	24,989

XML

Other Non-Current Assets

12 Months Ended

Dec. 31, 2019

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

As of December 31, 2019 and 2018, other non-current assets, net consisted of the following (in thousands):

	December 31,
	2019		2018
Advances and other asset conveyances to third parties to support LNG terminal	$	18,703	$	18,209
Operating lease assets	7,215		—
Tax-related payments and receivables	3,200		3,783
Information technology service prepayments	3,010		2,435
Advances made under EPC and non-EPC contracts	14,067		—
Other	9,435		7,282
Total other non-current assets, net	$	55,630	$	31,709

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Year Ended December 31,
	2019		2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	258,491	$	104,811	$	—
Non-cash capital contribution for conveyance of property, plant and equipment from affiliate	—		83,058		—

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Revenues from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018		2017
LNG revenues	$	678,843	$	—	$	—
LNG revenues—affiliate	726,100		—		—
Total revenues from customers	1,404,943		—		—
Net derivative gains (1)	227		—		—
Total revenues	$	1,405,170	$	—	$	—

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

Transaction Price Allocated to Future Performance Obligations

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, 2019 and 2018:

	December 31, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	33.6	11	$	33.9	12
LNG revenues—affiliate	1.0		13	1.0		14
Total revenues	$	34.6		$	34.9

(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.

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Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Interest Rate Derivatives [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 4,500	$ 4,000
Effective Date	May 20, 2015
Maturity Date	May 31, 2022
Weighted Average Fixed Interest Rate Paid	2.30%
Interest Rate Forward Start Derivatives [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 750	$ 0
Effective Date	Sep. 30, 2020
Maturity Date	Dec. 31, 2030
Weighted Average Fixed Interest Rate Paid	2.06%

XML

Other Non-Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Other Assets, Noncurrent [Abstract]
Advances and other asset conveyances to third parties to support LNG terminal	$ 18,703	$ 18,209
Operating lease assets	7,215	0
Tax-related payments and receivables	3,200	3,783
Information technology service prepayments	3,010	2,435
Advances made under EPC and non-EPC contracts	14,067	0
Other	9,435	7,282
Total other non-current assets, net	$ 55,630	$ 31,709

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Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) tbtu item
Commitments and Contingencies [Line Items]
Loss Contingency, Pending Claims, Number | item	0
CCL [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Energy Units Secured Through Natural Gas Supply Agreements | tbtu	2,999
BechtelEPCContractTrainThree [Member] | CCL [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Amount	$ 2,400
Long-term Purchase Commitment, Amount Incurred To Date	2,000
Contract termination convenience penalty	$ 30
Natural Gas Supply Agreements [Member] | CCL [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	8 years
Natural Gas Transportation Agreements [Member] | CCL [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	20 years
Storage Service Agreements [Member] | CCL [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	5 years

XML

Related Party Transactions - Service Agreements (Details) - CCL [Member]	12 Months Ended
	Dec. 31, 2019 USD ($)
Gas and Power Supply Services Agreement [Member] | Shared Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 125,000
Operation and Maintenance Agreement [Member] | O&M Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	125,000
Management Services Agreement [Member] | Shared Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 375,000
Monthly fee as a percentage of capital expenditures incurred in the previous month	3.00%

XML

Supplemental Guarantor Information - Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues
Revenues	$ 612,457	$ 386,559	$ 300,073	$ 106,081	$ 0	$ 0	$ 0	$ 0	$ 1,405,170	$ 0	$ 0
Revenues from contracts with customers									1,404,943	0	0
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)									691,301	172	91
Cost of sales—affiliate									3,015	0	0
Cost of sales—related party									85,429	0	0
Operating and maintenance expense (recovery)									242,027	(96)	3,024
Operating and maintenance expense—affiliate									59,319	4,283	2,401
Development expense									596	177	516
Development expense—affiliate									61	0	8
General and administrative expense									6,106	5,263	5,551
General and administrative expense—affiliate									11,352	2,201	1,173
Depreciation and amortization expense									230,780	9,859	892
Impairment expense and loss on disposal of assets									364	20	5,505
Total operating costs and expenses									1,330,350	21,879	19,161
Income (loss) from operations	234,561	(90,951)	(43,388)	(25,402)	(15,193)	2,345	(5,941)	(3,090)	74,820	(21,879)	(19,161)
Other income (expense)
Interest expense, net of capitalized interest									(278,035)	0	0
Loss on modification or extinguishment of debt									(41,296)	(15,332)	(32,480)
Derivative gain (loss), net									(133,427)	43,105	3,249
Other income (expense)									3,642	392	(260)
Total other income (expense)									(449,116)	28,165	(29,491)
Net income (loss)	$ 158,298	$ (272,410)	$ (188,907)	$ (71,277)	$ (91,113)	$ 24,388	$ 7,319	$ 65,692	(374,296)	6,286	(48,652)
LNG [Member]
Revenues
Revenues									679,070	0	0
Revenues from contracts with customers									678,843	0	0
LNG—affiliate [Member]
Revenues
Revenues from contracts with customers									726,100	0	0
Parent Issuer [Member]
Revenues
Revenues									0
Revenues from contracts with customers										0	0
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)									0	0	0
Cost of sales—affiliate									0
Cost of sales—related party									0
Operating and maintenance expense (recovery)									0	0	0
Operating and maintenance expense—affiliate									0	0	0
Development expense									0	0	0
Development expense—affiliate									0		0
General and administrative expense									2,082	1,513	1,360
General and administrative expense—affiliate									0	0	0
Depreciation and amortization expense									24,297	239	13
Impairment expense and loss on disposal of assets									0	0	0
Total operating costs and expenses									26,379	1,752	1,373
Income (loss) from operations									(26,379)	(1,752)	(1,373)
Other income (expense)
Interest expense, net of capitalized interest									(278,035)
Loss on modification or extinguishment of debt									(41,296)	(15,332)	(32,480)
Derivative gain (loss), net									(133,427)	43,105	3,249
Other income (expense)									3,387	352	(265)
Total other income (expense)									(449,371)	28,125	(29,496)
Net income (loss)									(475,750)	26,373	(30,869)
Parent Issuer [Member] | LNG [Member]
Revenues
Revenues									0
Parent Issuer [Member] | LNG—affiliate [Member]
Revenues
Revenues from contracts with customers									0
Guarantors [Member]
Revenues
Revenues									1,405,170
Revenues from contracts with customers										0	0
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)									691,301	172	91
Cost of sales—affiliate									3,015
Cost of sales—related party									85,429
Operating and maintenance expense (recovery)									242,027	(96)	3,024
Operating and maintenance expense—affiliate									59,319	4,283	2,401
Development expense									596	177	516
Development expense—affiliate									61		8
General and administrative expense									4,024	3,750	4,191
General and administrative expense—affiliate									11,352	2,201	1,173
Depreciation and amortization expense									206,483	9,620	879
Impairment expense and loss on disposal of assets									364	20	5,505
Total operating costs and expenses									1,303,971	20,127	17,788
Income (loss) from operations									101,199	(20,127)	(17,788)
Other income (expense)
Interest expense, net of capitalized interest									0
Loss on modification or extinguishment of debt									0	0	0
Derivative gain (loss), net									0	0	0
Other income (expense)									528	7,952	15,580
Total other income (expense)									528	7,952	15,580
Net income (loss)									101,727	(12,175)	(2,208)
Guarantors [Member] | LNG [Member]
Revenues
Revenues									679,070
Guarantors [Member] | LNG—affiliate [Member]
Revenues
Revenues from contracts with customers									726,100
Eliminations [Member]
Revenues
Revenues									0
Revenues from contracts with customers										0	0
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)									0	0	0
Cost of sales—affiliate									0
Cost of sales—related party									0
Operating and maintenance expense (recovery)									0	0	0
Operating and maintenance expense—affiliate									0	0	0
Development expense									0	0	0
Development expense—affiliate									0		0
General and administrative expense									0	0	0
General and administrative expense—affiliate									0	0	0
Depreciation and amortization expense									0	0	0
Impairment expense and loss on disposal of assets									0	0	0
Total operating costs and expenses									0	0	0
Income (loss) from operations									0	0	0
Other income (expense)
Interest expense, net of capitalized interest									0
Loss on modification or extinguishment of debt									0	0	0
Derivative gain (loss), net									0	0	0
Other income (expense)									(273)	(7,912)	(15,575)
Total other income (expense)									(273)	(7,912)	(15,575)
Net income (loss)									(273)	$ (7,912)	$ (15,575)
Eliminations [Member] | LNG [Member]
Revenues
Revenues									0
Eliminations [Member] | LNG—affiliate [Member]
Revenues
Revenues from contracts with customers									$ 0

XML

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest, net of amounts capitalized	$ 258,491	$ 104,811	$ 0
Noncash capital contributions for conveyance of property, plant and equipment from affiliate	0	83,058	0
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 186,700	$ 178,300	$ 274,300

XML

Debt - CCH Credit Facility (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) Rate trains	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	May 31, 2018 USD ($)	May 01, 2018 USD ($)
Line of Credit Facility [Line Items]
Loss on modification or extinguishment of debt	$ 41,296	$ 15,332	$ 32,480
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 6,100,000	$ 4,600,000
Number of Liquefaction LNG Trains | trains	3
Maturity Date	Jun. 30, 2024
Line of Credit Facility, Date of First Quarterly Payment, Number of Months Following Project Completion	3 months
Line Of Credit Facility Amortization Period	19 years
Debt Instrument, Description of Variable Rate Basis	LIBOR or the base rate
Line Of Credit Facility, Unused Capacity, Commitment Fee Percentage Of Margin On Undrawn Commitment	40.00%
Debt Instrument, Balance Required in Reserve Account, Period of Debt Service	6 months
Loss on modification or extinguishment of debt	$ 2,600	15,300
Debt Issuance Costs, Required Fees to Agents and Lenders		$ 53,300
Line of Credit Facility, Decrease, Termination	6,687,020
CCH Credit Facility [Member] | Capital Allocation Framework [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Decrease, Termination	$ 152,800
CCH Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.75%
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.75%
CCH Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Fixed Charge, Coverage Ratio, Projected | Rate	1.50
Percentage of Debt Hedged by Interest Rate Derivatives	65.00%
Debt Instrument, Fixed Charge, Coverage Ratio | Rate	1.25

XML

Revenues from Contracts with Customers - Narrative (Details)	12 Months Ended
	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	44.00%
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	100.00%

XML

Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (80,645)	$ 18,069
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(80,645)	18,069
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Interest Rate Forward Start Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(7,582)	0
Interest Rate Forward Start Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Interest Rate Forward Start Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(7,582)	0
Interest Rate Forward Start Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	46,656	(68)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	2,383	1,299
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	9,198	2,990
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 35,075	$ (4,357)

XML

Consolidated Statements of Member's Equity - USD ($) $ in Thousands	Total	Cheniere CCH HoldCo I, LLC [Member]
Member's equity, beginning of period at Dec. 31, 2016	$ 1,313,809	$ 1,313,809
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	402,119	402,119
Net income (loss)	(48,652)	(48,652)
Member's equity, end of period at Dec. 31, 2017	1,667,276	1,667,276
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	407,575	407,575
Net income (loss)	6,286	6,286
Member's equity, end of period at Dec. 31, 2018	2,081,137	2,081,137
Increase (Decrease) in Partners' Capital [Roll Forward]
Capital contributions	710,737	710,737
Net income (loss)	(374,296)	(374,296)
Member's equity, end of period at Dec. 31, 2019	$ 2,417,578	$ 2,417,578

XML

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 230.0	$ 9.5	$ 0.8
Offsets to LNG terminal costs	$ 156.1	$ 48.7	$ 0.0

XML

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) unit customer	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jan. 01, 2019 USD ($)
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Right-of-use assets	$ 7,215,000	$ 0
Accounts Receivable, Allowance for Credit Loss, Current	0	0
Impairment expense related to property, plant and equipment	0	0	$ 5,500,000
Derivative instruments designated as cash flow hedges	0	0	0
Income Tax Expense (Benefit)	$ 0	$ 0	$ 0
Number of Reportable Segments | unit	1
Corpus Christi Pipeline [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Asset Retirement Obligation	$ 0
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Assets [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Right-of-use assets				$ 8,100,000
Accounting Standards Update 2016-02 [Member] | Other Current Liabilities [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Lease liabilities				500,000
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Liabilities [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Lease liabilities				5,200,000
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Liabilities—affiliate [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Lease liabilities				$ 1,200,000
Accounting Standards Update 2019-12 [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cumulative-effect on retained earnings	$ 2,100,000
CCL [Member] | Customer Concentration Risk [Member] | SPA Customers [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
SPA, Term of Agreement	20 years
Concentration Risk, Number of Significant Customers | customer	9

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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.

Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

Recent Accounting Standards

We adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), and subsequent amendments thereto on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. The adoption of the standard did not materially impact our Consolidated Financial Statements. Upon adoption of the standard, we recorded right-of-use assets of $8.1 million in other non-current assets, net, and lease liabilities of $0.5 million in other current liabilities—affiliate, $5.2 million other non-current liabilities and $1.2 million in other non-current liabilities—affiliate.

In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The new guidance retrospectively eliminates the requirement to allocate the consolidated amount of current and deferred tax expense to entities that are not subject to income tax. We early adopted this guidance effective December 31, 2019 and recorded a cumulative-effect adjustment to retained earnings of $2.1 million on our subsidiaries’ financial statements, that has been eliminated upon consolidated on our Consolidated Financial Statements. The provision for income taxes, taxes payable and deferred income tax balances have been retrospectively removed from our subsidiaries’ financial statements. The deferred tax assets were offset with a full valuation allowance and therefore no cumulative effect adjustment to retained earnings was required on our Consolidated Financial Statements.

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, revenue recognition, property, plant and equipment, derivative instruments 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, accounts receivables 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. Non-financial assets and liabilities initially measured at fair value include AROs.

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. Revenues from the sale of LNG are recognized as LNG revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.

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

Restricted cash 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.

Accounts Receivable

Accounts receivable is reported net of any allowances for doubtful accounts. We periodically review the collectability on our accounts receivable and recognize an allowance if there is probability of non-collection, based on historical write-off and customer-specific factors. We did not have an allowance on our accounts receivable as of December 31, 2019 and 2018.

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 and subsequently charged to expense when issued.

Accounting for LNG Activities

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. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.

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. 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. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses 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 is identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. During the year ended December 31, 2017, we recognized $5.5 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2019 and 2018.

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 reduce our asset balances to reflect a market basis less than cost and 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 the natural gas pipelines are placed in service.

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. When we have the contractual right and intend 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, 2019, 2018 and 2017. 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 restricted cash, derivative instruments and accounts receivable. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these 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 nine 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.

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, they are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in gain (loss) on modification or extinguishment of debt on our Consolidated Statements of Operations.

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.

XML

Customer Concentration

12 Months Ended

Dec. 31, 2019

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

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

	Percentage of Total Revenues from External Customers			Percentage of Accounts Receivable from External Customers
	Year Ended December 31,			December 31,
	2019	2018	2017	2019	2018
Customer A	57%	—%	—%	38%	—%
Customer B	23%	—%	—%	39%	—%

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in thousands). 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,
	2019		2018		2017
Spain	$	451,199	$	—	$	—
Indonesia	154,584		—		—
United States	73,287		—		—
Total	$	679,070	$	—	$	—

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Basis of Presentation, Policy

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.

Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

Recent Accounting Standards

Recent Accounting Standards

We adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), and subsequent amendments thereto on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. The adoption of the standard did not materially impact our Consolidated Financial Statements. Upon adoption of the standard, we recorded right-of-use assets of $8.1 million in other non-current assets, net, and lease liabilities of $0.5 million in other current liabilities—affiliate, $5.2 million other non-current liabilities and $1.2 million in other non-current liabilities—affiliate.

In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The new guidance retrospectively eliminates the requirement to allocate the consolidated amount of current and deferred tax expense to entities that are not subject to income tax. We early adopted this guidance effective December 31, 2019 and recorded a cumulative-effect adjustment to retained earnings of $2.1 million on our subsidiaries’ financial statements, that has been eliminated upon consolidated on our Consolidated Financial Statements. The provision for income taxes, taxes payable and deferred income tax balances have been retrospectively removed from our subsidiaries’ financial statements. The deferred tax assets were offset with a full valuation allowance and therefore no cumulative effect adjustment to retained earnings was required on our Consolidated Financial Statements.

Use of Estimates, Policy

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, revenue recognition, property, plant and equipment, derivative instruments 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, Policy

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, accounts receivables 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. Non-financial assets and liabilities initially measured at fair value include AROs.

Revenue Recognition

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. Revenues from the sale of LNG are recognized as LNG revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents, Policy

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, Policy

Restricted Cash

Restricted cash 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.

Receivables, Policy

Accounts Receivable

Accounts receivable is reported net of any allowances for doubtful accounts. We periodically review the collectability on our accounts receivable and recognize an allowance if there is probability of non-collection, based on historical write-off and customer-specific factors. We did not have an allowance on our accounts receivable as of December 31, 2019 and 2018.

Inventory, Policy

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 and subsequently charged to expense when issued.

Accounting For LNG Activities, Policy

Accounting for LNG Activities

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. The costs of lease options are amortized over the life of the lease once obtained. If no land or lease is obtained, the costs are expensed.

Property, Plant and Equipment, Policy

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. 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. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses 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 is identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. During the year ended December 31, 2017, we recognized $5.5 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey. We did not record any impairments related to property, plant and equipment during the years ended December 31, 2019 and 2018.

Interest Capitalization, Policy

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, Policy

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 reduce our asset balances to reflect a market basis less than cost and 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 the natural gas pipelines are placed in service.

Derivative Instruments, Policy

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. When we have the contractual right and intend 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, 2019, 2018 and 2017. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk, Policy

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of restricted cash, derivative instruments and accounts receivable. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these 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 nine 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.

Debt, Policy

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, they are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in gain (loss) on modification or extinguishment of debt on our Consolidated Statements of Operations.

Asset Retirement Obligations, Policy

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, Policy

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, Policy

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.

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

As of December 31, 2019 and 2018, property, plant and equipment, net consisted of the following (in thousands):

	December 31,
	2019			2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	10,027,111		$	618,547
LNG site and related costs	275,959			44,725
LNG terminal construction-in-process	2,425,226			10,470,577
Accumulated depreciation	(232,451		)	(7,416		)
Total LNG terminal costs, net	12,495,845			11,126,433
Fixed assets
Fixed assets	19,083			15,534
Accumulated depreciation	(7,509		)	(3,142		)
Total fixed assets, net	11,574			12,392
Property, plant and equipment, net	$	12,507,419		$	11,138,825

Property Plant and Equipment Estimated Useful Lives Table [Table Text Block]

The identifiable components of the Liquefaction Project have depreciable lives between 10 and 50 years, as follows:

Components	Useful life (yrs)
Water pipelines	30
Natural gas pipeline facilities	40
Liquefaction processing equipment	10-50
Other	15-30

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Summarized Quarterly Financial Data (unaudited) (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Summarized Quarterly Financial Data—(in thousands)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2019:
Revenues	$	106,081		$	300,073		$	386,559		$	612,457
Income (loss) from operations	(25,402		)	(43,388		)	(90,951		)	234,561
Net income (loss)	(71,277		)	(188,907		)	(272,410		)	158,298
Year ended December 31, 2018:
Revenues	$	—		$	—		$	—		$	—
Income (loss) from operations	(3,090		)	(5,941		)	2,345			(15,193		)
Net income (loss)	65,692			7,319			24,388			(91,113		)

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Long-term Purchase Commitment [Line Items]

Contractual Obligation, Fiscal Year Maturity Schedule

As of December 31, 2019, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in thousands): 

Years Ending December 31,	Payments Due (1)
2020	$	1,255,512
2021	1,047,335
2022	711,428
2023	591,844
2024	483,856
Thereafter	2,072,188
Total	$	6,162,163

(1)

Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2019. 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.

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Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2019

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

As of December 31, 2019 and 2018, accrued liabilities consisted of the following (in thousands): 

	December 31,
	2019		2018
Interest costs and related debt fees	$	7,950	$	994
Accrued natural gas purchases	132,148		91,910
Liquefaction Project costs	192,215		46,964
Other	37,667		22,337
Total accrued liabilities	$	369,980	$	162,205

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

As of December 31, 2019 and 2018, property, plant and equipment, net consisted of the following (in thousands):

	December 31,
	2019			2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	10,027,111		$	618,547
LNG site and related costs	275,959			44,725
LNG terminal construction-in-process	2,425,226			10,470,577
Accumulated depreciation	(232,451		)	(7,416		)
Total LNG terminal costs, net	12,495,845			11,126,433
Fixed assets
Fixed assets	19,083			15,534
Accumulated depreciation	(7,509		)	(3,142		)
Total fixed assets, net	11,574			12,392
Property, plant and equipment, net	$	12,507,419		$	11,138,825

 

Depreciation expense was $230.0 million, $9.5 million and $0.8 million during the years ended December 31, 2019, 2018 and 2017, respectively.

We realized offsets to LNG terminal costs of $156.1 million and $48.7 million during the years ended December 31, 2019 and 2018, respectively, that were 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. We did not realize any offsets to LNG terminal costs during the year ended December 31, 2017.

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 10 and 50 years, as follows:

Components	Useful life (yrs)
Water pipelines	30
Natural gas pipeline facilities	40
Liquefaction processing equipment	10-50
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.

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Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Debt

DEBT

As of December 31, 2019 and 2018, our debt consisted of the following (in thousands): 

	December 31,
	2019			2018
Long-term debt
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	$	1,250,000		$	1,250,000
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500,000			1,500,000
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500,000			1,500,000
4.80% Senior Secured Notes due 2039 (“4.80% CCH Senior Notes”)	727,000			—
3.925% Senior Secured Notes due 2039 (“3.925% CCH Senior Notes”)	475,000			—
3.700% Senior Secured Notes due 2029 (“2029 CCH Senior Notes”)	1,500,000			—
CCH Credit Facility	3,282,655			5,155,737
Unamortized debt issuance costs	(141,175		)	(160,185		)
Total long-term debt, net	10,093,480			9,245,552
Current debt
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”)	—			168,000
Total debt, net	$	10,093,480		$	9,413,552

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, 2019 (in thousands): 

Years Ending December 31,	Principal Payments
2020	$	—
2021	134,973
2022	118,507
2023	132,859
2024	4,146,316
Thereafter	5,702,000
Total	$	10,234,655

Senior Notes

CCH Senior Notes

In September 2019, we issued an aggregate principal amount of $727 million of the 4.80% CCH Senior Notes in a private placement conducted pursuant to Section 4(a)(2) of the Securities Act. The 4.80% CCH Senior Notes were issued under an indenture dated as of September 27, 2019 pursuant to a note purchase agreement with the purchasers party thereto and Allianz Global Investors GmbH, as noteholder consultant, originally entered into in June 2019. In October 2019, we issued an aggregate principal amount of $475 million of the 3.925% CCH Senior Notes in a private placement conducted pursuant to Section 4(a)(2) of the Securities Act. The 3.925% CCH Senior Notes were issued under an indenture dated October 17, 2019 pursuant to a note purchase agreement with the purchasers party thereto and certain accounts managed by BlackRock Real Assets and certain accounts managed by MetLife Investment Management. The 4.80% CCH Senior Notes and the 3.925% CCH Senior Notes accrue interest at a fixed rate of 4.80% and 3.925% per annum, respectively, and are fully amortizing according to a fixed sculpted amortization schedule with semi-annual payments of interest starting December 2019 and semi-annual payments of principal starting June 2027. The 4.80% CCH Senior Notes and the 3.925% CCH Senior Notes have a weighted average life of 15 years.

In November 2019, we issued an aggregate principal amount of $1.5 billion of the 2029 CCH Senior Notes. The 2029 CCH Senior Notes were issued pursuant to the same indenture governing the 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes (together with the 2029 CCH Senior Notes, the "144A CCH Senior Notes"). Borrowings under the 2029 CCH Senior Notes accrue interest at a fixed rate of 3.700% per annum.

The proceeds of the 4.80% CCH Senior Notes, 3.925% CCH Senior Notes and 2029 CCH Senior Notes were used to prepay a portion of the balance outstanding under the CCH Credit Facility, resulting in the recognition of debt modification and

extinguishment costs of $38.7 million for the year ended December 31, 2019 relating to the write off of unamortized debt discounts and issuance costs.

The 144A CCH Senior Notes, 4.80% CCH Senior Notes and 3.925% CCH Senior Notes (collectively, the “CCH Senior Notes”) are jointly and severally guaranteed by our subsidiaries, CCL, CCP and CCP GP (the “Guarantors”). The indentures governing each of the CCH Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to us or any of our restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of us and our restricted subsidiaries taken as a whole; or permit any Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. Interest on the CCH Senior Notes is payable semi-annually in arrears.

At any time prior to six months before the respective dates of maturity for each of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the appropriate indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time within six months of the respective dates of maturity for each of the CCH Senior Notes, we may redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2019 (in thousands):

	CCH Credit Facility		CCH Working Capital Facility
Original facility size	$	8,403,714	$	350,000
Incremental commitments	1,565,961		850,000
Less:
Outstanding balance	3,282,655		—
Commitments terminated	6,687,020		—
Letters of credit issued	—		470,784
Available commitment	$	—	$	729,216
Interest rate on available balance	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75%
Weighted average interest rate of outstanding balance	3.55%		n/a
Maturity date	June 30, 2024		June 29, 2023

CCH Credit Facility

In May 2018, we amended and restated the CCH Credit Facility to increase total commitments under the CCH Credit Facility from $4.6 billion to $6.1 billion. Borrowings are used to fund a portion of the costs of developing, constructing and placing into service the three Trains and the related facilities of the Liquefaction Project and for related business purposes.

The CCH Credit Facility matures on June 30, 2024, with principal payments due quarterly commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following the completion of the Liquefaction Project as defined in the common terms agreement and (2) a set date determined by reference to the date under which a certain LNG buyer linked to the last Train of the Liquefaction Project to become operational is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the completion of Trains 1 through 3 and designed to achieve a minimum projected fixed debt service coverage ratio of 1.50:1.

Loans under the CCH Credit Facility accrue interest at a variable rate per annum equal to, at our election, LIBOR or the base rate (determined by reference to the applicable agent’s prime rate), plus the applicable margin. The applicable margin for LIBOR loans is 1.75% and for base rate loans is 0.75%. Interest on LIBOR loans is due and payable at the end of each applicable

interest period and interest on base rate loans is due and payable at the end of each quarter. The CCH Credit Facility also requires us to pay a commitment fee at a rate per annum equal to 40% of the margin for LIBOR loans, multiplied by the outstanding undrawn debt commitments.

Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in us, on a pari passu basis with the CCH Senior Notes and the CCH Working Capital Facility.

Under the CCH Credit Facility, we are required to hedge not less than 65% of the variable interest rate exposure of our senior secured debt. We are restricted from making certain distributions under agreements governing our indebtedness generally until, among other requirements, the completion of the construction of Trains 1 through 3 of the Liquefaction Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.

The amendment and restatement of the CCH Credit Facility resulted in the recognition of $15.3 million of debt modification and extinguishment costs during the year ended December 31, 2018 relating to the incurrence of third party fees and write off of unamortized debt issuance costs. We were required to pay certain upfront fees to the agents and lenders under the CCH Credit Facility together with additional transaction fees and expenses in the aggregate amount of $53.3 million during the year ended December 31, 2018.

As part of the capital allocation framework announced by Cheniere in June 2019, we prepaid $152.8 million of outstanding borrowings under the CCH Credit Facility during the year ended December 31, 2019. The prepayment resulted in the recognition of debt extinguishment costs of $2.6 million for the year ended December 31, 2019.

CCH Working Capital Facility

In June 2018, we amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility from $350 million to $1.2 billion. The CCH Working Capital Facility is intended to be used for loans (“CCH Working Capital Loans”) and the issuance of letters of credit for certain working capital requirements related to developing and operating the Liquefaction Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the Guarantors. We may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility.

Loans under the CCH Working Capital Facility, including CCH Working Capital Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans” and collectively, the “Revolving Loans”) accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of (1) the prime rate, (2) the federal funds rate plus 0.50% and (3) one month LIBOR plus 0.50%) plus the applicable margin. The applicable margin for LIBOR Revolving Loans ranges from 1.25% to 1.75% per annum, and the applicable margin for base rate Revolving Loans ranges from 0.25% to 0.75% per annum. Interest on Revolving Loans is due and payable on the date the loan becomes due. Interest on LIBOR Revolving Loans is due and payable at the end of each LIBOR period, and interest on base rate Revolving Loans is due and payable at the end of each quarter.

We pay (1) a commitment fee equal to an annual rate of 40% of the applicable margin for LIBOR Revolving Loans on the average daily amount of the excess of the total commitment amount over the principal amount outstanding, (2) a letter of credit fee equal to an annual rate equal to the applicable margin for LIBOR Revolving Loans on the undrawn portion of all letters of credit issued under the CCH Working Capital Facility and (3) a letter of credit fronting fee equal to an annual rate of 0.20% of the undrawn portion of all fronted letters of credit. Each of these fees is payable quarterly in arrears.

If draws are made upon a letter of credit issued under the CCH Working Capital Facility and we do not elect for such draw (a “CCH LC Draw”) to be deemed a CCH LC Loan, we are required to pay the full amount of the CCH LC Draw on or prior to the business day following the notice of the CCH LC Draw. A CCH LC Draw accrues interest at an annual rate of 2.00% plus the base rate.

We were required to pay certain upfront fees to the agents and lenders under the CCH Working Capital Facility together with additional transaction fees and expenses in the aggregate amount of $13.8 million during the year ended December 31, 2018.

The CCH Working Capital Facility matures on June 29, 2023 and we may prepay the Revolving Loans at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. We are required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the assets of the Guarantors as well as all of the membership interests in us and the membership interest in each of the Guarantors on a pari passu basis with the CCH Senior Notes and the CCH Credit Facility.

Restrictive Debt Covenants

As of December 31, 2019, we were in compliance with all covenants related to our debt agreements.

Interest Expense

Total interest expense consisted of the following (in thousands):

	Year Ended December 31,
	2019			2018			2017
Total interest cost	$	538,677		$	451,135		$	360,932
Capitalized interest, including amounts capitalized as an Allowance for Funds Used During Construction	(260,642		)	(451,135		)	(360,932		)
Total interest expense, net	$	278,035		$	—		$	—

Fair Value Disclosures

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

	December 31, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	5,750,000	$	6,329,200	$	4,250,000	$	4,228,750
4.80% CCH Senior Notes (2)	727,000		830,203		—		—
3.925% CCH Senior Notes (2)	475,000		495,291		—		—
Credit facilities (3)	3,282,655		3,282,655		5,323,737		5,323,737

(1) Includes 144A CCH Senior Notes. 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)

Includes CCH Credit Facility and CCH Working Capital Facility. 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.

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Customer Concentration - Schedule of Revenue and Accounts Receivable by Major Customers (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	57.00%	0.00%	0.00%
Customer A [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	38.00%	0.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	23.00%	0.00%	0.00%
Customer B [Member] | Accounts Receivable from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	39.00%	0.00%

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Related Party Transactions - Other Agreements (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) yd3 mi unit	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	May 31, 2018 USD ($)
Related Party Transaction [Line Items]
Due to affiliates	$ 26,900,000	$ 25,086,000
Revenue from Related Parties	726,100,000	0	$ 0
Cost of sales—related party	85,429,000	0	0
Midship Pipeline [Member] | CCL [Member] | Midship Pipeline Letter of Credit [Member]
Related Party Transaction [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 16,200,000
Letters of credit issued	0
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	7,031,000	$ 0	$ 0
Contracts for Sale and Purchase of Natural Gas And LNG [Member] | CCL [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	0
Contracts for Sale and Purchase of Natural Gas And LNG [Member] | Midship Pipeline [Member] | CCL [Member]
Related Party Transaction [Line Items]
Cost of sales—related party	$ 0
Natural Gas Transportation Agreement [Member] | Cheniere Corpus Christi Liquefaction Stage III, LLC [Member] | CCP [Member]
Related Party Transaction [Line Items]
Agreement Term	20 years
Related Party Agreement, Number Of Available Extensions | unit	2
Related Party Agreement, Term Of Available Extension	5 years
Natural Gas Transportation Agreement [Member] | Midship Pipeline [Member] | CCL [Member]
Related Party Transaction [Line Items]
Agreement Term	10 years
Length Of Natural Gas Pipeline | mi	200
Lease Agreements [Member] | Cheniere Land Holdings [Member] | CCL [Member]
Related Party Transaction [Line Items]
Annual lease payment	$ 600,000
Lease Agreements [Member] | Cheniere Land Holdings [Member] | CCL [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Lease Term	3 years
Lease Agreements [Member] | Cheniere Land Holdings [Member] | CCL [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Lease Term	5 years
Easement Agreements [Member] | Cheniere Land Holdings [Member] | CCL [Member]
Related Party Transaction [Line Items]
Annual lease payment	$ 100,000
Easement Agreements [Member] | Cheniere Land Holdings [Member] | CCL [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Agreement Term	3 years
Easement Agreements [Member] | Cheniere Land Holdings [Member] | CCL [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Agreement Term	5 years
Dredge Material Disposal Agreement [Member] | Cheniere Land Holdings [Member] | CCL [Member]
Related Party Transaction [Line Items]
Dredge Material Deposits, Price Per Cubic Yard Of Deposit	$ 0.50
Dredge Material Deposits, Deposit Threshold | yd3	5,000,000.0
Dredge Material Deposits, Price Per Cubic Yard Of Deposit After Exceeding Threshold	$ 4.62
Tax Sharing Agreement [Member] | Cheniere [Member] | CCL [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	0
Tax Sharing Agreement [Member] | Cheniere [Member] | CCP [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0

XML

Supplemental Guarantor Information - Condensed Consolidating Statements of Cash Flows - Balances per Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Balances per Condensed Consolidating Balance Sheet:
Cash and cash equivalents	$ 0	$ 0
Restricted cash	79,741	289,141
Total cash, cash equivalents and restricted cash	79,741	289,141	$ 226,559	$ 270,540
Parent Issuer [Member]
Balances per Condensed Consolidating Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	68,787	282,248
Total cash, cash equivalents and restricted cash	68,787	282,248	226,559	270,540
Guarantors [Member]
Balances per Condensed Consolidating Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	10,954	6,893
Total cash, cash equivalents and restricted cash	10,954	6,893	0	0
Eliminations [Member]
Balances per Condensed Consolidating Balance Sheet:
Cash and cash equivalents	0	0
Restricted cash	0	0
Total cash, cash equivalents and restricted cash	$ 0	$ 0	$ 0	$ 0

XML

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Liquefaction Supply Derivatives [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset	$ 46,656,000	$ (68,000)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Asset	35,075,000	$ (4,357,000)
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Market Approach [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread	$ (0.718)
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation Technique, Option Pricing Model [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	86.00%
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Market Approach [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread	$ 0.050
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation Technique, Option Pricing Model [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	191.00%

XML

Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest Rate Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ (100,508)	$ 43,105	$ 3,249
Interest Rate Forward Start Derivatives [Member] | Derivative gain (loss), net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		(32,919)	0	0
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	227	0	0
Liquefaction Supply Derivatives [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	45,148	23	(91)
Liquefaction Supply Derivatives [Member] | Cost of sales—related party [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ (957)	$ 0	$ 0

[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.

XML

Debt - Schedule of Debt Instruments (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Jun. 30, 2018	Jun. 01, 2018	May 31, 2018	May 01, 2018
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ (141,175,000)	$ (160,185,000)
Long-term Debt, Net	10,093,480,000	9,245,552,000
Current debt	0	168,000,000
Total Debt, Net	10,093,480,000	9,413,552,000
2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,250,000,000	1,250,000,000
Debt Instrument, Interest Rate, Stated Percentage	7.00%
2025 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.125%
4.8% CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 727,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	4.80%
3.925% CCH Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 475,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	3.925%
2029 Corpus Christi Holdings Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	3.70%
CCH Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 3,282,655,000	$ 5,155,737,000
Line of Credit Facility, Maximum Borrowing Capacity					$ 6,100,000,000	$ 4,600,000,000
CCH Working Capital Facility [Member]
Debt Instrument [Line Items]
Current debt	0
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,200,000,000.0		$ 1,200,000,000	$ 350,000,000

XML

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018			2017
LNG revenues—affiliate
Cheniere Marketing Agreements	$	719,069	$	—		$	—
Contracts for Sale and Purchase of Natural Gas and LNG	7,031		—			—
Total LNG revenues—affiliate	726,100		—			—
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	3,015		—			—
Cost of sales—related party
Natural Gas Supply Agreement	85,429		—			—
Operating and maintenance expense—affiliate
Services Agreements	58,576		3,412			2,075
Land Agreements	743		874			326
Other Agreements	—		(3		)	—
Total operating and maintenance expense—affiliate	59,319		4,283			2,401
Development expense—affiliate
Services Agreements	61		—			8
General and administrative expense—affiliate
Services Agreements	11,352		2,201			1,173

XML

Other Non-Current Assets (Tables)

12 Months Ended

Dec. 31, 2019

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

As of December 31, 2019 and 2018, other non-current assets, net consisted of the following (in thousands):

	December 31,
	2019		2018
Advances and other asset conveyances to third parties to support LNG terminal	$	18,703	$	18,209
Operating lease assets	7,215		—
Tax-related payments and receivables	3,200		3,783
Information technology service prepayments	3,010		2,435
Advances made under EPC and non-EPC contracts	14,067		—
Other	9,435		7,282
Total other non-current assets, net	$	55,630	$	31,709

XML

Supplemental Guarantor Information (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Balance Sheets

Condensed Consolidating Balance Sheet
December 31, 2019
(in thousands)
	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	68,787		10,954		—			79,741
Accounts and other receivables	—		57,712		—			57,712
Accounts receivable—affiliate	—		57,211		—			57,211
Advances to affiliate	—		115,476		—			115,476
Inventory	—		69,179		—			69,179
Derivative assets	—		73,809		—			73,809
Derivative assets—related party	—		2,623		—			2,623
Other current assets	249		14,603		—			14,852
Other current assets—affiliate	—		5		—			5
Total current assets	69,036		401,572		—			470,608
Property, plant and equipment, net	1,330,748		11,176,671		—			12,507,419
Debt issuance and deferred financing costs, net	14,705		—		—			14,705
Non-current derivative assets	—		61,217		—			61,217
Non-current derivative assets—related party	—		1,933		—			1,933
Investments in subsidiaries	11,224,400		—		(11,224,400		)	—
Other non-current assets, net	—		55,630		—			55,630
Total assets	$	12,638,889	$	11,697,023	$	(11,224,400	)	$	13,111,512
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	32	$	7,258	$	—		$	7,290
Accrued liabilities	9,488		360,492		—			369,980
Accrued liabilities—related party	—		2,531		—			2,531
Due to affiliates	337		26,563		—			26,900
Derivative liabilities	39,566		6,920		—			46,486
Other current liabilities	—		364		—			364
Other current liabilities—affiliate	—		519		—			519
Total current liabilities	49,423		404,647		—			454,070
Long-term debt, net	10,093,480		—		—			10,093,480
Non-current derivative liabilities	48,661		86,006		—			134,667
Other non-current liabilities	—		10,433		—			10,433
Other non-current liabilities—affiliate	—		1,284		—			1,284
Member’s equity	2,447,325		11,194,653		(11,224,400		)	2,417,578
Total liabilities and member’s equity	$	12,638,889	$	11,697,023	$	(11,224,400	)	$	13,111,512

Condensed Consolidating Balance Sheet
December 31, 2018
(in thousands)
	Parent Issuer		Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—		$	—
Restricted cash	282,248		6,893		—			289,141
Accounts and other receivables	—		24,989		—			24,989
Accounts receivable—affiliate	—		21,060		—			21,060
Advances to affiliate	—		94,397		—			94,397
Inventory	—		26,198		—			26,198
Derivative assets	10,556		5,071		—			15,627
Derivative assets—related party	—		2,132		—			2,132
Other current assets	178		15,039		—			15,217
Other current assets—affiliate	—		634		(1		)	633
Total current assets	292,982		196,413		(1		)	489,394
Property, plant and equipment, net	1,094,671		10,044,154		—			11,138,825
Debt issuance and deferred financing costs, net	38,012		—		—			38,012
Non-current derivative assets	7,917		11,115		—			19,032
Non-current derivative assets—related party	—		3,381		—			3,381
Investments in subsidiaries	10,194,296		—		(10,194,296		)	—
Other non-current assets, net	1		31,708		—			31,709
Total assets	$	11,627,879	$	10,286,771	$	(10,194,297	)	$	11,720,353
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	71	$	16,131	$	—		$	16,202
Accrued liabilities	1,242		160,963		—			162,205
Current debt	168,000		—		—			168,000
Due to affiliates	—		25,086		—			25,086
Derivative liabilities	6		13,570		—			13,576
Total current liabilities	169,319		215,750		—			385,069
Long-term debt, net	9,245,552		—		—			9,245,552
Non-current derivative liabilities	398		8,197		—			8,595
Member’s equity	2,212,610		10,062,824		(10,194,297		)	2,081,137
Total liabilities and member’s equity	$	11,627,879	$	10,286,771	$	(10,194,297	)	$	11,720,353

Condensed Consolidating Statements of Operations

Condensed Consolidating Statement of Operations
Year Ended December 31, 2019
(in thousands)
	Parent Issuer			Guarantors		Eliminations			Consolidated
Revenues
LNG revenues	$	—		$	679,070	$	—		$	679,070
LNG revenues—affiliate	—			726,100		—			726,100
Total revenues	—			1,405,170		—			1,405,170
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			691,301		—			691,301
Cost of sales—affiliate	—			3,015		—			3,015
Cost of sales—related party	—			85,429		—			85,429
Operating and maintenance expense	—			242,027		—			242,027
Operating and maintenance expense—affiliate	—			59,319		—			59,319
Development expense	—			596		—			596
Development expense—affiliate	—			61		—			61
General and administrative expense	2,082			4,024		—			6,106
General and administrative expense—affiliate	—			11,352		—			11,352
Depreciation and amortization expense	24,297			206,483		—			230,780
Impairment expense and loss on disposal of assets	—			364		—			364
Total operating costs and expenses	26,379			1,303,971		—			1,330,350
Income (loss) from operations	(26,379		)	101,199		—			74,820
Other income (expense)
Interest expense, net of capitalized interest	(278,035		)	—		—			(278,035		)
Loss on modification or extinguishment of debt	(41,296		)	—		—			(41,296		)
Derivative loss, net	(133,427		)	—		—			(133,427		)
Other income	3,387			528		(273		)	3,642
Total other income (expense)	(449,371		)	528		(273		)	(449,116		)
Net income (loss)	$	(475,750	)	$	101,727	$	(273	)	$	(374,296	)

Condensed Consolidating Statement of Operations
Year Ended December 31, 2018
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Revenues	$	—		$	—		$	—		$	—
Operating costs and expenses (recoveries)
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			172			—			172
Operating and maintenance recovery	—			(96		)	—			(96		)
Operating and maintenance expense—affiliate	—			4,283			—			4,283
Development expense	—			177			—			177
General and administrative expense	1,513			3,750			—			5,263
General and administrative expense—affiliate	—			2,201			—			2,201
Depreciation and amortization expense	239			9,620			—			9,859
Impairment expense and gain on disposal of assets	—			20			—			20
Total operating costs and expenses	1,752			20,127			—			21,879
Loss from operations	(1,752		)	(20,127		)	—			(21,879		)
Other income (expense)
Loss on modification or extinguishment of debt	(15,332		)	—			—			(15,332		)
Derivative gain, net	43,105			—			—			43,105
Other income	352			7,952			(7,912		)	392
Total other income	28,125			7,952			(7,912		)	28,165
Net income (loss)	$	26,373		$	(12,175	)	$	(7,912	)	$	6,286

Condensed Consolidating Statement of Operations
Year Ended December 31, 2017
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Revenues	$	—		$	—		$	—		$	—
Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			91			—			91
Operating and maintenance expense	—			3,024			—			3,024
Operating and maintenance expense—affiliate	—			2,401			—			2,401
Development expense	—			516			—			516
Development expense—affiliate	—			8			—			8
General and administrative expense	1,360			4,191			—			5,551
General and administrative expense—affiliate	—			1,173			—			1,173
Depreciation and amortization expense	13			879			—			892
Impairment expense and gain on disposal of assets	—			5,505			—			5,505
Total operating costs and expenses	1,373			17,788			—			19,161
Loss from operations	(1,373		)	(17,788		)	—			(19,161		)
Other income (expense)
Loss on modification or extinguishment of debt	(32,480		)	—			—			(32,480		)
Derivative gain, net	3,249			—			—			3,249
Other income (expense)	(265		)	15,580			(15,575		)	(260		)
Total other income (expense)	(29,496		)	15,580			(15,575		)	(29,491		)
Net loss	$	(30,869	)	$	(2,208	)	$	(15,575	)	$	(48,652	)

Condensed Consolidating Statements of Cash Flows

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2019
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(237,471	)	$	250,856		$	(46,758	)	$	(33,373	)
Cash flows from investing activities
Property, plant and equipment, net	(242,322		)	(1,274,840		)	—			(1,517,162		)
Investments in subsidiaries	(2,711,350		)	—			2,711,350			—
Distributions received from affiliates	1,634,489			—			(1,634,489		)	—
Other	—			(2,058		)	—			(2,058		)
Net cash used in investing activities	(1,319,183		)	(1,276,898		)	1,076,861			(1,519,220		)
Cash flows from financing activities
Proceeds from issuances of debt	4,203,550			—			—			4,203,550
Repayments of debt	(3,543,757		)	—			—			(3,543,757		)
Debt issuance and deferred financing costs	(16,210		)	—			—			(16,210		)
Debt extinguishment cost	(11,127		)	—			—			(11,127		)
Capital contributions	710,737			2,711,350			(2,711,350		)	710,737
Distributions	—			(1,681,247		)	1,681,247			—
Net cash provided by financing activities	1,343,193			1,030,103			(1,030,103		)	1,343,193
Net increase (decrease) in cash, cash equivalents and restricted cash	(213,461		)	4,061			—			(209,400		)
Cash, cash equivalents and restricted cash—beginning of period	282,248			6,893			—			289,141
Cash, cash equivalents and restricted cash—end of period	$	68,787		$	10,954		$	—		$	79,741

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2019
	Parent Issuer		Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—
Restricted cash	68,787		10,954		—		79,741
Total cash, cash equivalents and restricted cash	$	68,787	$	10,954	$	—	$	79,741

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2018
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows used in operating activities	$	(6,854	)	$	(51,913	)	$	(1,395	)	$	(60,162	)
Cash flows from investing activities
Property, plant and equipment, net	(555,946		)	(2,406,990		)	—			(2,962,936		)
Investments in subsidiaries	(2,532,266		)	—			2,532,266			—
Distributions received from affiliates	67,744			—			(67,744		)	—
Other	—			2,669			—			2,669
Net cash used in investing activities	(3,020,468		)	(2,404,321		)	2,464,522			(2,960,267		)
Cash flows from financing activities
Proceeds from issuances of debt	3,114,800			—			—			3,114,800
Repayments of debt	(301,455		)	—			—			(301,455		)
Debt issuance and deferred financing costs	(45,743		)	—			—			(45,743		)
Debt extinguishment cost	(9,108		)	—			—			(9,108		)
Capital contributions	324,517			2,532,266			(2,532,266		)	324,517
Distributions	—			(69,139		)	69,139			—
Net cash provided by financing activities	3,083,011			2,463,127			(2,463,127		)	3,083,011
Net increase in cash, cash equivalents and restricted cash	55,689			6,893			—			62,582
Cash, cash equivalents and restricted cash—beginning of period	226,559			—			—			226,559
Cash, cash equivalents and restricted cash—end of period	$	282,248		$	6,893		$	—		$	289,141

Balances per Condensed Consolidating Balance Sheet:

	December 31, 2018
	Parent Issuer		Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	—	$	—	$	—	$	—
Restricted cash	282,248		6,893		—		289,141
Total cash, cash equivalents and restricted cash	$	282,248	$	6,893	$	—	$	289,141

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
(in thousands)
	Parent Issuer			Guarantors			Eliminations			Consolidated
Cash flows used in operating activities	$	(52,633	)	$	(11,683	)	$	—		$	(64,316	)
Cash flows from investing activities
Property, plant and equipment, net	(253,612		)	(1,733,642		)	—			(1,987,254		)
Investments in subsidiaries	(1,720,280		)	—			1,720,280			—
Other	—			25,045			—			25,045
Net cash used in investing activities	(1,973,892		)	(1,708,597		)	1,720,280			(1,962,209		)
Cash flows from financing activities
Proceeds from issuances of debt	3,040,000			—			—			3,040,000
Repayments of debt	(1,436,050		)	—			—			(1,436,050		)
Debt issuance and deferred financing costs	(23,496		)	—			—			(23,496		)
Debt extinguishment cost	(29		)	—			—			(29		)
Capital contributions	402,119			1,720,437			(1,720,437		)	402,119
Distributions	—			(157		)	157			—
Net cash provided by financing activities	1,982,544			1,720,280			(1,720,280		)	1,982,544
Net decrease in cash, cash equivalents and restricted cash	(43,981		)	—			—			(43,981		)
Cash, cash equivalents and restricted cash—beginning of period	270,540			—			—			270,540
Cash, cash equivalents and restricted cash—end of period	$	226,559		$	—		$	—		$	226,559

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Derivative Instruments

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

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

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

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, 2019 and 2018, which are classified as derivative assets, derivative assets—related party, non-current derivative assets, non-current derivative assets—related party, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in thousands):

	Fair Value Measurements as of
	December 31, 2019										December 31, 2018
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total
Interest Rate Derivatives asset (liability)	$	—	$	(80,645	)	$	—	$	(80,645	)	$	—	$	18,069	$	—		$	18,069
Interest Rate Forward Start Derivatives liability	—		(7,582		)	—		(7,582		)	—		—		—			—
Liquefaction Supply Derivatives asset (liability)	2,383		9,198			35,075		46,656			1,299		2,990		(4,357		)	(68		)

We value our CCH 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 conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of December 31, 2019 and 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

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 prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2019:

	Net Fair Value Asset (in thousands)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$35,075	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.718) - $0.050
		Option pricing model	International LNG pricing spread, relative to Henry Hub (1)	86% - 191%

(1)    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.

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, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018			2017
Balance, beginning of period	$	(4,357	)	$	(91	)	$	—
Realized and mark-to-market gains (losses):
Included in cost of sales	(82,645		)	(9,944		)	—
Purchases and settlements:
Purchases	120,755			5,678			(91		)
Settlements	1,432			—			—
Transfers out of Level 3 (1)	(110		)	—			—
Balance, end of period	$	35,075		$	(4,357	)	$	(91	)
Change in unrealized losses relating to instruments still held at end of period	$	(82,645	)	$	(9,944	)	$	—

(1) Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. 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.

CCH Interest Rate Derivatives

CCH has 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.

In June and July of 2019, we entered into the Interest Rate Forward Start Derivatives to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH, which is anticipated by the end of 2020. In November 2019, we settled a portion of the Interest Rate Forward Start Derivatives in conjunction with the prepayment of $1.5 billion of commitments under the CCH Credit Facility. In June 2018, we settled a portion of the Interest Rate Derivatives in conjunction with the amendment of the CCH Credit Facility.

As of December 31, 2019, we had the following CCH Interest Rate Derivatives outstanding:

	Notional Amounts
	December 31, 2019	December 31, 2018	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives	$4.5 billion	$4.0 billion	May 20, 2015	May 31, 2022	2.30%	One-month LIBOR
Interest Rate Forward Start Derivatives	$750 million	—	September 30, 2020	December 31, 2030	2.06%	Three-month LIBOR

The following table shows the fair value and location of our CCH Interest Rate Derivatives on our Consolidated Balance Sheets (in thousands):

	December 31, 2019									December 31, 2018
	Interest Rate Derivatives			Interest Rate Forward Start Derivatives			Total			Interest Rate Derivatives			Interest Rate Forward Start Derivatives		Total
Consolidated Balance Sheet Location
Derivative assets	$	—		$	—		$	—		$	10,556		$	—	$	10,556
Non-current derivative assets	—			—			—			7,918			—		7,918
Total derivative assets	—			—			—			18,474			—		18,474
Derivative liabilities	(31,984		)	(7,582		)	(39,566		)	(7		)	—		(7		)
Non-current derivative liabilities	(48,661		)	—			(48,661		)	(398		)	—		(398		)
Total derivative liabilities	(80,645		)	(7,582		)	(88,227		)	(405		)	—		(405		)
Derivative asset (liability), net	$	(80,645	)	$	(7,582	)	$	(88,227	)	$	18,069		$	—	$	18,069

The following table shows the changes in the fair value and settlements of our CCH Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018		2017
Interest Rate Derivatives gain (loss)	$	(100,508	)	$	43,105	$	3,249
Interest Rate Forward Start Derivatives loss	(32,919		)	—		—

Liquefaction Supply Derivatives

CCL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to eight years, some of which commence upon the satisfaction of certain conditions precedent.

The forward notional for our Liquefaction Supply Derivatives was approximately 3,153 TBtu and 2,854 TBtu as of December 31, 2019 and 2018, respectively, of which 120 TBtu and 55 TBtu, respectively, were for a natural gas supply contract CCL has with a related party.

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

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	December 31, 2019			December 31, 2018
Derivative assets	$	73,809		$	5,071
Derivative assets—related party	2,623			2,132
Non-current derivative assets	61,217			11,114
Non-current derivative assets—related party	1,933			3,381
Total derivative assets	139,582			21,698
Derivative liabilities	(6,920		)	(13,569		)
Non-current derivative liabilities	(86,006		)	(8,197		)
Total derivative liabilities	(92,926		)	(21,766		)
Derivative asset (liability), net	$	46,656		$	(68	)

(1) Does not include collateral posted with counterparties by us of $4.5 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of both December 31, 2019 and 2018.

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2019, 2018 and 2017 (in thousands):

		Year Ended December 31,
	Consolidated Statements of Operations Location (1)	2019			2018		2017
Liquefaction Supply Derivatives gain	LNG revenues	$	227		$	—	$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	45,148			23		(91		)
Liquefaction Supply Derivatives loss	Cost of sales—related party	(957		)	—		—

(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.

Consolidated Balance Sheet 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 thousands):

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of December 31, 2019
Interest Rate Derivatives	$	(80,645	)	$	—		$	(80,645	)
Interest Rate Forward Start Derivatives	(7,582		)	—			(7,582		)
Liquefaction Supply Derivatives	145,135			(5,553		)	139,582
Liquefaction Supply Derivatives	(98,625		)	5,699			(92,926		)
As of December 31, 2018
Interest Rate Derivatives	$	19,520		$	(1,046	)	$	18,474
Interest Rate Derivatives	(413		)	8			(405		)
Liquefaction Supply Derivatives	31,770			(10,072		)	21,698
Liquefaction Supply Derivatives	(29,996		)	8,230			(21,766		)

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Revenues from Contracts with Customers

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenues from Contracts with Customers

REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019		2018		2017
LNG revenues	$	678,843	$	—	$	—
LNG revenues—affiliate	726,100		—		—
Total revenues from customers	1,404,943		—		—
Net derivative gains (1)	227		—		—
Total revenues	$	1,405,170	$	—	$	—

(1)    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 equal to approximately 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.

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.

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, 2019 and 2018:

	December 31, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	33.6	11	$	33.9	12
LNG revenues—affiliate	1.0		13	1.0		14
Total revenues	$	34.6		$	34.9

(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 44% during the year ended December 31, 2019 of our LNG revenues were related to variable consideration received from customers. All of our LNG revenues—affiliate were related to variable consideration received from customers during the year ended December 31, 2019.

We have entered 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.

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Commitments and Contingencies - Purchase Obligation Table (Details) - CCL [Member] - Natural Gas Supply, Transportation And Storage Service Agreements [Member] $ in Thousands	Dec. 31, 2019 USD ($)	[1]
Long-term Purchase Commitment [Line Items]
2020	$ 1,255,512
2021	1,047,335
2022	711,428
2023	591,844
2024	483,856
Thereafter	2,072,188
Total	$ 6,162,163

[1] (1) Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on estimated forward prices and basis spreads as of December 31, 2019. 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.

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Related Party Transactions - Natural Gas Supply Agreement (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Cost of sales—related party	$ 85,429,000	$ 0	$ 0
Accrued liabilities—related party	2,531,000	0
Derivative assets—related party	2,623,000	2,132,000
Non-current derivative assets—related party	1,933,000	3,381,000
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—related party	85,429,000	0	$ 0
CCL [Member] | Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales—related party		0
Accrued liabilities—related party	2,500,000	0
Derivative assets—related party	2,600,000	2,100,000
Non-current derivative assets—related party	1,900,000	$ 3,400,000
CCL [Member] | Natural Gas Supply Agreement [Member] | Cost of sales—related party [Member]
Related Party Transaction [Line Items]
Cost of sales—related party	$ 85,400,000

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Supplemental Guarantor Information - Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	$ (33,373)	$ (60,162)	$ (64,316)
Cash flows from investing activities
Property, plant and equipment, net	(1,517,162)	(2,962,936)	(1,987,254)
Investments in subsidiaries	0	0	0
Distributions received from affiliates	0	0
Other	(2,058)	2,669	25,045
Net cash used in investing activities	(1,519,220)	(2,960,267)	(1,962,209)
Cash flows from financing activities
Proceeds from issuances of debt	4,203,550	3,114,800	3,040,000
Repayments of debt	(3,543,757)	(301,455)	(1,436,050)
Debt issuance and deferred financing costs	(16,210)	(45,743)	(23,496)
Debt extinguishment cost	(11,127)	(9,108)	(29)
Capital contributions	710,737	324,517	402,119
Distributions	0	0	0
Net cash provided by financing activities	1,343,193	3,083,011	1,982,544
Net increase (decrease) in cash, cash equivalents and restricted cash	(209,400)	62,582	(43,981)
Cash, cash equivalents and restricted cash—beginning of period	289,141	226,559	270,540
Cash, cash equivalents and restricted cash—end of period	79,741	289,141	226,559
Parent Issuer [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	(237,471)	(6,854)	(52,633)
Cash flows from investing activities
Property, plant and equipment, net	(242,322)	(555,946)	(253,612)
Investments in subsidiaries	(2,711,350)	(2,532,266)	(1,720,280)
Distributions received from affiliates	1,634,489	67,744
Other	0	0	0
Net cash used in investing activities	(1,319,183)	(3,020,468)	(1,973,892)
Cash flows from financing activities
Proceeds from issuances of debt	4,203,550	3,114,800	3,040,000
Repayments of debt	(3,543,757)	(301,455)	(1,436,050)
Debt issuance and deferred financing costs	(16,210)	(45,743)	(23,496)
Debt extinguishment cost	(11,127)	(9,108)	(29)
Capital contributions	710,737	324,517	402,119
Distributions	0	0	0
Net cash provided by financing activities	1,343,193	3,083,011	1,982,544
Net increase (decrease) in cash, cash equivalents and restricted cash	(213,461)	55,689	(43,981)
Cash, cash equivalents and restricted cash—beginning of period	282,248	226,559	270,540
Cash, cash equivalents and restricted cash—end of period	68,787	282,248	226,559
Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	250,856	(51,913)	(11,683)
Cash flows from investing activities
Property, plant and equipment, net	(1,274,840)	(2,406,990)	(1,733,642)
Investments in subsidiaries	0	0	0
Distributions received from affiliates	0	0
Other	(2,058)	2,669	25,045
Net cash used in investing activities	(1,276,898)	(2,404,321)	(1,708,597)
Cash flows from financing activities
Proceeds from issuances of debt	0	0	0
Repayments of debt	0	0	0
Debt issuance and deferred financing costs	0	0	0
Debt extinguishment cost	0	0	0
Capital contributions	2,711,350	2,532,266	1,720,437
Distributions	(1,681,247)	(69,139)	(157)
Net cash provided by financing activities	1,030,103	2,463,127	1,720,280
Net increase (decrease) in cash, cash equivalents and restricted cash	4,061	6,893	0
Cash, cash equivalents and restricted cash—beginning of period	6,893	0	0
Cash, cash equivalents and restricted cash—end of period	10,954	6,893	0
Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Cash flows provided by (used in) operating activities	(46,758)	(1,395)	0
Cash flows from investing activities
Property, plant and equipment, net	0	0	0
Investments in subsidiaries	2,711,350	2,532,266	1,720,280
Distributions received from affiliates	(1,634,489)	(67,744)
Other	0	0	0
Net cash used in investing activities	1,076,861	2,464,522	1,720,280
Cash flows from financing activities
Proceeds from issuances of debt	0	0	0
Repayments of debt	0	0	0
Debt issuance and deferred financing costs	0	0	0
Debt extinguishment cost	0	0	0
Capital contributions	(2,711,350)	(2,532,266)	(1,720,437)
Distributions	1,681,247	69,139	157
Net cash provided by financing activities	(1,030,103)	(2,463,127)	(1,720,280)
Net increase (decrease) in cash, cash equivalents and restricted cash	0	0	0
Cash, cash equivalents and restricted cash—beginning of period	0	0	0
Cash, cash equivalents and restricted cash—end of period	$ 0	$ 0	$ 0

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Debt - Schedule of Maturities (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2020	$ 0
2021	134,973
2022	118,507
2023	132,859
2024	4,146,316
Thereafter	5,702,000
Total	$ 10,234,655

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Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (4,357)	$ (91)	$ 0
Realized and mark-to-market gains (losses):
Included in cost of sales		(82,645)	(9,944)	0
Purchases and settlements:
Purchases		120,755	5,678	(91)
Settlements		1,432	0	0
Transfers out of Level 3	[1]	(110)	0	0
Balance, end of period		35,075	(4,357)	(91)
Change in unrealized losses relating to instruments still held at end of period		$ (82,645)	$ (9,944)	$ 0

[1] Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

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Derivative Instruments - Derivative Net Presentation on Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Interest Rate Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		$ 19,520
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(1,046)
Derivative Assets (Liabilities), at Fair Value, Net		18,474
Interest Rate Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	$ (80,645)	(413)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	0	8
Derivative Assets (Liabilities), at Fair Value, Net	(80,645)	(405)
Interest Rate Forward Start Derivatives [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(7,582)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	0
Derivative Assets (Liabilities), at Fair Value, Net	(7,582)	0
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	145,135	31,770
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets	(5,553)	(10,072)
Derivative Assets (Liabilities), at Fair Value, Net	139,582	21,698
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(98,625)	(29,996)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets	5,699	8,230
Derivative Assets (Liabilities), at Fair Value, Net	$ (92,926)	$ (21,766)

XML

Debt - CCH Working Capital Facility (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jun. 30, 2018	Jun. 01, 2018
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,200,000,000.0		$ 1,200,000,000	$ 350,000,000
Debt Instrument, Description of Variable Rate Basis	LIBOR or the base rate
Debt Issuance Costs, Required Fees to Agents and Lenders		$ 13,800,000
Maturity Date	Jun. 29, 2023
CCH Working Capital Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.25%
CCH Working Capital Facility [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.25%
CCH Working Capital Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
CCH Working Capital Facility [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%
Letter of Credit [Member] | Portion issued and not drawn [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.20%
CCH Revolving Loans [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR or the base rate
Line Of Credit Facility, Unused Capacity, Commitment Fee Percentage Of Margin On Undrawn Commitment	40.00%
Line of Credit Facility, Number of Business Days Notice Required for Repayment of Debt Without Penalty	3 days
CCH Revolving Loans [Member] | Base Rate Determination Federal Funds Rate [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
CCH Revolving Loans [Member] | Base Rate Determination LIBOR [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
CCH Revolving Loans [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.25%
CCH Revolving Loans [Member] | Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.25%
CCH Revolving Loans [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
CCH Revolving Loans [Member] | Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%
CCH LC Loan [Member] | Base Rate [Member] | Drawn Portion [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
CCH LC Loan [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Term	1 year
CCH Working Capital Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Annual Temporary Requirement, Balance, Outstanding Principal	$ 0
Line of Credit Facility, Annual Temporary Requirement, Period, Number of Consecutive Business Days	5 days

XML

Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers										$ 1,404,943	$ 0	$ 0
Net derivative gains	[1]									227	0	0
Revenues		$ 612,457	$ 386,559	$ 300,073	$ 106,081	$ 0	$ 0	$ 0	$ 0	1,405,170	0	0
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers										678,843	0	0
Revenues										679,070	0	0
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers										$ 726,100	$ 0	$ 0

[1] See Note 7—Derivative Instruments for additional information about our derivatives.

XML

Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Inventory [Line Items]
Inventory	$ 69,179	$ 26,198
Natural gas [Member]
Inventory [Line Items]
Inventory	6,870	1,326
LNG [Member]
Inventory [Line Items]
Inventory	6,103	0
Materials and other [Member]
Inventory [Line Items]
Inventory	$ 56,206	$ 24,872

XML

Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2019 unit mi item milliontonnes / yr trains
Corpus Christi Pipeline [Member]
Organization And Nature Of Operations [Line Items]
Length Of Natural Gas Pipeline | mi	23
Corpus Christi LNG Terminal [Member]
Organization And Nature Of Operations [Line Items]
Number of Liquefaction LNG Trains Operating	2
Number of Liquefaction LNG Trains Constructing	1
Total Production Capability | milliontonnes / yr	15
Number of LNG Storage Tanks | unit	3
Number of Marine Berths | item	2

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Restricted Cash

12 Months Ended

Dec. 31, 2019

Restricted Cash [Abstract]

Restricted Cash

RESTRICTED CASH

Restricted cash 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, 2019 and 2018, restricted cash consisted of the following (in thousands):

	December 31,
	2019		2018
Current restricted cash
Liquefaction Project	$	79,741	$	289,141

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.

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2019 USD ($) shares
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	333-215435
Entity Registrant Name	Cheniere Corpus Christi Holdings, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-1929160
Entity Address, Address Line One	700 Milam Street
Entity Address, Address Line Two	Suite 1900
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	375-5000
Title of 12(b) Security	None
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float | $	$ 0
Documents Incorporated by Reference	None
Entity Central Index Key	0001693317
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
No Trading Symbol Flag	true
Entity Common Stock, Shares Outstanding | shares	0

XML

Derivative Instruments - Narrative (Details) $ in Billions	1 Months Ended	12 Months Ended
	Nov. 30, 2019 USD ($)	Dec. 31, 2019 tbtu	Dec. 31, 2018 tbtu
CCH Credit Facility [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Line of Credit Facility, Increase (Decrease), Net | $	$ (1.5)
CCL [Member] | Natural Gas Supply Agreement [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount		120	55
CCL [Member] | Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract		8 years
CCL [Member] | Liquefaction Supply Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount		3,153	2,854

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities
Net income (loss)	$ (374,296)	$ 6,286	$ (48,652)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization expense	230,780	9,859	892
Amortization of discount and debt issuance costs	15,953	0	0
Loss on modification or extinguishment of debt	41,296	15,332	32,480
Total losses (gains) on derivatives, net	88,052	(43,128)	(3,158)
Total losses on derivatives, net—related party	957	0	0
Net cash used for settlement of derivative instruments	(29,437)	(7,222)	(50,981)
Impairment expense and loss on disposal of assets	364	20	5,505
Other	1,603	0	0
Changes in operating assets and liabilities:
Accounts receivable	(57,654)	0	0
Accounts receivable—affiliate	(57,203)	0	0
Advances to affiliate	(53,231)	(10,911)	0
Inventory	(36,885)	(24,852)	0
Accounts payable and accrued liabilities	174,471	10,354	152
Accrued liabilities—related party	2,531	0	0
Due to affiliates	15,368	530	1,567
Other, net	3,863	(16,313)	(1,454)
Other, net—affiliate	95	(117)	(667)
Net cash used in operating activities	(33,373)	(60,162)	(64,316)
Cash flows from investing activities
Property, plant and equipment, net	(1,517,162)	(2,962,936)	(1,987,254)
Other	(2,058)	2,669	25,045
Net cash used in investing activities	(1,519,220)	(2,960,267)	(1,962,209)
Cash flows from financing activities
Proceeds from issuances of debt	4,203,550	3,114,800	3,040,000
Repayments of debt	(3,543,757)	(301,455)	(1,436,050)
Debt issuance and deferred financing costs	(16,210)	(45,743)	(23,496)
Debt extinguishment cost	(11,127)	(9,108)	(29)
Capital contributions	710,737	324,517	402,119
Net cash provided by financing activities	1,343,193	3,083,011	1,982,544
Net increase (decrease) in cash, cash equivalents and restricted cash	(209,400)	62,582	(43,981)
Cash, cash equivalents and restricted cash—beginning of period	289,141	226,559	270,540
Cash, cash equivalents and restricted cash—end of period	$ 79,741	$ 289,141	$ 226,559

XML

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

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, 2019 and 2018, which are classified as derivative assets, derivative assets—related party, non-current derivative assets, non-current derivative assets—related party, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in thousands):

	Fair Value Measurements as of
	December 31, 2019										December 31, 2018
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total
Interest Rate Derivatives asset (liability)	$	—	$	(80,645	)	$	—	$	(80,645	)	$	—	$	18,069	$	—		$	18,069
Interest Rate Forward Start Derivatives liability	—		(7,582		)	—		(7,582		)	—		—		—			—
Liquefaction Supply Derivatives asset (liability)	2,383		9,198			35,075		46,656			1,299		2,990		(4,357		)	(68		)

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2019:

	Net Fair Value Asset (in thousands)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$35,075	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.718) - $0.050
		Option pricing model	International LNG pricing spread, relative to Henry Hub (1)	86% - 191%

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

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

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, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018			2017
Balance, beginning of period	$	(4,357	)	$	(91	)	$	—
Realized and mark-to-market gains (losses):
Included in cost of sales	(82,645		)	(9,944		)	—
Purchases and settlements:
Purchases	120,755			5,678			(91		)
Settlements	1,432			—			—
Transfers out of Level 3 (1)	(110		)	—			—
Balance, end of period	$	35,075		$	(4,357	)	$	(91	)
Change in unrealized losses relating to instruments still held at end of period	$	(82,645	)	$	(9,944	)	$	—

(1)

Transferred to Level 2 as a result of observable market for the underlying natural gas purchase agreements.

Derivative Net Presentation on Consolidated Balance Sheets

The following table shows the fair value of our derivatives outstanding on a gross and net basis (in thousands):

	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of December 31, 2019
Interest Rate Derivatives	$	(80,645	)	$	—		$	(80,645	)
Interest Rate Forward Start Derivatives	(7,582		)	—			(7,582		)
Liquefaction Supply Derivatives	145,135			(5,553		)	139,582
Liquefaction Supply Derivatives	(98,625		)	5,699			(92,926		)
As of December 31, 2018
Interest Rate Derivatives	$	19,520		$	(1,046	)	$	18,474
Interest Rate Derivatives	(413		)	8			(405		)
Liquefaction Supply Derivatives	31,770			(10,072		)	21,698
Liquefaction Supply Derivatives	(29,996		)	8,230			(21,766		)

Interest Rate Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of December 31, 2019, we had the following CCH Interest Rate Derivatives outstanding:

	Notional Amounts
	December 31, 2019	December 31, 2018	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives	$4.5 billion	$4.0 billion	May 20, 2015	May 31, 2022	2.30%	One-month LIBOR
Interest Rate Forward Start Derivatives	$750 million	—	September 30, 2020	December 31, 2030	2.06%	Three-month LIBOR

Fair Value of Derivative Instruments by Balance Sheet Location

The following table shows the fair value and location of our CCH Interest Rate Derivatives on our Consolidated Balance Sheets (in thousands):

	December 31, 2019									December 31, 2018
	Interest Rate Derivatives			Interest Rate Forward Start Derivatives			Total			Interest Rate Derivatives			Interest Rate Forward Start Derivatives		Total
Consolidated Balance Sheet Location
Derivative assets	$	—		$	—		$	—		$	10,556		$	—	$	10,556
Non-current derivative assets	—			—			—			7,918			—		7,918
Total derivative assets	—			—			—			18,474			—		18,474
Derivative liabilities	(31,984		)	(7,582		)	(39,566		)	(7		)	—		(7		)
Non-current derivative liabilities	(48,661		)	—			(48,661		)	(398		)	—		(398		)
Total derivative liabilities	(80,645		)	(7,582		)	(88,227		)	(405		)	—		(405		)
Derivative asset (liability), net	$	(80,645	)	$	(7,582	)	$	(88,227	)	$	18,069		$	—	$	18,069

Derivative Instruments, Gain (Loss)

The following table shows the changes in the fair value and settlements of our CCH Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2019, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2019			2018		2017
Interest Rate Derivatives gain (loss)	$	(100,508	)	$	43,105	$	3,249
Interest Rate Forward Start Derivatives loss	(32,919		)	—		—

Liquefaction Supply Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Instruments by Balance Sheet Location

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

	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	December 31, 2019			December 31, 2018
Derivative assets	$	73,809		$	5,071
Derivative assets—related party	2,623			2,132
Non-current derivative assets	61,217			11,114
Non-current derivative assets—related party	1,933			3,381
Total derivative assets	139,582			21,698
Derivative liabilities	(6,920		)	(13,569		)
Non-current derivative liabilities	(86,006		)	(8,197		)
Total derivative liabilities	(92,926		)	(21,766		)
Derivative asset (liability), net	$	46,656		$	(68	)

(1)

Does not include collateral posted with counterparties by us of $4.5 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of both December 31, 2019 and 2018.

Derivative Instruments, Gain (Loss)

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2019, 2018 and 2017 (in thousands):

		Year Ended December 31,
	Consolidated Statements of Operations Location (1)	2019			2018		2017
Liquefaction Supply Derivatives gain	LNG revenues	$	227		$	—	$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	45,148			23		(91		)
Liquefaction Supply Derivatives loss	Cost of sales—related party	(957		)	—		—

(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.

XML

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2019		2018		2017
Cash paid during the period for interest, net of amounts capitalized	$	258,491	$	104,811	$	—
Non-cash capital contribution for conveyance of property, plant and equipment from affiliate	—		83,058		—

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $186.7 million, $178.3 million and $274.3 million as of December 31, 2019, 2018 and 2017, respectively.

XML

Restricted Cash (Tables)

12 Months Ended

Dec. 31, 2019

Restricted Cash [Abstract]

Schedule of Restricted Cash

As of December 31, 2019 and 2018, restricted cash consisted of the following (in thousands):

	December 31,
	2019		2018
Current restricted cash
Liquefaction Project	$	79,741	$	289,141