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Corpus Christi Liquefaction

Filed: 24 Feb 20, 7:00pm
     
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)
Delaware47-1929160
(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 classTrading SymbolName of each exchange on which registered
NoneNoneNone
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





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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

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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:
image6a17.jpg
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.


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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;
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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% —% —%
 

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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.


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 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.

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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,

22


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 Project79,741
 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 flows1,343,193
 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 period289,141
 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—affiliate726,100
 
 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—affiliate3,015
 
 3,015
 
 
Cost of sales—related party85,429
 
 85,429
 
 
Operating and maintenance expense (recovery)242,027
 (96) 242,123
 3,024
 (3,120)
Operating and maintenance expense—affiliate59,319
 4,283
 55,036
 2,401
 1,882
Development expense596
 177
 419
 516
 (339)
Development expense—affiliate61
 
 61
 8
 (8)
General and administrative expense6,106
 5,263
 843
 5,551
 (288)
General and administrative expense—affiliate11,352
 2,201
 9,151
 1,173
 1,028
Depreciation and amortization expense230,780
 9,859
 220,921
 892
 8,967
Impairment expense and loss on disposal of assets364
 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 debt41,296
 15,332
 25,964
 32,480
 (17,148)
Derivative loss (gain), net133,427
 (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

35


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
 


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—affiliate726,100
 
 
Total revenues1,405,170
 
 
      
Operating costs and expenses (recoveries)     
Cost of sales (excluding depreciation and amortization expense shown separately below)691,301
 172
 91
Cost of sales—affiliate3,015
 
 
Cost of sales—related party85,429
 
 
Operating and maintenance expense (recovery)242,027
 (96) 3,024
Operating and maintenance expense—affiliate59,319
 4,283
 2,401
Development expense596
 177
 516
Development expense—affiliate61
 
 8
General and administrative expense6,106
 5,263
 5,551
General and administrative expense—affiliate11,352
 2,201
 1,173
Depreciation and amortization expense230,780
 9,859
 892
Impairment expense and loss on disposal of assets364
 20
 5,505
Total operating costs and expenses1,330,350
 21,879
 19,161
      
Income (loss) from operations74,820
 (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 Members
Equity
Balance at December 31, 2016$1,313,809
 $1,313,809
Capital contributions402,119
 402,119
Net loss(48,652) (48,652)
Balance at December 31, 20171,667,276
 1,667,276
Capital contributions407,575
 407,575
Net income6,286
 6,286
Balance at December 31, 20182,081,137
 2,081,137
Capital contributions710,737
 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 expense230,780
 9,859
 892
Amortization of discount and debt issuance costs15,953
 
 
Loss on modification or extinguishment of debt41,296
 15,332
 32,480
Total losses (gains) on derivatives, net88,052
 (43,128) (3,158)
Total losses on derivatives, net—related party957
 
 
Net cash used for settlement of derivative instruments(29,437) (7,222) (50,981)
Impairment expense and loss on disposal of assets364
 20
 5,505
Other1,603
 
 
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 liabilities174,471
 10,354
 152
Accrued liabilities—related party2,531
 
 
Due to affiliates15,368
 530
 1,567
Other, net3,863
 (16,313) (1,454)
Other, net—affiliate95
 (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 debt4,203,550
 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 contributions710,737
 324,517
 402,119
Net cash provided by financing activities1,343,193
 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 period289,141
 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 cash79,741
 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 2 Trains and are constructing 1 additional Train for a total production capacity of approximately 15 mtpa of LNG. The Liquefaction Project, once fully constructed, will contain 3 LNG storage tanks and 2 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 0t 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 0t 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 0t 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 9 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.
 

48


CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We have 0t 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, 0 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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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 0t 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives, including those with related parties, during the years ended December 31, 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:     
Purchases120,755
 5,678
 (91)
Settlements1,432
 
 
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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CHENIERE CORPUS CHRISTI HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 gainLNG revenues$227
 $
 $
Liquefaction Supply Derivatives gain (loss)Cost of sales45,148
 23
 (91)
Liquefaction Supply Derivatives lossCost 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 3 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 0 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 LNG7,031
 
 
Total LNG revenues—affiliate726,100
 
 
      
Cost of sales—affiliate     
Contracts for Sale and Purchase of Natural Gas and LNG3,015
 
 
      
Cost of sales—related party     
Natural Gas Supply Agreement85,429
 
 
      
Operating and maintenance expense—affiliate     
Services Agreements58,576
 3,412
 2,075
Land Agreements743
 874
 326
Other Agreements
 (3) 
Total operating and maintenance expense—affiliate59,319
 4,283
 2,401
      
Development expense—affiliate     
Services Agreements61
 
 8
      
General and administrative expense—affiliate     
Services Agreements11,352
 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 0 was included in accrued liabilities—related party as of December 31, 2019 and 2018, respectively. CCL did 0t 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 0t 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 2 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 0t 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 0 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 0 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 0 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
20211,047,335
2022711,428
2023591,844
2024483,856
Thereafter2,072,188
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 0 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
 $
 $
Indonesia154,584
 
 
United States73,287
 
 
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 cash68,787
 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 assets249
 14,603
 
 14,852
Other current assets—affiliate
 5
 
 5
Total current assets69,036
 401,572
 
 470,608
        
Property, plant and equipment, net1,330,748
 11,176,671
 
 12,507,419
Debt issuance and deferred financing costs, net14,705
 
 
 14,705
Non-current derivative assets
 61,217
 
 61,217
Non-current derivative assets—related party
 1,933
 
 1,933
Investments in subsidiaries11,224,400
 
 (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 liabilities9,488
 360,492
 
 369,980
Accrued liabilities—related party
 2,531
 
 2,531
Due to affiliates337
 26,563
 
 26,900
Derivative liabilities39,566
 6,920
 
 46,486
Other current liabilities
 364
 
 364
Other current liabilities—affiliate
 519
 
 519
Total current liabilities49,423
 404,647
 
 454,070
        
Long-term debt, net10,093,480
 
 
 10,093,480
Non-current derivative liabilities48,661
 86,006
 
 134,667
Other non-current liabilities
 10,433
 
 10,433
Other non-current liabilities—affiliate
 1,284
 
 1,284
        
Member’s equity2,447,325
 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


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Condensed Consolidating Balance Sheet
December 31, 2018
(in thousands)
        
 Parent Issuer Guarantors Eliminations Consolidated
ASSETS       
Current assets       
Cash and cash equivalents$
 $
 $
 $
Restricted cash282,248
 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 assets10,556
 5,071
 
 15,627
Derivative assets—related party
 2,132
 
 2,132
Other current assets178
 15,039
 
 15,217
Other current assets—affiliate
 634
 (1) 633
Total current assets292,982
 196,413
 (1) 489,394
        
Property, plant and equipment, net1,094,671
 10,044,154
 
 11,138,825
Debt issuance and deferred financing costs, net38,012
 
 
 38,012
Non-current derivative assets7,917
 11,115
 
 19,032
Non-current derivative assets—related party
 3,381
 
 3,381
Investments in subsidiaries10,194,296
 
 (10,194,296) 
Other non-current assets, net1
 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 liabilities1,242
 160,963
 
 162,205
Current debt168,000
 
 
 168,000
Due to affiliates
 25,086
 
 25,086
Derivative liabilities6
 13,570
 
 13,576
Total current liabilities169,319
 215,750
 
 385,069
        
Long-term debt, net9,245,552
 
 
 9,245,552
Non-current derivative liabilities398
 8,197
 
 8,595
        
Member’s equity2,212,610
 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 expense2,082
 4,024
 
 6,106
General and administrative expense—affiliate
 11,352
 
 11,352
Depreciation and amortization expense24,297
 206,483
 
 230,780
Impairment expense and loss on disposal of assets
 364
 
 364
Total operating costs and expenses26,379
 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 income3,387
 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 expense1,513
 3,750
 
 5,263
General and administrative expense—affiliate
 2,201
 
 2,201
Depreciation and amortization expense239
 9,620
 
 9,859
Impairment expense and gain on disposal of assets
 20
 
 20
Total operating costs and expenses1,752
 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, net43,105
 
 
 43,105
Other income352
 7,952
 (7,912) 392
Total other income28,125
 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 expense1,360
 4,191
 
 5,551
General and administrative expense—affiliate
 1,173
 
 1,173
Depreciation and amortization expense13
 879
 
 892
Impairment expense and gain on disposal of assets
 5,505
 
 5,505
Total operating costs and expenses1,373
 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, net3,249
 
 
 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 affiliates1,634,489
 
 (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 debt4,203,550
 
 
 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 contributions710,737
 2,711,350
 (2,711,350) 710,737
Distributions
 (1,681,247) 1,681,247
 
Net cash provided by financing activities1,343,193
 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 period282,248
 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 cash68,787
 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 affiliates67,744
 
 (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 debt3,114,800
 
 
 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 contributions324,517
 2,532,266
 (2,532,266) 324,517
Distributions
 (69,139) 69,139
 
Net cash provided by financing activities3,083,011
 2,463,127
 (2,463,127) 3,083,011
        
Net increase in cash, cash equivalents and restricted cash55,689
 6,893
 
 62,582
Cash, cash equivalents and restricted cash—beginning of period226,559
 
 
 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 cash282,248
 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 debt3,040,000
 
 
 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 contributions402,119
 1,720,437
 (1,720,437) 402,119
Distributions
 (157) 157
 
Net cash provided by financing activities1,982,544
 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 period270,540
 
 
 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: 

(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 EntityFormExhibitFiling Date
3.1  CCHS-43.11/5/2017
3.2  CCHS-43.21/5/2017
3.3  CCHS-43.31/5/2017
3.4  CCHS-43.41/5/2017
3.5  CCHS-43.51/5/2017
3.6  CCHS-43.61/5/2017
3.7  CCHS-43.71/5/2017

78


Exhibit No.   Incorporated by Reference (1)
 Description EntityFormExhibitFiling Date
3.8  CCHS-43.81/5/2017
3.9  CCHS-43.91/5/2017
3.10  CCHS-43.101/5/2017
3.11  CCHS-43.111/5/2017
4.1  Cheniere8-K4.15/18/2016
4.2  Cheniere8-K4.15/18/2016
4.3  Cheniere8-K4.112/9/2016
4.4  Cheniere8-K4.112/9/2016
4.5  CCH8-K4.15/19/2017
4.6  CCH8-K4.15/19/2017
4.7  CCH8-K4.19/12/2019
4.8  CCH8-K4.19/30/2019
4.9  CCH8-K4.110/18/2019
4.10  CCH8-K4.111/13/2019
10.1  CCH8-K10.15/24/2018
10.2  CCH8-K10.25/24/2018
10.3  CCH10-K10.32/26/2019
10.4  CCH10-Q10.211/1/2019

79


Exhibit No.   Incorporated by Reference (1)
 Description EntityFormExhibitFiling Date
10.5  CCH8-K10.35/24/2018
10.6  CCH10-K10.52/26/2019
10.7  CCH10-Q10.311/1/2019
10.8  CCH8-K10.45/24/2018
10.9  CCH8-K10.55/24/2018
10.10  CCH8-K10.17/2/2018
10.11  CCH8-K10.1011/13/2019
10.12  CCH10-K/A10.234/27/2018
10.13  CCH10-Q10.1011/8/2018

80


Exhibit No.   Incorporated by Reference (1)
 Description EntityFormExhibitFiling Date
10.14  CCH10-K10.282/26/2019
10.15  CCH10-Q10.205/9/2019
10.16  CCH10-Q10.208/8/2019
10.17  CCH10-Q10.5011/1/2019
10.18*      

81


Exhibit No.   Incorporated by Reference (1)
 Description EntityFormExhibitFiling Date
10.19  CCHS-410.141/5/2017
10.20  CCHS-410.151/5/2017
10.21  Cheniere8-K10.104/2/2014
10.22  Cheniere8-K10.104/8/2014
10.23  Cheniere10-Q10.305/1/2014
10.24  Cheniere10-Q10.9010/30/2015
10.25  Cheniere10-Q10.1010/30/2015
10.26  Cheniere10-Q10.504/30/2015
10.27  CCHS-410.221/5/2017
10.28  CCH10-Q10.1011/1/2019
10.29  Cheniere8-K10.106/2/2014
10.30  CCH10-Q10.505/4/2018
10.31  CCHS-410.321/5/2017
10.32  CCHS-410.331/5/2017
10.33  CCHS-410.341/5/2017
10.34*      
21.1*      
31.1*      
32.1**      
101.INS* XBRL Instance Document     
101.SCH* XBRL Taxonomy Extension Schema Document     

82


Exhibit No.   Incorporated by Reference (1)
 Description EntityFormExhibitFiling 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.
SignatureTitleDate
   
/s/ Michael J. WortleyManager, President and Chief Financial Officer
(Principal Executive and Financial Officer)
February 24, 2020
Michael J. Wortley
   
/s/ Aaron StephensonManagerFebruary 24, 2020
Aaron Stephenson
   
/s/ Leonard E. TravisChief 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





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:
image6a18.jpg

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 Members
Equity
Balance at December 31, 2016$5,687,512
 $5,687,512
Capital contributions1,516,772
 1,516,772
Net loss(17,325) (17,325)
Balance at December 31, 20177,186,959
 7,186,959
Capital contributions2,567,410
 2,567,410
Distributions(67,744) (67,744)
Net loss(12,147) (12,147)
Balance at December 31, 20189,674,478
 9,674,478
Capital contributions2,670,627
 2,670,627
Distributions(1,617,488) (1,617,488)
Net income77,686
 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.


S-9


CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED



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.

S-10


CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED



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.


S-11


CORPUS CHRISTI LIQUEFACTION, LLC
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

S-12


CORPUS CHRISTI LIQUEFACTION, LLC
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.


S-13


CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED



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:     
Purchases120,755
 5,678
 (91)
Settlements1,432
 
 
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.


S-14


CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED



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 gainLNG revenues$227
 $
 $
Liquefaction Supply Derivatives gain (loss)Cost of sales45,148
 23
 (91)
Liquefaction Supply Derivatives lossCost 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)


S-15


CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED



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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CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED



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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CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED



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 LNG7,031
 
 
Total LNG revenue—affiliate726,100
 
 
      
Cost of sales—affiliate     
Transportation Agreement5,868
 
 
Contracts for Sale and Purchase of Natural Gas and LNG8,758
 
 
Total cost of sales—affiliate14,626
 
 
      
Cost of sales—related party     
Natural Gas Supply Agreement85,429
 
 
      
Operating and maintenance expense—affiliate     
Services Agreements50,681
 298
 2,005
Land Agreements53,916
 880
 326
Total operating and maintenance expense—affiliate104,597
 1,178
 2,331
      
Development expense—affiliate     
Services Agreements61
 
 8
      
General and administrative expense—affiliate     
Services Agreements11,260
 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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CORPUS CHRISTI LIQUEFACTION, LLC
NOTES TO FINANCIAL STATEMENTS—CONTINUED



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.

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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
20211,047,335
2022711,428
2023591,844
2024483,856
Thereafter2,072,188
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
 $
 $
Indonesia154,584
 
 
United States73,287
 
 
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.


S-23
















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:
image6a17.jpg
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


S-26


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—affiliate4,241
 
 
Total revenues66,116
 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 expense1,028
 718
 234
General and administrative expense—affiliate92
 114
 46
Depreciation and amortization expense10,725
 6,160
 69
Other expense
 
 5
Total expenses32,351
 14,122
 452
      
Income (loss) from operations33,765
 (12,563) (452)

   
  
Other income     
Other income268
 7,912
 15,575
Other income—affiliate5
 5
 
Total other income273
 7,917
 15,575
      
Net income (loss)$34,038
 $(4,646) $15,123


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

S-28



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 expense10,726
 6,160
 69
Allowance for funds used during construction (268) (7,912) (15,575)
Other131
 
 5
Changes in operating assets and liabilities:     
Accounts receivable—affiliate(6,272) (1,100) 
Advances to affiliate6,769
 (10,911) 
Inventory(1,127) (1,105) 
Operational balancing assets5,916
 (6,106) 
Regulatory assets(635) (158) 
Accounts payable and accrued liabilities1,450
 2,862
 26
Due to affiliates629
 989
 6
Operational balancing assets and liabilities—affiliate(8,007) 6,189
 
Regulatory liabilities5,631
 
 
Other, net(296) (379) (157)
Other, net—affiliate(3) 
 
Net cash provided by (used in) operating activities48,682
 (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 contributions40,713
 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.

S-30



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.


S-31


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.


S-32


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—affiliate4,241
 
 
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—affiliate61,875
 1,559
 
       
Other revenues—affiliate      
Transportation Agreements4,241
 
 
       
Operating and maintenance expense (recovery)—affiliate     
Services Agreements7,189
 3,114
 70
Land Agreements12
 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 Agreements92
 114
 46
       
Other income—affiliate      
Land Agreements5
 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:
image6a17.jpg
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 Members
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.

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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.


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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.


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